WO2011072145A2 - Système de contrôle sous-marin à double trajet - Google Patents

Système de contrôle sous-marin à double trajet Download PDF

Info

Publication number
WO2011072145A2
WO2011072145A2 PCT/US2010/059726 US2010059726W WO2011072145A2 WO 2011072145 A2 WO2011072145 A2 WO 2011072145A2 US 2010059726 W US2010059726 W US 2010059726W WO 2011072145 A2 WO2011072145 A2 WO 2011072145A2
Authority
WO
WIPO (PCT)
Prior art keywords
subsea
control system
valve
recited
test tree
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2010/059726
Other languages
English (en)
Other versions
WO2011072145A3 (fr
Inventor
Jr. Terrell Eugene Dailey
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Technology Corp
Schlumberger Holdings Ltd
Prad Research and Development Ltd
Original Assignee
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Technology Corp
Schlumberger Holdings Ltd
Prad Research and Development Ltd
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Schlumberger Canada Ltd, Services Petroliers Schlumberger SA, Schlumberger Technology BV, Schlumberger Technology Corp, Schlumberger Holdings Ltd, Prad Research and Development Ltd filed Critical Schlumberger Canada Ltd
Publication of WO2011072145A2 publication Critical patent/WO2011072145A2/fr
Publication of WO2011072145A3 publication Critical patent/WO2011072145A3/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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 OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/02—Valve arrangements for boreholes or wells in well heads
    • E21B34/04—Valve arrangements for boreholes or wells in well heads in underwater well heads
    • E21B34/045—Valve arrangements for boreholes or wells in well heads in underwater well heads adapted to be lowered on a tubular string into position within a blow-out preventer stack, e.g. so-called test trees

