16D tables added 030804 fm Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment API SPECIFICATION 16D SECOND EDITION, JULY 2004 EFFECTIVE DA[.]
General
The specifications outline design standards for systems controlling blowout preventers (BOPs) and associated valves during drilling operations, excluding material selection and manufacturing details Diverters, while not classified as well control devices, are integrated into BOP control systems Control systems typically utilize pressurized hydraulic fluid to operate BOP components, with each operation termed a control function The specifications categorize control systems into several types: surface-mounted BOP stacks, which use simple hydraulic control systems; subsea BOP stacks, requiring specialized remote control equipment; discrete hydraulic systems utilizing umbilical hose bundles; electro-hydraulic/multiplex systems for deepwater operations with electric/optical signal transmission; diverter equipment controls; auxiliary equipment controls for floating drilling operations; emergency disconnect sequenced systems (EDS) for automatic LMRP disconnection; backup systems for inaccessible subsea controls; and special features for deepwater/harsh environments.
ABS Class Society Rules: CDS (Certification of Drilling Systems)
RP 14F Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities
RP 500 Recommended Practice for Classification of Locations for Electrical Installations
Y32.10 Graphic Symbols for Fluid Power Diagrams
ASME Boiler and Pressure Vessel Code
IEC 529 Degrees of Protection by Enclosures
ISO 1219 Fluid Power—systems and components—graphic symbols and circuit diagrams
API RP 17H ROV interfaces on subsea production systems
ISO 14224 Collection and exchange of reliability and maintenance data for equipment
RP0176 Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production
British Design Code BS-5500 Specification for Unfired Fusion Welded Pressure Vessels
DOT Spec 3AA2015 Welding, Cutting and Brazing
German Design Code AD-Merkblaetter
3 Terms, Definitions, and Abbreviated Terms
Graphic symbols for fluid power diagrams shall be in accordance with ANSI Y32.10 and/or ISO Standard 1219, latest editions. For the purposes of this specification, the following definitions apply:
3.1 accumulator: A pressure vessel charged with non-reactive or inert gas used to store hydraulic fluid under pressure for operation of blowout preventers.
3.2 accumulator bank: An assemblage of multiple accumulators sharing a common manifold.
3.3 accumulator precharge: An initial inert gas charge in an accumulator, which is further compressed when the hydraulic fluid is pumped into the accumulator, thereby storing potential energy.
3.4 acoustic control system: A subsea control system that uses coded acoustic signals for communications and is normally used as an emergency backup having control of a few selected critical functions.
3.5 air pump/air-powered pump: Air driven hydraulic piston pump.
The 3.6 annular BOP is a hydraulically operated device featuring a toroidal-shaped, steel-reinforced elastomer packing element It is designed to effectively close and seal around various sizes of drill pipes, ensuring complete closure of the wellbore.
1American National Standards Institute, 25 West 43rd Street, 4th Floor, New York, New York 10036 www.ansi.org
2ASME International, 3 Park Avenue, New York, New York 100160-5990 www.asme.org
3American Welding Society, 550 N.W LeJeune Road, Miami, Florida 33135 www.aws.org
4International Organization for Standardization, 1, rue de Varemb´e, Case postale 56, CH-211, Geneva 20, Switzerland www.iso.org
5NACE International, 1440 South Creek Drive, P.O Box 218340, Houston, Texas 77218-8340 www.nace.org
3.7 arm: To enable the operation of a critical function or functions.
3.8 backup: An element or system that is intended to be used only in the event that the primary element or system is non-func- tional.
3.9 blind ram BOP: A BOP having rams which seal against each other to close the wellbore in the absence of any pipe.
3.10 block position: The center position of a three-position control valve.
3.11 blowout: An uncontrolled flow of pressurized wellbore fluids.
3.12 BOP (blowout preventer): A device that allows the well to be sealed to confine the well fluids in the wellbore.
3.13 BOP closing ratio (ram BOP): A dimensionless factor equal to the area of the piston operator divided by area of the ram shaft.
The 3.14 BOP control system comprises essential components such as pumps, valves, accumulators, fluid storage and mixing equipment, manifolds, piping, hoses, and control panels, all of which are crucial for the hydraulic operation of BOP equipment.
3.15 BOP stack: The assembly of well control equipment including BOPs, spools, valves, and nipples connected to the top of the casing head.
3.16 BOP stack maximum rated wellbore pressure: The pressure containment rating of the ram BOPs in a stack.
In cases where the rams have varying pressure ratings, the maximum wellbore pressure of the BOP stack is determined by the lowest rated ram BOP pressure For BOP stacks without any ram BOP, the maximum rated wellbore pressure is based on the lowest rated BOP pressure.
3.17 central control unit (CCU): The central control point for control and monitoring system functions and communica- tions.
3.18 check valve: A valve that allows flow through it in one direction only.
3.19 choke line: A high-pressure line connected below a BOP to transmit well fluid flow to the choke manifold during well control operations.
3.20 choke and kill valves: BOP stack-mounted valves that are connected below selected BOPs to allow access to the well- bore to either choke or kill the well.
3.21 closing unit (closing system): See BOP control system.
3.22 commodity item: A manufactured product purchased by the control system manufacturer for use in the construction of control systems for drilling well control equipment.
3.23 control fluid: Hydraulic oil, water based fluid, or gas which, under pressure, pilots the operation of control valves or directly operates functions
3.24 control hose bundle: A group of pilot and/or supply and/or control hoses assembled into a bundle covered with an outer protective sheath.
3.25 control line: A flexible hose or rigid line that transmits control fluid.
3.26 control manifold: The assemblage of valves, regulators, gauges and piping used to regulate pressures and control the flow of hydraulic power fluid to operate system functions.
A control panel is an enclosure that features a variety of switches, push buttons, lights, valves, and pressure gauges or meters for monitoring and controlling functions There are several types of control panels, including diverter panels, rig floor panels, master panels, and mini or auxiliary remote panels These panels operate remotely from the main hydraulic manifold and can be powered by pneumatic, electric, or hydraulic systems.
1 Diverter Panel—A panel that is dedicated to the diverter and flowline system functions
2 Rig Floor Panel (Driller’s Panel)—The BOP control panel mounted near the driller’s position on the rig floor
The Master Panel, whether hydraulic or electric, is strategically located near the primary power fluid supply This panel allows for the operation of all control functions, featuring essential components such as regulators, gauges, meters, and both audible and visible alarms.
4 Mini or Auxiliary Remote Panel (Toolpusher’s Panel)—A full or limited function panel mounted in a remote location for use as an emergency backup
3.28 control pod: The assemblage of valves and pressure regulators which respond to control signals to direct hydraulic power fluid through assigned porting to operate functions.
The 3.29 control valve is a crucial component of the surface control system, positioned on the hydraulic manifold It effectively directs hydraulic power fluid to specific functions, such as closing the annular blowout preventer (BOP), while simultaneously venting the opposite function, which is the opening of the annular BOP.
3.30 control valve (subsea control system): A pilot operated valve in the subsea control pod that directs power fluid to operate a function.
3.31 dedicated: An element or system that is exclusively used for a specific purpose.
3.32 disarm: To disable the operation of a critical function or functions.
1 Unlatch and separation of the LMRP connector from its mandrel.
2 Unlatch and separation of the BOP stack connector from the wellhead.
3.34 discrete hydraulic control system: A system utilizing pilot hoses to transmit hydraulic pressure signals to activate pilot-operated valves assigned to functions.
3.35 diverter: A device attached to the wellhead or marine riser to close the vertical flow path and direct well flow (typically shallow gas) into a vent line away from the rig.
Drift-off refers to the unintended lateral movement of a dynamically positioned vessel away from its designated location near the wellhead This phenomenon typically occurs due to a loss of station-keeping control or propulsion.
3.37 drive-off: An unintended lateral move of a dynamically positioned vessel off its location driven by the vessel’s main pro- pulsion or station keeping thrusters.
3.39 dynamic positioning (automatic station keeping): A computerized means of maintaining a vessel on location by selectively driving thrusters.
3.40 electric pump: An electrically driven hydraulic pump, usually a three-plunger (triplex) pump.
The electro-hydraulic (EH) control system employs electrical conductor wires within an armored subsea umbilical cable to relay command signals These signals activate solenoid-operated valves, which subsequently control pilot-operated valves designated for specific functions.
Note: One pair of wires is dedicated to each function.
3.42 factory acceptance testing: Testing by a manufacturer of a particular product to validate its conformance to perfor- mance specifications and ratings.