Definitions

  • a variety of subsea control systems are employed for use in controlling subsea wells during, for example, emergency shutdowns.
  • various standards or protocols govern operation of the well.
  • gas and oil wells are required to meet specific safety integrity levels.
  • Instrumented systems have been integrated into subsea wells to ensure against unwanted discharge of fluids into the surrounding subsea environment.
  • the present application provides a technique for enabling protection of subsea wells.
  • the technique employs a subsea test tree and associated control system to ensure control over the well in a variety of situations, e.g. a dual path control design.
  • the subsea test tree may be formed with an upper portion releasably coupled to a lower portion.
  • the upper portion may employ at least one upper shut-off valve
  • the lower portion may employ at least one lower shut-off valve to protect against unwanted release of fluids from either above or below the subsea test tree.
  • the subsea test tree also is coupled with the control system in a manner which allows control to be exercised over the at least one upper and at least one lower shut-off valves.
  • Figure 1 is an illustration of one example of a subsea installation and an associated control system, according to an embodiment
  • Figure 2 is an illustration of a portion of one example of a subsea test tree that can be used at the subsea installation, according to an embodiment
  • Figure 3 is a schematic illustration of a portion of the associated control system, according to an embodiment
  • Figure 4 is a schematic illustration of another portion of the associated control system, according to an embodiment
  • Figure 5 is a schematic illustration of another portion of the associated control system, according to an embodiment
  • Figure 6 is a schematic illustration of safety relevant parameters topside and subsea, according to an embodiment
  • Figure 7 is a schematic illustration of one example of the subsea control system incorporating a pressure balanced accumulator, according to an embodiment
  • Figure 8 is a cross-sectional view of one example of the pressure balanced accumulator illustrated in Figure 7, according to an embodiment
  • Figure 9 is a cross-sectional view of an enlarged portion of the pressure balanced accumulator illustrated in Figure 8, according to an embodiment;
  • Figure 10 is a graph illustrating fluid volume expelled from the pressure balanced accumulator at different hydrostatic pressure levels, according to an
  • Figure 11 is a schematic of a dual path control system according to an embodiment.
  • the present application generally relates to a sub sea control system comprising a subsea test tree, such as a subsea test tree located within a riser, and an associated dual path control system.
  • the subsea control system is a subsea wellhead control system comprising a subsea installation with an independently controlled subsea test tree.
  • the subsea test tree comprises an upper portion separable from a lower portion and a plurality of shut-off valves. At least one shut-off valve is located in each of the upper portion and the lower portion.
  • the present technique and components may be used in cooperation with existing components and control systems.
  • the present technique may be employed with the SenTURIANTM Deep Water Control System manufactured by SchlumbergerTM
  • the system may be employed as a safety instrumented system as defined by one or more applicable standards, such as IEC61508.
  • IEC61508 the IEC61508 standard is selected and covers safety-related systems when such systems incorporate electrical, electronic, or programmable electronic (E/E/PE) devices. Such devices may include a variety of devices from electrical relays and switches through programmable logic controllers (PLCs).
  • PLCs programmable logic controllers
  • the standard is designed to cover possible hazards created when failures of the safety functions performed by E/E/PE safety-related systems occur.
  • the international standard IEC61508, although generic, is an example of a standard which is becoming more widely accepted as a basis for the specification, design and operation of programmable electronic systems in the petroleum production industry.
  • SILs safety integrity levels
  • SIL levels are discussed as outlined by the Norwegian Petroleum Directorate for the safety functions carried out by the system, e.g. SIL2.
  • SIL2 ensures that the safe failure fraction is between 90% and 99% assuming a hardware fault tolerance of zero.
  • SIL2 also implies that the probability of failure on demand for dangerous undetected failures is between 0.01 and 0.001, thus resulting in a risk reduction factor of between 100 and 1000.
  • a well system 20 is illustrated.
  • well system 20 is a subsea control system comprising a subsea installation 22 which includes a production control system 24 cooperating with a subsea test tree 26.
  • the subsea installation 22 is positioned at a subsea location 28 generally over a well 30 such as an oil and/or gas production well.
  • a control system 32 is employed to control operation of the production control system 24 and subsea test tree 26.
  • the control system 32 may comprise an integrated system or independent systems for controlling the various components of the production control system and the subsea test tree.
  • production control system 24 may comprise a variety of components depending on the specific application and well environment in which a production operation is to be conducted, specific examples are discussed to facilitate an understanding of the present system and technique.
  • production control system 24 comprises a horizontal tree section 34 having, for example, a production line 36 and an annulus line 38.
  • a blowout preventer 40 e.g. a blowout preventer stack, may be positioned in cooperation with the horizontal tree section 34 to protect against blowouts.
  • These components also comprise an internal passageway 42 to accommodate passage of tubing string components 44 and related components, such as a tubing hanger/running tool 46.