3.43 function: Operation of a BOP, choke or kill valve or other component, in one direction (example, closing the blind rams is a function, opening the blind rams is a separate function).
3.44 hose bundle: See control hose bundle.
3.45 hydraulic conduit: An auxiliary line on a marine drilling riser used for transmission of control fluid between the surface and the subsea BOP stack.
3.46 hydraulic connector: A mechanical connector that is activated hydraulically and connects the BOP stack to the well- head or the LMRP to the BOP stack.
3.47 hydrophone: An underwater listening device that converts acoustic energy to electric signals or converts electric signals to acoustic energy for acoustic transmission.
3.48 interflow: The control fluid lost (vented) during the travel of the piston in a control valve during the interval when the control valve’s inlet and vent points are temporarily interconnected.
3.49 jumper: A segment of hose or cable used to make a connection such as a hose reel junction box to the control manifold.
3.50 junction box (J-box) (electrical): An enclosure used to house the termination points of electrical cables and compo- nents that may also contain electrical components required for system operation
The 3.51 junction box (J-box), available in hydraulic or pneumatic options, features a bolt-on plate equipped with multiple stab-type terminal fittings This design facilitates the quick connection of a multi-hose bundle to various systems, including pods, hose reels, or manifolds.
The 3.52 kill line is a crucial high-pressure line that connects the mud pumps to a point below the Blowout Preventer (BOP) This line enables the pumping of fluid into the well or annulus while the BOP remains closed, playing a vital role in well control operations.
The 3.53 LMRP (Lower Marine Riser Package) is the upper part of a two-section subsea Blowout Preventer (BOP) stack It includes essential components such as the hydraulic connector, annular BOP(s), flex/ball joint, riser adapter, flexible choke and kill lines, and subsea control pods.
Note: This interfaces with the lower subsea BOP stack
3.54 limit switch: A hydraulic, pneumatic or electrical switch that indicates the motion or position of a device.
3.55 manifold: An assemblage of pipe, valves, and fittings by which fluid from one or more sources is selectively directed to various systems or components.
3.56 mixing system: A system that mixes a measured amount of water soluble lubricant and, optionally, glycol to feed water and delivers it to a storage tank or reservoir.
The 3.57 multiplex (MUX) control system employs electrical or optical conductors within an armored subsea umbilical cable, allowing multiple distinct functions to be independently controlled through dedicated serialized coded commands on each conductor Additionally, solenoid-operated valves are used to activate pilot-operated valves that are designated for specific functions.
3.58 non-retrievable control pod: A pod that is fixed in place on the LMRP and not retrievable independently.
3.59 paging: A computer display method of conveying or mapping between displays or screens to allow increased informa- tion or control utilizing multiple screens, but not displayed simultaneously.
3.60 pilot fluid: Control fluid that is dedicated to the pilot supply system.
3.61 pilot line: A line that transmits pilot fluid to operate a control valve.
3.62 pipe ram BOP: A hydraulically operated assembly typically having two opposed ram assemblies that move inward to close on pipe in the wellbore and seal the annulus.
3.63 pipe rams: Rams whose ends are contoured to seal around pipe to close the annular space.
A pop-up display or control dialog box is a feature that appears on a computer screen, providing enhanced access to control items It serves as an auxiliary display for data, messages, or additional operational requests, triggered either by commands from an operator or system alarm notifications.
3.66 potable water: A water supply that is acceptably pure for human consumption.
Note: On an offshore rig, it is usually produced by watermakers and used as supply water for mixing control fluid for a subsea control system
3.67 power fluid: Pressurized fluid dedicated to the direct operation of functions.
The 3.70 pressure biased control system is a discrete hydraulic control mechanism designed to maintain a higher pressure level on pilot lines, which is below the actuation pressure of the control valve This innovative approach significantly reduces the hydraulic signal transmission time, enhancing overall system efficiency.
General
Well control systems and associated auxiliary equipment, as outlined in Section 1, must be designed and supplied by control system manufacturers to meet or exceed specified standards for oil well drilling rigs Additionally, the materials chosen for the design must comply with or surpass these specifications.
Design Review
Before producing equipment or releasing it from inventory to meet sales orders, the manufacturer's engineering authority must ensure that the design complies with all specified requirements The design review will focus on key considerations to guarantee adherence to these standards.
The manufacturer is responsible for specifying the sizing and capacity requirements, the system's rated working pressure, and the temperature ratings necessary for the control system to function effectively within expected ambient conditions Additionally, the manufacturer must classify the environmental temperature ranges as outlined in Table 1 and determine the appropriate location for the equipment.
Offshore well control equipment encompasses both surface and subsea systems To ensure the effective design of the control system, purchasers should refer to Annexes A and B, which serve as checklists detailing the specifications of the Blowout Preventer (BOP) stack and other essential well control equipment.
Design data documentation shall be retained by the manufacturer for each system design type for a minimum of 10 years after delivery of the last unit of the subject design.
The design data documentation must be well-structured and easy to understand, featuring a comprehensive Table of Contents Key components include a Title Page, Foreword, Typical Sizing/Capacity Calculations, System Rated Working Pressure, temperature ratings and environmental classifications for subsystems, drawings and calculations to ensure compliance with specifications, a Utilities Consumption List, a list of applicable standards and specifications, and designations for equipment locations.
The accumulator must deliver adequate hydraulic fluid volume and pressure to operate well control equipment effectively while ensuring enough residual pressure for sealing capability Sizing calculation methods serve as conservative guidelines and should not be relied upon for field performance The minimum required volume design factors, F_v and F_p, differ based on the chosen method Additionally, control system valve interflow is included in the volume design factors and does not need separate consideration.
The Functional Volume Requirements (FVR) outlined in sections 5.1.3, 5.1.4, 5.1.5, 5.2.3, 5.2.4, 5.5.3, and 5.8 can be met using Bottle Volume (BV) from surface or subsea stack-mounted accumulators, based on the calculation method from Table 2 While stack-mounted accumulators can enhance the main hydraulic supply for subsea BOP stacks, their use is not mandatory.
Table 1—Ambient Temperature Classification Chart
Classification High Low High Low
FVR = BV * minimum of (VE v and VE p ) for surface or stack-mounted bottles
The formula for FVR is defined as the minimum of two expressions: the first being the product of the surface bottle volume (BV surf) and the surface volume efficiency (VE v,surf) added to the product of the stack-mounted bottle volume (BV sm) and the stack-mounted volume efficiency (VE v,sm), and the second being the product of the surface bottle volume (BV surf) and the surface pressure efficiency (VE p,surf) added to the product of the stack-mounted bottle volume (BV sm) and the stack-mounted pressure efficiency (VE p,sm) This applies to systems that utilize both surface and stack-mounted bottles.
FVR = Functional Volume Required from 5.1.3, 5.1.4, 5.2.3, 5.2.4, and 5.5.3,
VE = Volumetric Efficiency, deliverable fluid volume / total gas volume of a bottle, based on design conditions and calcu- lation method (A, B, or C) See 4.2.3.1.1 for VE calculation procedure,
VE v = VE for volume limited case,
VE p = VE for pressure limited case.
Accumulator sizing calculations involve four key conditions: precharged (Condition 0), charged (Condition 1), discharged to the minimum required operating pressure (Condition 2), and totally discharged (Condition 3).
Condition 0 refers to a precharged state where accumulator bottles are filled solely with precharge gas at their initial pressure and ambient temperature It is essential to specify the precharge pressure alongside the temperature, ensuring it does not surpass the accumulator's working pressure Additionally, any precharge pressure below the working pressure can be utilized, provided it meets the necessary functional requirements for pressure, volume, and minimum design factors.
When addressing pressure fluctuations caused by temperature changes, it is crucial to ensure that the precharge pressure does not surpass the working pressure at higher ambient temperatures For instance, if the precharge pressure is set at 100°F, a corresponding chart or table should be available to indicate the appropriate precharge levels at lower temperatures Additionally, for ideal gas behavior, the precharge pressure must be adjusted according to the temperature of the charged condition.
P c /T c = P 3 / T 0 where T 1 = T 0 (Temperatures and pressures in absolute units.) V 0 is the precharge volume of the accumulator in the normal dis- charged/precharge state
In hydraulic systems, the charged condition is defined by the pump stop pressure, except for rapid discharge systems, which may utilize the pump start pressure if the accumulator pressure varies with it For instance, a 3000 psig accumulator system may have a charged pressure of 2700 psig If a rapid discharge accumulator is isolated by a check valve, it maintains the pump stop pressure, applicable in scenarios like dedicated shear circuits or acoustic accumulators Additionally, pressure compensation for water depth is determined by the hydrostatic column of the control system fluid, while the gas temperature in the charged state is typically the ambient temperature Special-purpose accumulators may also consider gas temperature from adiabatic compression, as illustrated in the appendix with a normally closed valve in a hydraulic assist circuit.