  • the production control system 24 also may comprise a variety of additional components incorporated into or positioned above blowout preventer 40.
  • at least one pipe ram 46 may be mounted in subsea installation 22 at a suitable location. Two pipe rams 46 can be employed.
  • the system also may comprise at least one shear ram 48, such as the two shear rams illustrated. Additionally, one or more, e.g. two, annular rams 50 may be employed in the system.
  • the various production control systems 24 accommodate a riser 52 designed to receive subsea test tree 26.
  • the subsea test tree 26 comprises an upper portion 54 releasably coupled with a lower portion 56 via a connector 58, such as a latch connector.
  • the upper portion 54 and the lower portion 56 each contain at least one shut- off valve which may be selectively actuated to block flow of production fluid through the subsea installation 22.
  • the various components of subsea installation 22 are designed to allow an emergency shutdown.
  • subsea test tree 26 enables provision of a safety system installed within riser 52 during completion operations to facilitate safe, temporary closure of the subsea well 30.
  • the control system 32 provides hydraulic power to the subsea test tree 26 to enable control over the shut-off valves. Control over the subsea test tree 26 may be independent of the safety functions of the production control system 24, such as actuation of blowout preventer 40.
  • shut-off valves in subsea test tree 26 may range in number and design.
  • the upper portion 54 comprises a retainer valve 60, as further illustrated in Figure 2.
  • the lower portion 56 may include a pair of valves in the form of a flapper valve 62 and a ball valve 64. As desired for a given application, other
  • the upper portion 54 may comprise additional components in the form of a space out sub 66, a bleed off valve 68, and a shear sub 70.
  • the lower portion 56 may comprise additional components, such as a ported joint 72 extending down to tubing hanger 46.
  • the shut-off valves may be controlled electrically, hydraulically, or by other suitable techniques.
  • valves 60, 62, 64 are controlled hydraulically via hydraulic lines 74.
  • the position of the valves 60, 62, 64 may be controlled via a combination of opened or closed directional control valves 76 located in, for example, a subsea control module 78.
  • the directional control valve 76 control whether hydraulic pressure is present or vented on its assigned output port in the subsea test tree.
  • the directional control valves 76 within subsea control module 78 may be controlled via solenoid valves or other actuators which may be energized via electrical signals sent from the surface.
  • the overall control system 32 for controlling subsea test tree 26 may have a variety of topside and subsea components which work in cooperation.
  • an operations engineer may issue a command via a human machine interface 80 of a master control station 82, such as a computer-based master control station.
  • the master control station 82 comprises or works in cooperation with one or more programmable logic controllers (PLC).
  • PLC programmable logic controllers
  • Electric current is sent down through an umbilical 84 to the solenoid valves and subsea control module 78 to actuate directional control valves 76.
  • the umbilical 84 also may comprise one or more hydraulic control lines extending down to the subsea control module from a hydraulic power unit 86.
  • the hydraulic lines 74 also are routed to an accumulator 88, such as a subsea accumulator module.
  • a desired directional control valve 76 When a desired directional control valve 76 is opened, hydraulic pressure supplied by hydraulic power unit 86 is passed through its assigned output port to the subsea test tree 26. Conversely, when a directional control valve 76 is closed, any hydraulic pressure present at its output port is vented. Hydraulic power is transferred from the subsea accumulator module 88 to a particular valve 60, 62, 64 located in the subsea test tree 26. The designated valve transitions and fulfills the intended safety instrumented function for a given situation.
  • An emergency shutdown sequence may be achieved through a series of commands sent to one or more of the valves 60, 62 and 64.
  • the emergency shutdown sequence may be designed to bring the overall system to a safe state upon a given command.
  • the emergency shutdown sequence also may control transition of additional valves, e.g. a topside production control valve, to a desired safety state.
  • the directional control valves 76 are designed to return to a natural or default state via, for example, spring actuation. This action automatically brings the well to a fail safe position with the topside riser and the well sealed and isolated. If the topside equipment is unable to bring the well into a safe state, then the operator can institute a block- and-bleed on the hydraulic power unit 86 to cause the subsea test tree to transition into its failsafe configuration. Additionally, visual and/or audible alerts may be used to alert an operator to a variety of fault or potential fault situations.
  • the subsea test tree 26 has four basic functions utilizing retainer valve 60, connector 58, flapper valve 62, and ball valve 64.
  • the retainer valve 60 functions to contain riser fluids in riser 52 after upper portion 54 is disconnected from lower portion 56.
  • the connector 58 e.g. latch mechanism, enables the riser 52 and upper portion 54 to be disconnected from the remaining subsea installation 22.
  • the flapper valve 62 provides a second or
  • supplemental barrier used to isolate and contain the subsea well.
  • the ball valve 64 is used to isolate and contain the subsea well as a first barrier against release of production fluid.
  • the subsea test tree 26 may be used in a variety of operational modes.
  • the subsea test tree 26 may be transitioned to a "normal mode".
  • a standard emergency shutdown sequence may be used in which a ball valve close function is performed to close ball valve 64.
  • the ball valve 64 may be closed by supplying hydraulic fluid at a desired pressure, e.g. 5 kpsi.