Condition 2 outlines the minimum operating pressure necessary for functional requirements, focusing on pressure-limited scenarios It emphasizes the importance of annular closing pressure for diverter operations and specifies that the rams bore working pressure divided by the rams closing ratio applies to both surface and subsea BOP stacks Additionally, valve opening pressure is relevant for subsea stacks, while shear pressure requirements pertain to shear circuits in both environments Purchasers may specify other minimum operating pressure requirements, and some accumulator systems must accommodate multiple pressure conditions For instance, a dead man circuit may necessitate pipe shearing at a higher pressure than a connector unlatch function, requiring careful design to meet both demands The volume design factor for this condition is the pressure-limited factor, \( F_p \), as detailed in Table 2 It is crucial to note that the pressure for Condition 2 must not fall below ambient hydrostatic pressure or the precharge pressure during full discharge conditions, which may be adiabatic, resulting in significantly lower temperature and pressure than the original precharge.
Condition 3, known as total discharge, involves discharging the maximum amount of fluid, often all of it However, this process may be restricted if the accumulator pressure equalizes with the subsea hydrostatic pressure before complete discharge occurs, leading to a volume-limited condition The total hydraulic volume available in this scenario is represented by the difference V 3 – V 1 The volume design factor for this condition is referred to as the volume-limited factor F v, as detailed in Table 2.
Stack-mounted accumulators can have precharge pressures that fall below seawater hydrostatic pressure In such cases, the full discharge is calculated similarly to Condition 2, using the hydrostatic pressure as the minimum pressure and applying the volume design factor for volume-limited discharge For instance, a 3000 psi accumulator precharged to 3000 psig (3014.7 psia) at 100°F and submerged to a depth of 10,000 ft experiences a hydrostatic pressure of 4464.7 psia, resulting in a surface-charging pressure of 7464.7 psia Additionally, under certain discharge conditions with adiabatic expansion, a significant temperature drop can lead to a temporary decrease in gas pressure below seawater hydrostatic levels until the gas warms up again.
The basis of the volumetric efficiency calculation is the following equation for fluid withdrawal at the condition of interest i:
Maximum gas pressure, psia Surface systems Subsea systems
Surface accumulators Rapid discharge systems, such as dedicated shear system
Surface accumulator (including credit for any stack-mounted accumu- lators) for subsea systems
Main hydraulic supply supplement stack-mounted accumulator
Rapid discharge sys- tems (e.g., autoshear, deadman) dedicated shear systems, and some acoustic and special-purpose accumulators Functional volume requirements
5.1.4: Close one annular and all rams and open one side outlet line 5.1.5.1: twice pilot function volume needed to close all BOPs in the BOP stack
5.5.3: operate all of the divert mode functions
Volume and pressure requirement specified by purchaser Usually 100% of function and required pressure times method design factor for volume.
5.2.3.1: Close and open one annular and four rams
5.2.3.2: pilot function volume needed to close and open one annular and four ram BOPs in the BOP stack 5.5.3: operate all of the divert mode functions
Volume and pressure requirement specified by purchaser May be required in order to meet closing times if flow supply from surface is inadequate without added subsea supply.
5.8.2.2, 5.9.1: Volume and pressure requirement specified by purchaser Usually 100% of function and required pressure times method design factor for volume.
< 5015 psia Method A Method C Method A Method A Method C
> 5015 psia Method B Method C Method B Method B Method C
Method A Method B Method C ideal gas, isothermal
1.5 volume design factor for volume-limited condition, F v
1.0 volume design factor for pressure-limited condition, F p real gas, NIST data, isothermal
1.4 volume design factor for volume-limited condition, F v
1.0 volume design factor for pressure-limited condition, F p real gas, NIST data, adiabatic1.1 volume design factor for both volume and pressure-limited conditions, F v and F p where:
V 0 = gas volume at condition 0 (precharge),
V i = gas volume at withdrawal condition of interest: 2 (minimum operating pressure), or 3 (total discharge),
F = Volume Design Factor for the condition of interest = F p for Condition 2 (pressure-limited), or F v for Condition 3
Gas volume can expressed by the following:
V i = m / ρ i where: m = mass of the gas, ρ i = density of gas at condition i (pressure and temperature). so:
VE i = ((ρ 0 /ρ i ) - (ρ 0 /ρ 1 ))/F where: ρ0 = density at precharge
For stack-mounted accumulators that enhance the supply from the main surface accumulator, the precharge is calibrated based on the temperature-adjusted original precharge and the height of the seawater column, typically at 0.445 psi/ft The density (\(ρ_1\)) of the accumulator is determined when it is fully charged at the "pump stop pressure," which includes the hydrostatic pressure of the control fluid column, usually fresh water at 0.433 psi/ft, for accumulators connected to the main hydraulic supply.
For Condition 2 pressure-limited case, VE p = (ρ0 / ρ2 – ρ0 / ρ1) / F p [ρ2 must be > = ρ0]: ρ2 = density when accumulator is at the minimum operating pressure as the greater of the following:
= calculated minimum operating pressure plus hydrostatic pressure of sea water column,
= component minimum operating pressure plus hydrostatic pressure of sea water column,
= user specified minimum operating pressure, such as to close annular preventer, operate special equipment, etc. For Condition 3 volume-limited case:
VE v = (1.0 – ρ0/ρ1)/F v ρ 3 = total discharge case, ρ 3 = ρ 0 For Optimum Precharge:
VE v = VE p = (ρ0/ρ2 – ρ0/ρ1)/F p Rearranged for Optimum Precharge Density: ρ 0 = F p /(F v /ρ 2 – (F v - F p )/ρ 1 )
These equations are further evolved for Methods A, B, and C in the following sections.
4.2.3.1.2 Method A (Ideal Gas, Isothermal Discharge, Pressures below 5015 psia, 1.5 Volume Design Factor for Volume-limited Discharge, 1.0 Volume Design Factor for Pressure-limited Discharge):
Equipment Design Specifications
To ensure well control equipment remains operational, the loss of rig power services, such as electricity or compressed air, must not lead to immediate loss of control Hydraulic power fluid is stored in accumulators, providing a backup in case of pump power failure Additionally, remote control panels are required to have sufficient backup power as outlined in this document It is crucial that no single point failure in subsea BOP control equipment results in the loss of control of both pods.
At least two control stations shall be provided The hydraulic control manifold may serve as one of those control stations At least one control station shall be full function.
Surface and subsea control function circuitry must be designed as self-contained systems, ensuring that a leak or failure in any single component or circuit element does not impact the operation of other functions.
The design and component selection process of the surface and subsea control system manufacturer must guarantee that all commodity items, sub-vendor materials, and the manufacturer's equipment meet or exceed relevant industry standards and specifications The purchaser is required to provide a comprehensive description and functional specifications, including details about the equipment to be operated, service conditions, and any application specifics essential for the manufacturer to create a compliant control system.
Annexes A and B are essential checklists for purchasers to define the functions to be controlled Annex A outlines the operating and interface requirements for a surface control system, while Annex B details the specifications for a subsea control system.
The hydraulic control manifold consists of hydraulic control valves, regulators, and gauges that directly manage system functions It enables manual adjustment of power fluid pressure according to the specifications set by the BOP manufacturer Additionally, the manifold offers direct pressure readings for both supply and regulated pressures.
An isolation valve must be installed with a nominal bore size that matches or exceeds the size of the control manifold supply piping to facilitate the supply of control fluid from an alternate source When not in use, this valve should be securely plugged.
A minimum of two (2) independent hydraulic pressure control circuits shall be provided (typically, manifold and annular BOP regulated pressure circuits).
The hydraulic control manifold features a centralized power fluid supply along with pressure regulation and control valves essential for the operation of ram BOPs and choke and kill valves It is equipped with a manifold regulator bypass valve or alternative methods to enhance manifold pressure, ensuring it does not surpass the working pressure limits set by stack system operators Additionally, the manifold is engineered to operate effectively at the system's rated working pressure during emergencies.
The manifold system must feature a specialized pressure regulator designed to lower the upstream manifold pressure to the power fluid pressure level specified by the BOP manufacturer This regulator should be highly responsive to downstream pressure fluctuations, ensuring that the set pressure is maintained within a tolerance of ± 150 psi.