  • Another mode is employed as the subsea test tree system is run in hole or pulled out of hole (RIH/POOH mode). In this mode, the valve functions are disabled to prevent a spurious unlatch at connector 58 while the assembly is suspended in riser 52.
  • the system is placed in a "coil tubing" mode when coil tubing is present in riser 52 while a disconnect is to be initiated.
  • the ball valve is actuated under a higher pressure, e.g. 10 kpsi, to enable severing of the tubing via, for example, shear rams 48.
  • the control system 32 also may be designed to operate in a diagnostic mode.
  • the diagnostic mode is useful in determining the integrity of the signal path as well as the basic functionality of the subsea control module, including the solenoid valves and directional control valves.
  • a selected current e.g. a 30mA current
  • the impedance of the system can be inferred. This current is insufficient to trigger a solenoid into actuation, but the current may be used to verify various operational parameters.
  • verifying operational parameters include: verifying delivery of power to the system from an uninterruptible power supply; verifying the solenoid driver power supply is functional; verifying performance of a programmable logic controller; verifying that all connectors are intact; and verifying solenoids have not failed in an open or shorted manner.
  • the diagnostic testing can be performed on command from a SCADA, or as a self-diagnostic function at pre-determined time intervals depending on results of a hazard and operability application.
  • control system 32 utilizes a surface based master control system 82 comprising a programmable logic control system 90 to isolate topside flow output via a production wing valve 92.
  • the wing valve 92 may comprise a master valve, a downhole safety valve, or another wing valve operated by the production control system.
  • the overall system may be designed at a SIL3 level while the subsea test tree employed in the subsea installation 22 is at an SIL2 level.
  • the topside wing valve 92 is operated by a high pressure system through a solenoid actuated valve 94 controlled via programmable logic controller 90 in master control system 82.
  • the valve 94 is considered to be in a safe state when it is in its closed position.
  • the system may be designed to enable manual triggering of the valve. Verification that wing valve 92 has been actuated can be based on select parameters. For example, the verification may be based on detection of actuation current delivered by the master control system; detection of the actuation voltage required to achieve the desired current (implied impedance); and/or operator verification of the position of the wing valve via an appropriate gauge or sensor.
  • programmable logic controller 90 is coupled to an emergency shutdown panel 96. Additionally, the programmable logic controller 90 comprises an input module 98, a logic module 100, and an output module 102. The programmable logic controller 90 may be powered by an uninterruptible power supply 104, and the output module 102 may be independently coupled to a power supply unit 106. The output module 102 controls actuation of solenoid valve 94 which, in turn, controls delivery of hydraulic actuation fluid to wing valve 92. Additional components may be positioned between solenoid valve 94 and wing valve 92 to provide an added level of control and safety. Examples of such components comprise a supplemental valve 108 and an air block 110.
  • a similar control technique may be used to control actuation of retainer valve 60 in upper portion 54, as illustrated in Figure 4.
  • the emergency shutdown sub-function begins at the master control system 82 where the demand is initiated, however the function does not include other initiating factors. The function concludes with the retainer valve 60 closing with respect to riser 52.
  • An appropriate SIL level for this sub-function may be SIL2. Verification that retainer valve 60 has been actuated to a closed position can be based on select parameters.
  • the verification may be based on detection of actuation current delivered by the master control system; detection of the actuation voltage required to achieve the desired current (implied impedance); detection of flow as measured by flow meters on the hydraulic power unit 86; and/or measuring a pressure response with transducers on the subsea accumulator module 88.
  • shut-off valves e.g. valves 62, 64
  • two shut-off valves are utilized for the sake of redundancy in the form of flapper valve 62 and ball valve 64, however one valve is sufficient to leave the subsea well 30 in a safe state.
  • the emergency shutdown sub-function begins at the master control system 82 where the demand is initiated, however the function does not include other initiating factors. The function concludes with the flapper valve 62 and/or ball valve 64 closing with respect to subsea well 30.
  • An appropriate SIL level for this sub-function may be SIL2.
  • Verification that at least one of the flapper valve 62 and ball valve 64 has been actuated to a closed position can be based on select parameters.
  • the verification may be based on detection of actuation current delivered by the master control system; detection of the actuation voltage required to achieve the desired current (implied impedance); detection of flow as measured by flow meters on the hydraulic power unit 86; and/or measuring a pressure response with transducers on the subsea accumulator module 88.
  • the safety integrity levels (SILs) described herein are not necessarily derived from a risk-based approach for determining SIL levels as described in standard IEC61508. Instead, the SIL levels sometimes are based on industry recognized standards for production system safety functions. Based on the minimum SIL requirements for each function as applies to the existing layers of protection, the minimum SIL level for the various safety integrity functions, e.g. the sub-functions outlined in Figures 3-5, may be selected as SIL2. [0039] Additionally, the subsea test tree 26 and its corresponding shut-off valves
  • the overall control system 32 may comprise completely independent control systems for the subsea test tree 26 and the production control system 24.