The annular BOP pressure regulator must be remotely controllable, ensuring efficient operation In case of a loss of remote control capability, the system should allow for direct manual operation of the valve and regulator, enabling the closure of the annular BOP and the maintenance of the set regulated pressure.
To operate the control valve effectively, positioning the handle to the right (when facing the valve) will close the BOP, choke, or kill valve, while the left position will open these valves The center position, known as the “block” or “vent” position, shuts off the power fluid supply at the control valve Depending on the selected valve for the application, the other ports on the four-way valve may either be vented or blocked It is essential that the hydraulic circuit schematics clearly outline the port assignments for the center position of the control valve within the specific control system.
Valves and gauges shall be clearly functionally labeled.
Protective covers or alternative solutions that do not hinder remote operation must be installed on the blind/shear ram and other critical function control valves To facilitate local function operation, it is necessary to lift these covers or perform deliberate sequential actions.
All functions on the hydraulic control manifold shall be operable from the Rig Floor control station
For offshore installations, it is essential to have an isolated pilot supply, either pneumatic or hydraulic, to ensure the remote operation of surface manifold-mounted control valves without impacting manual control in case of pilot supply loss Additionally, the remote control system must allow for the operation of all surface control valves at least two times following a loss of rig air and electric power.
A minimum of one remote control panel must be provided to ensure operation from at least two locations for all critical system functions The panel's design requires two-handed operation for all control functions, with the exception of regulator control To prevent accidental operations, control devices will be spaced appropriately All analog circular mechanical meters must have a movement of at least 120° and a resolution of no less than 5%, with system accuracy maintained within ± 2.5% of full scale Pressure readings will be displayed in psi, with additional measurement units being optional Control and monitoring stations may utilize keyboards, CRTs, video displays, and alphanumeric displays that are suitable for the area classification When both the BOP and diverter are in operation, the status of the entire BOP stack and diverter will be displayed simultaneously, ensuring comprehensive functionality.
The control system must be designed for two-handed operation, utilizing pop-up controls alongside complete status displays, while avoiding menu-driven controls for system status Each control station display panel should show the entire BOP stack and diverter status, anticipating potential failures of multiple display panels Components in control panels must not exceed 150V RMS, with higher voltages confined to tool-accessible enclosures marked with warning signs Hydraulic lines must be positioned to prevent leaks from affecting electrical controls, and all electrical components in hazardous atmospheres must be certified for safety Rig floor panels should comply with API RP 14F recommendations, and any air purge system failure must trigger alarms and allow for electrical isolation Safety covers must ensure visibility of critical functions to prevent unintended operations, and panel designs should ensure that failures in one do not impact others Additionally, electro-hydraulic devices should be vented properly, and failures in remote control circuits must not lead to unintentional operations Finally, all common electrical circuits should be centralized to maintain functionality across remote panels connected in parallel.
The control station accessible to the driller, which may be the hydraulic manifold, must feature a remote panel that graphically represents the BOP stack It should control all hydraulic functions for BOPs, choke and kill valves, and other critical operations For offshore installations, the panel must display control valve positions and indicate when the electric pump is active, along with provisions for electric and pneumatic backup power for remote operations Additionally, it should allow control of the annular BOP regulator pressure setting and the manifold regulator bypass or override valve, or alternatively, provide remote control of the manifold regulator pressure The Rig Floor Panel must also include displays for essential readouts.
Control Systems for Surface Mounted BOP Stacks
BOP control systems for surface installations, including land rigs and offshore platforms, utilize hydraulic power fluid in a return-to-reservoir circuit Key components of these systems consist of storage equipment to ensure a sufficient supply of control fluid, pumping systems to pressurize the fluid, and accumulator bottles for storing the pressurized fluid Additionally, a hydraulic control manifold is essential for regulating pressure and directing fluid flow to operate BOPs and choke and kill valves Remote control panels enable operation of the hydraulic control manifold from distant locations, all relying on hydraulic control fluid for functionality.
The response time for activating and fully operating a function is determined by the blowout preventer (BOP) or valve closure and seal off For surface installations, the BOP control system must close each ram BOP within 30 seconds, while the closing time for annular BOPs smaller than 18 3/4 inches in nominal bore should also not exceed 30 seconds For annular preventers of 18 3/4 inches and larger, the closing time is set at 45 seconds Additionally, the response time for choke and kill valves, whether opening or closing, must not exceed the minimum observed ram close response time The measurement of closing response time starts when the close function is activated at any control panel and concludes when the BOP or valve is fully closed and seals effectively, which is indicated by the regulated operating pressure returning to its nominal setting.
Note: If confirmation of seal off is required, pressure testing below the BOP or across the valve is necessary.
Conformance with response time specifications shall be demonstrated by manufacturer’s calculations, by simulated physical test- ing or by interface with the actual BOP stack.
The manifold pumping unit supplies hydraulic power for all control system functions, serving both the BOP and diverter systems It must consist of at least two pump systems, each with independent power sources, ensuring reliable operation.
The manifold pumping unit must meet specific criteria, including the ability to maintain functionality when accumulators are isolated and one pump or power system is offline In such scenarios, the remaining pump systems should be capable of operating effectively within a two-minute timeframe.
1 Close one (1) annular BOP (excluding the diverter) on open hole.
2 Open the hydraulically operated choke valve(s).
Ensure that the final pressure meets or exceeds the higher minimum operating pressure specified by the manufacturers of both the annular blowout preventer (BOP) and choke valves Additionally, the combined output capacity of the pump systems must be adequate to charge the entire accumulator system from its pre-charge pressure to the rated working pressure within a 15-minute timeframe.
*An independent power supply is a source of power that is not impaired by any fault which disables the power to the other pump system(s) Examples of independent power supplies:
1 One pump may be powered from the emergency buss on an all electric power rig.
Electric drive rigs utilize independent power supplies through separate electric motors and motor controllers, provided they are connected to distinct busses or busses that can be isolated using a buss tie circuit breaker.
Compressed air is not classified as an independent power source unless it is generated by a compressor driven by a distinct prime mover Additionally, if the electric motors for the compressors are supplied by a separate electrical system, independent from the primary supply for the pumps, or if there is adequate stored air available, then it may be considered independent.
Each pump system must deliver a discharge pressure that meets or exceeds the system's rated working pressure Additionally, air-driven pump systems should be able to charge accumulators to the rated working pressure using a 75 psi air supply to operate the pump.
Each pump system must have at least two devices to prevent overpressurization The first device ensures that the pump discharge pressure remains within the system's rated working pressure The second device, typically a relief valve, is set to activate at no more than 10% above this rated pressure Additionally, the relief valve and vent piping must be capable of handling the maximum pumping capacity at up to 133% of the system's rated working pressure, with verification achieved through design calculations or testing.
To ensure effective prevention of pump over-pressurization, devices must be installed directly in the control system supply line to the accumulators without any isolation valves that could compromise their function Additionally, relief devices on main hydraulic surface supplies should feature automatic resetting, as rupture discs and non-resetting relief valves may lead to a total loss of pressure control.
Primary pumps are designed to automatically activate when the system's working pressure drops to around 90% of its rated level and will shut off when the pressure rises to between 97% and 100% of the rated working pressure.
Secondary pumps are designed to operate similarly to primary pumps, with the key difference being that their start set point can be adjusted to a slightly lower level to prevent simultaneous activation of both systems Additionally, the control for the secondary pump will not allow it to stop if the system pressure is above 95% of the rated working pressure and will automatically activate the pump if the pressure drops below 85% of the rated working pressure.
5.1.3.1 Accumulators shall meet design requirements of and be documented in accordance with applicable normative refer- ences listed in Section 2.
Note: Accumulators shall comply with 9.2.3.
The accumulator system must be engineered to ensure that the failure of a single accumulator or bank does not lead to a reduction exceeding 25% of the overall capacity of the accumulator system.
5.1.3.3 Accumulator designs include bladder, piston and float types Selection of type may be based on purchaser preference and manufacturer’s recommendations considering the intended operating environment.
Supply-pressure isolation valves and bleed-down valves must be installed on every accumulator bank to enable the checking of precharge pressure and to allow for the draining of accumulators back to the control fluid reservoir.
5.1.3.5 Accumulators shall be precharged with nitrogen Compressed air or oxygen shall not be used to precharge accumulators.
The precharge pressure in system accumulators is essential for propelling the hydraulic fluid necessary for system functions This pressure varies based on the specific operational requirements of the equipment and the surrounding environment It is crucial to ensure that the precharge pressure does not exceed the accumulator's rated working pressure.