  • the subsea test tree 26 may be installed within the production control system 24, e.g. inside a Christmas tree, during operation inside the blowout preventer stack 40. In the event that the blowout preventer 40 is required to close, the subsea test tree 26 is sealed and disconnected from the string (separated at connector 58). This allows the upper portion 54 of the subsea test tree 26 to be retracted so the blowout preventer rams can be closed without interference.
  • the shear rams 48 may be operated to sever the tool and safely close the well.
  • the blowout preventer control system has no influence on the safety functions of the subsea test tree system.
  • One example of a closing pattern comprises closing the upper retainer valve 60, followed by closure of the lower ball valve 64 and subsequent closure of the flapper valve 62. Once the upper production string is sealed via retainer valve 60 and access to the wellbore is sealed via ball valve 64 and flapper valve 62, the subsea test tree is disconnected and separated at connector 58.
  • Specific safety relevant parameters may be selected according to the system design, environment, and applicable requirements in a given geographical location. However, one example of a typical approach is illustrated in Figure 6 as having a safe failure fraction exceeding 90% on the topside for a Type B safety system
  • the accumulator module 88 may be incorporated into the overall system in a variety of configurations and at a variety of locations. In one example, accumulator module 88 is a pressure balanced accumulator to provide hydraulic power to the system in case of emergency closure and disconnect and/or loss of hydraulic power from the surface.
  • Accumulators are devices that provide a reserve of hydraulic fluid under pressure and are used in conventional hydraulically-driven systems where hydraulic fluid under pressure operates a piece of equipment or a device.
  • the hydraulic fluid is pressurized by a pump that maintains the high pressure required.
  • accumulators may be used to provide a reserve source of pressurized hydraulic fluid for this type of equipment.
  • accumulators can be used to provide a reserve source of pressurized hydraulic fluid to enable the operation of a piece of equipment or device.
  • Accumulators may include a compressible fluid, e.g., gas, nitrogen, helium, air, etc., on one side of a separating mechanism, and a non-compressible fluid (hydraulic fluid) on the other side.
  • a compressible fluid e.g., gas, nitrogen, helium, air, etc.
  • hydroaulic fluid non-compressible fluid
  • accumulator module 88 is a pressure balanced accumulator system.
  • the accumulator system 88 is connected with the one or more hydraulic lines 74 routed between hydraulic power unit 86 and subsea test tree 26.
  • Hydraulic power unit 86 may comprise one or more suitable pumps 110 for pumping hydraulic fluid.
  • the hydraulic power unit 86 is located above a sea surface 111 and provides control fluid for the operation of, for example, blowout preventer 40 and the valves 60, 62, 64 of subsea test tree 26.
  • the pressurized hydraulic fluid from hydraulic power unit 86 also is used to charge the pressure balanced accumulator system 88.
  • the hydrostatic pressure P H s supplied by pump 110 is approximately 7500 psi, although other pressure levels may be used.
  • the pressure balanced accumulator 88 comprises a housing 112, which is a generally tubular- shaped member having two ends 114 and 116.
  • An accumulator mechanism 118 is located within the housing 112 proximate the first end 114.
  • the accumulator mechanism 118 comprises a first chamber 120 (see Figure 9) for receiving a pressurized gas at a first pressure.
  • the pressurized gas may, for example, be injected into chamber 120 through gas precharge port 122.
  • the gas in the first chamber 120 is helium, and it is pressurized to
  • accumulator mechanism 118 also comprises a second chamber 124 for receiving a first pressurized fluid at a second pressure.
  • the pressure of the fluid in chamber 124 is sometimes referred to as the "gauge pressure.”
  • liquid may be injected into chamber 124 via a seal stab port 126.
  • the liquid injected into chamber 124 may be in the form of a water glycol mixture according to one embodiment of the present invention.
  • the mixture may be injected into chamber 124 at a pressure of approximately 5000 psi, although other pressures may be utilized in other applications.
  • Chambers 120 and 124 are hermetically sealed from one another at regions 128 and 130.
  • the pressure balanced accumulator system 88 may further comprise a third chamber 132 which abuts accumulator mechanism 118 in housing 112.
  • Third chamber 132 contains a fluid, which may be injected into chamber 132 via fluid fill port 134.
  • the fluid injected into third chamber 132 is silicon oil, which is selected for use because of its lubricity and because it will not adversely affect seals 136 deployed to seal along one end of chamber 132. Initially, the silicon fluid is not injected into third chamber 132 under pressure. In operation, however, the pressure of the fluid in chamber 132 tracks the pressure of the fluid in second chamber 124, as described below.
  • Pressure balanced accumulator 88 also comprises a piston 138 which is located within the housing proximate the second end 116 of housing 112.
  • the piston 138 has a first end 140 and a second end 142 which have first and second cross- sectional areas, respectively.
  • the cross-sectional areas of piston ends 140 and 142 are circular in shape.
  • Piston 138 is movable between a first position, as shown in Figure 8, and a second position in which piston end 140 is stopped by a shoulder 144.
  • Housing end 116 also may comprise an ambient pressure port 146.
  • ambient pressure port 146 permits the ambient subsea pressure to impinge on end 140 of piston 138.
  • pressure balanced accumulator system 88 also comprises an atmospheric chamber 148 which includes an annular recess 150 formed between piston 138 and the wall of housing 112; an axial cavity 152 which is formed by hollowing out a portion of piston 138; and a passage 154 connecting annular recess 150 and axial cavity 152.
  • This atmospheric chamber allows differential pressure to exist across piston 138 which enables the piston to start to move when an equilibrium pressure exists across piston 138 as discussed below.
  • the pressure in the atmospheric chamber is 14.7 psi
  • the volume of annular recess 150 is approximately 10 in. sup.3
  • the volume of axial cavity 152 is approximately 200 in. sup.3.
  • accumulator module 88 may be located in a subsea environment to control the operation of an in-riser or open water intervention system, such as subsea test tree 26 and associated valves 60, 62, 64.
  • the first and second chambers 120 and 124 in accumulator mechanism 118 of pressure balanced accumulator system 88 are precharged prior to placement of pressure balanced accumulator system 88 in the subsea environment.
  • Pump 110 which is located above the sea surface 111, provides the control fluid for the operation of blowout preventer 40 and shut-off valves 60, 62, 64.
  • the pump 110 also provides a charging input to second chamber 124 of accumulator mechanism 118 in pressure balanced accumulator system 88.
  • piston ends 140 and 142 are circular in cross-section and have cross-sectional areas established by diameters of 3.375 inches and 2.688 inches, respectively, although the sizes are for purposes of explanation only.
  • the equilibrium pressure, which the iston 138 starts to move is:
  • P C is the pressure to which the second chamber of accumulator mechanism 118 is charged, e.g., 5000 psi
  • S is a hydraulic safety factor which is an allowance given to prevent instability in maximum hydrostatic conditions.
  • a graph is presented with a graph line 156 provided to illustrate the fluid volume of fluid expelled from the accumulator mechanism 118 at a hydrostatic pressure of 7500 psi and with Di and D 2 being 3.375 inches and 2.688 inches, respectively.
  • Graph lines 158, 160 and 162 illustrate fluid volume expelled at hydrostatic pressures of 6500, 5500 and 4500 psi, respectively.
  • the overall subsea control system 20 may be designed for use in a variety of well applications and well environments. Accordingly, the number, type and configuration of components and systems within the overall system may be adjusted to accommodate different applications.
  • the subsea test tree may include different numbers and types of shut-off valves as well as a variety of connectors, e.g. latch mechanisms, for releasably connecting the upper and lower parts of the subsea test tree.
  • the production control system also may comprise various types and configurations of subsea installation components.
  • the control system 32 may rely on various topside and subsea components which enable independent control over the subsea test tree and the blowout preventer.
  • control system utilizes surface components which are computer-based to enable easy input of commands and monitoring of subsea functions.
  • programmable logic controllers also may be employed and used to carry out various sub-functions implemented in emergency shutdown procedures.
  • Various adaptations may be made to accommodate specific environments, types of well equipment, applicable standards, and other parameters which affect a given subsea well application.
  • the subsea control systems described herein can include a dual path system.
  • Figure 11a shows a single path control system 200.
  • a programmable logic controller (PLC) 201 is connected with a single control path 204 through the umbilical 202.
  • the single control path 204 connects with a valve coil 203 that controls actuation of a valve.
  • the control path can be an electrical conductor.
  • Figure 1 lb shows an embodiment of a dual path system 205.
  • the dual path system 205 has a primary PLC 201a and a slave PLC 201b.
  • Primary PLC 201a is connected with control path 204a and slave PLC 201b is connected with secondary control path 204b.
  • the control paths 204a and 204b extend through the umbilical 202.
  • the first control path 204a connects with a primary valve coil 203a.
  • the secondary control path 204b connects with a secondary valve coil 203b.
  • the slave PLC 201a will duplicate the commands sent by the master PLC 201a, but on the secondary control path 204b. This keeps operations transparent to the field technician.
  • the commands are transmitted by the master PLC 201a and slave PLC 201b down the primary control path 204a and secondary control path 204b, respectively.
  • dual coils can be incorporated on all of the solenoid valves on the subsea control module (SCM).
  • the valves are capable of being actuated by either coil.
  • the primary valve coil 203a for each valve will be coupled to the primary control path 204a and the secondary valve coil 203b will be coupled to the secondary control path 204b.
  • the solenoid valve will still operate when commanded by means of the secondary control path 204b and secondary coil 203b.
  • both coils will fire and the valve will operate.
  • the splitting of the control commands onto the two control paths can be accomplished in the SCM, wherein a programmable logic controller (PLC) is slaved to the primary, master programmable logic controller.
  • PLC programmable logic controller
  • the programming of the master PLC 201a and slave PLC 201b is such that the slave PLC 201b will interpret what command the master intends to or sends and will send the same command (i.e. duplicate) on the secondary control path 204b.
  • the slave PLC 201b can report voltage and current values back to the master PLC 201a for logging and display on the HMI via a communications link.
  • the slave PLC 201b will send the intended command even if this link is lost. This configuration increases the likelihood of functions occurring when they are commanded, i.e. in the event of any component failure.
  • signals can be demultiplexed at the SCM via a subsea electronics module (SEM).
  • SEM subsea electronics module
  • a feature of various embodiments of the SenTURIAN SEM is that they may contain no active electronics. According to various embodiments, only passive components such as diodes are contained in the SEM. In the dual path SCM, there can be two SEM's.

Landscapes

  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Fluid-Pressure Circuits (AREA)
  • Multiple-Way Valves (AREA)

Abstract

La présente invention a trait à une technique qui permet de protéger les puits sous-marins. La technique emploie un arbre d'essai sous-marin et un système de contrôle associé afin de garantir le contrôle du puits dans un grand nombre de situations. L'arbre d'essai sous-marin peut être constitué d'une partie supérieure couplée de façon amovible à une partie inférieure. La partie supérieure emploie au moins un robinet de sectionnement supérieur et la partie inférieure emploie au moins un robinet de sectionnement inférieur afin d'éviter toute libération non souhaitée de fluides au-dessus ou en dessous de l'arbre d'essai sous-marin. L'arbre d'essai sous-marin est également couplé au système de contrôle de manière à ce que le contrôle soit exercé sur le ou les robinets de sectionnement supérieurs et sur le ou les robinets de sectionnement inférieurs.
PCT/US2010/059726 2009-12-09 2010-12-09 Système de contrôle sous-marin à double trajet Ceased WO2011072145A2 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US26785209P 2009-12-09 2009-12-09
US61/267,852 2009-12-09

Publications (2)

Publication Number Publication Date
WO2011072145A2 true WO2011072145A2 (fr) 2011-06-16
WO2011072145A3 WO2011072145A3 (fr) 2011-08-18

Family

ID=44082803

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2010/059726 Ceased WO2011072145A2 (fr) 2009-12-09 2010-12-09 Système de contrôle sous-marin à double trajet

Country Status (2)

Country Link
US (1) US8708054B2 (fr)
WO (1) WO2011072145A2 (fr)

Families Citing this family (28)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2010129478A1 (fr) * 2009-05-04 2010-11-11 Schlumberger Canada Limited Système de commande sous-marin
US8978766B2 (en) * 2011-09-13 2015-03-17 Schlumberger Technology Corporation Temperature compensated accumulator
EP2620585B1 (fr) * 2012-01-26 2017-03-15 GE Oil & Gas UK Limited Communication dans un système de contrôle de puits sous-marin
GB201212591D0 (en) * 2012-07-16 2012-08-29 Aker Subsea Ltd Subsea safety system
EP2738348B1 (fr) * 2012-11-29 2017-09-20 GE Oil & Gas UK Limited Arrêt d'un puits de production de fluide sous-marin
US9284808B2 (en) * 2012-12-05 2016-03-15 David Wright Chemical deepwater stimulation systems and methods
WO2014194158A1 (fr) * 2013-05-30 2014-12-04 Schlumberger Canada Limited Structure a dispositif d'amenée
EP2853682A1 (fr) * 2013-09-25 2015-04-01 Siemens Aktiengesellschaft Système d'enceinte sous-marine destiné à l'élimination de la chaleur générée
US9458689B2 (en) 2014-02-21 2016-10-04 Onesubsea Ip Uk Limited System for controlling in-riser functions from out-of-riser control system
US10876369B2 (en) 2014-09-30 2020-12-29 Hydril USA Distribution LLC High pressure blowout preventer system
US10048673B2 (en) * 2014-10-17 2018-08-14 Hydril Usa Distribution, Llc High pressure blowout preventer system
BR112017004973A2 (pt) 2014-09-30 2018-03-06 Hydril Usa Distrib Llc sistema de controle para um sistema de segurança contra estouro submarino, sistema de controle redundante e método para controlar um sistema de segurança
US10196871B2 (en) 2014-09-30 2019-02-05 Hydril USA Distribution LLC Sil rated system for blowout preventer control
US9989975B2 (en) 2014-11-11 2018-06-05 Hydril Usa Distribution, Llc Flow isolation for blowout preventer hydraulic control systems
US9759018B2 (en) 2014-12-12 2017-09-12 Hydril USA Distribution LLC System and method of alignment for hydraulic coupling
US9528340B2 (en) 2014-12-17 2016-12-27 Hydrill USA Distribution LLC Solenoid valve housings for blowout preventer
US10202839B2 (en) 2014-12-17 2019-02-12 Hydril USA Distribution LLC Power and communications hub for interface between control pod, auxiliary subsea systems, and surface controls
US9828824B2 (en) * 2015-05-01 2017-11-28 Hydril Usa Distribution, Llc Hydraulic re-configurable and subsea repairable control system for deepwater blow-out preventers
WO2017007491A1 (fr) * 2015-07-09 2017-01-12 Halliburton Energy Services, Inc. Système collecteur modulaire pour un système de commande électrohydraulique
DK3400368T3 (da) 2016-03-23 2021-09-13 Halliburton Energy Services Inc Elektrisk underjordisk sikkerhedsventil (ESSSV)
US9631448B1 (en) * 2016-08-03 2017-04-25 Schlumberger Technology Corporation Distibuted control system for well application
CN110630221B (zh) * 2019-10-10 2024-07-02 西南石油大学 一种深水测试管柱安全装置复合电液井下控制系统
CN111535766B (zh) * 2020-05-13 2022-04-26 中石化石油工程技术服务有限公司 钻井液循环系统
CN111535772B (zh) * 2020-05-13 2021-12-07 中石化石油工程技术服务有限公司 钻井井口防溢控制系统
CN112302573A (zh) * 2020-12-01 2021-02-02 中国石油天然气集团有限公司 一种适用于引流测试作业的投球器和投球方法
US20220269233A1 (en) * 2021-02-22 2022-08-25 University Of Wyoming Modular reaction control system for live monitoring of long-term and/or multi-channel reactions
CN115075764B (zh) * 2022-06-29 2023-06-13 西南石油大学 一种电驱大通径水下测试树
CN116025311B (zh) * 2022-11-16 2024-05-28 西南石油大学 一种水下全电控坐落管柱系统及方法

Family Cites Families (18)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4174000A (en) * 1977-02-26 1979-11-13 Fmc Corporation Method and apparatus for interfacing a plurality of control systems for a subsea well
US4636934A (en) * 1984-05-21 1987-01-13 Otis Engineering Corporation Well valve control system
US4880060A (en) * 1988-08-31 1989-11-14 Halliburton Company Valve control system
US6125938A (en) * 1997-08-08 2000-10-03 Halliburton Energy Services, Inc. Control module system for subterranean well
DE19836389C1 (de) * 1998-08-12 2000-04-13 Deilmamm Haniel Maschinen Und Bohrvorrichtung mit Doppelschlagsystem
US6343654B1 (en) * 1998-12-02 2002-02-05 Abb Vetco Gray, Inc. Electric power pack for subsea wellhead hydraulic tools
US6202753B1 (en) 1998-12-21 2001-03-20 Benton F. Baugh Subsea accumulator and method of operation of same
NO312376B1 (no) * 2000-05-16 2002-04-29 Kongsberg Offshore As Fremgangsmåte og anordning for styring av ventiler av en undervannsinstallasjon
US20050155658A1 (en) 2004-01-20 2005-07-21 White Andrew J. Hermetically sealed pressure balanced accumulator
US20050217845A1 (en) * 2004-03-30 2005-10-06 Mcguire Lindell V Tubing hanger running tool and subsea test tree control system
US7768908B2 (en) * 2004-04-15 2010-08-03 Cameron International Corporation Systems and methods of providing redundant communication to an electronic device
US7539548B2 (en) * 2005-02-24 2009-05-26 Sara Services & Engineers (Pvt) Ltd. Smart-control PLC based touch screen driven remote control panel for BOP control unit
US7628207B2 (en) * 2006-04-18 2009-12-08 Schlumberger Technology Corporation Accumulator for subsea equipment
US20080202761A1 (en) * 2006-09-20 2008-08-28 Ross John Trewhella Method of functioning and / or monitoring temporarily installed equipment through a Tubing Hanger.
US20090038804A1 (en) * 2007-08-09 2009-02-12 Going Iii Walter S Subsurface Safety Valve for Electric Subsea Tree
JP4850970B2 (ja) * 2007-09-21 2012-01-11 トランスオーシャン セドコ フォレックス ベンチャーズ リミテッド 付加的な噴出防止装置の制御リダンダンシーを提供するシステムおよび方法
WO2009114445A1 (fr) * 2008-03-14 2009-09-17 Schlumberger Canada Limited Production de puits sous-marin
NO345599B1 (no) * 2008-04-18 2021-05-03 Schlumberger Technology Bv Undersgrunns testventiltre-system og fremgangsmåte for å operere et undersjøisk testventiltre

Also Published As

Publication number Publication date
WO2011072145A3 (fr) 2011-08-18
US8708054B2 (en) 2014-04-29
US20110137471A1 (en) 2011-06-09

Similar Documents

Publication Publication Date Title
US8708054B2 (en) Dual path subsea control system
US8839868B2 (en) Subsea control system with interchangeable mandrel
US20110005770A1 (en) Subsea control system
EP2466060B1 (fr) Système de test fonctionnel de circuit et procédé associé
US8347967B2 (en) Subsea tree safety control system
US9243478B2 (en) Piping system having an insulated annulus
EP3077612B1 (fr) Énergie propulsive pour faire fonctionner un équipement sous-marin
EP3014050B1 (fr) Chaîne d'accrochage sous-marine à fermeture d'urgence automatique et séparation
US20140360731A1 (en) Blowout Preventer Shut-In Assembly of Last Resort
EP3017139B2 (fr) Système pour intervention sous-marine
US10246970B2 (en) Landing string
WO2009056840A2 (fr) Ensemble sous-marin
WO2008074995A1 (fr) Système de stockage d'énergie électrique et de fourniture d'un fluide sous pression
GB2338971A (en) Workover tool control system
US20180195362A1 (en) Improved Pressure Barrier System
CA3159120A1 (fr) Systeme de controle pour un dispositif de commande de puits

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 10836698

Country of ref document: EP

Kind code of ref document: A1

121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 10836698

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 10836698

Country of ref document: EP

Kind code of ref document: A2