The LNG plant process units are designed with controls that ensure equipment is operating within their design pressure and temperature limits, and maintain a stable operation. During startup, plant upset, or emergency situations, pressure will build up such that excess pressure or flow must be relieved to the flare system to maintain a safe operation.
- Flare and relief design considerations
- Plot plan consideration
- Process and control system considerations
- System optimization
- Administrative procedures
- Design guidelines
- Flare systems configurations
- Material of construction
- Maintenance consideration
- Relief scenarios
- Plant failure causes
- Operator error
- Loss of utilities
- Electricity failure
- Cooling water failure
- Instrument air failure
- Steam failure
- Fuel oil/fuel gas failure
- Inert gas failure
- Equipment or operation failure
- Reflux failure
- Reboiler failure
- Heat exchanger tube failure
- Air fan condenser failure
- Cooling water failure
- Loss of inert gas
- Instrument air failure
- Loss of electric power
- External fire
- Thermal expansion
- Thermal stress
- Vacuum relief
- Feed inlet control valves open
- Blocked discharge
- Amine absorber level control valve failure
- Control valve bypasses
- JT valves open during MCHE and MR compressor shutdown
- Warm LNG excursion
- Operator intervention
- Operation relieves
- Scrub column startup
- Liquefaction train startup
- NGL fractionation startup
- Vapor return from LNG tankers
- Vapor return from LPG tankers
- Ship loading dock relief
- Design pressure
- Vacuum pressure
- Maximum allowable working pressure
- Design temperature
- Minimum design temperature
- Other design considerations
- Use of restriction orifice
- High integrity pressure protection systems
- Purge gas supply to stack and pilots
- Computer modeling
The objectives of a flare and relief system are:
- Providing adequate Safety, Risks and Security Aspects in Liquefied Natural Gas Industrysafety for personnel and equipment, complying with all safety laws, design codes, and standards;
- Minimizing atmospheric discharge, reducing environmental impacts from the relief;
- Recovering boil-off vapors and liquids for reuse where economically viable;
- Minimizing community impacts by reduction in emissions, flare luminescence, noise, and smoke.
The following sections describe the design and operation considerations in a flare and relief system, addressing the emergency scenarios as well as the normal operational requirements of the flare system.
Flare and relief design considerations
The relief and flare system designs should accommodate the maximum relief loads, during emergency and off-design operations from the process units that may be required to continue operation.
The design of the flare system begins with an assembly of engineering documents that define the basis for the flare design. Typically, this would include:
- Heat and material balances of process units and utility systems;
- A flare and blowdown distribution diagram;
- Power distribution and one-line electrical diagram;
- A plot plan with equipment location details.
Plot plan consideration
Review the plot plan with equipment locations, especially vessels containing light hydrocarbons. If the equipment is grouped too closely together, a very large relief load may result during a fire, resulting in a large relief system. This activity should be completed early in the project to avoid expensive changes later in the project.
Process and control system considerations
- Higher equipment design pressures to reduce relief loads;
- More reliable power distribution system to avoid or reduce the impact of a power failure;
- Highly reliable, double-lead electrical systems fed from dual power grids;
- Instrumentation to automatically remove the source of pressure or heat that are the cause of overpressure;
- Reliable driver with spares for reflux pumps and cooling water pumps.
- Operating and capital cost estimates for the flare system components;
- The expected frequency of normal operational upsets and emergency situations, which will impact the flare system;
- Recovery of vent gases from different sources, such as storage tanks, equipment and instrument leakage, purge gas, and compressor distance piece vents;
- Segregation of the flare headers according to process services, such as high and low pressure headers, wet sour and dry flare headers, cold and warm flare headers;
- Avoiding release of flammable liquid or two-phase mixtures, or of high molecular weight condensable vapors that may create unacceptable hazards;
- Multiple combustion systems to handle various flare gas or liquid quantities, such as open pit combustion, ground flares, and thermal oxidizers;
- Compliance with the latest safety standards and assessment of the impacts from the flare operation on the surroundings. Review relief material disposal methods. Are they safe, economical, and environmentally acceptable?
With the exception of low pressure (less than 15 psig) relief devices, the design and certification of almost all pressure relief devices is governed by ASME Boiler Pressure Vessel Code. The ASME Code specifies basic requirements for construction, set pressure, performance, and capacity testing and certification. Other standards also exist, which govern pressure relief device application, but these documents usually are based upon use of ASME-approved devices. See Chapter 8 for more detailed discussions on codes and standards.
In addition to sound engineering and design of a flare and relief system, a strict administrative procedure must be enforced on plant operation, which plays an important role in the safety of pressure relief systems. Administrative procedures must be clearly defined, communicated to unit operators, and strictly enforced. Some of the administrative procedures are as follows:
- Lock (or car seal) procedures for block valves associated with pressure relief valves or associated equipment, such as separators, towers and suction drums. The procedures should include a list of all block valves that are required to be locked in position, procedures for maintaining logs of locked block valve positions, and periodic inspection of the relevant valves;
- Requirements that equipment be continuously attended during certain operations, such as steam out, which is known to be problematic in generating excessive pressure;
- Limitations on modification of equipment, piping, and instrumentation. Any changes must be approved with the plant’s engineering manager. Examples are pump impeller size changes, turbine driver speed adjustments, control valve trim alteration, and removal of control valve limit stops;
- Venting, draining, purging, and cleaning procedures for equipment maintenance.
A flare system typically consists of a piping system, liquid-vapor knockout drums, and a flare that includes flame igniters, pilots, and flare tips. The flare system also serves as a disposal system for excess hydrocarbon vapor release from pressure control valves during off-design operation.
The flare systems are primarily designed to dispose of vapor releases, but are also capable of handling liquids that may be present during unit upsets. Liquids may form in the flare header due to condensation of heavy hydrocarbons. The liquid content must be separated from the vapor in a flare knockout drum and processed in incinerators and burn pits. Incinerator is the preferred option for liquid disposal rather than a burn-pit because of its lower emissions.
An alternative to flare is to install a vapor recovery system that allows for recovery of valuable hydrocarbons; however, this would not reduce the flare size since the flare system must operate when the vapor recovery system is down.
Flare systems configurations
Because of the wide ranges of operating pressures and temperatures of the different process units in an LNG production plant, the flare and relief systems typically are equipped with at least two independent flare systems, a warm/wet flare and a cold/dry flare.
The warm/wet flare is for vapor release from the front sections of the plant, including the condensate unit, acid gas removal unit, dehydration unit, NGL fractionation unit, and various utility systems. The cold/dry flare is for the liquefaction plant and refrigeration units, NGL recovery unit, and the cryogenic liquid storage tanks.
For the cold flare, it can be segregated according to operating conditions:
- Low pressure relief from the NGL fractionation columns, relief from the shell side of the liquefaction main exchanger, and for depressurization during plant upset;
- High pressure flare for refrigeration compressors blocked discharge cases and other high pressure relief scenarios;
- Liquid flare for disposal of liquids during the plant start-up or shutdown.
For the wet and warm systems, it can also be segregated according to operating pressure:
- Low pressure flare for the low pressure equipment, such as amine regenerator, the sulfur recovery unit, and the tail gas unit;
- High pressure flare for the feed gas inlet equipment including the dehydration unit.
Liquids that are released during startup or shutdown or other transient periods are routed to the flare knock out drums by liquid blowdown headers separately from the main flare headers. Liquids are disposed of in a liquid burn pit or incinerators specifically designed for liquid combustion.
Material of construction
Low temperature fluids require special consideration, particularly if there is a possibility of cryogenic vapor release or low boiling liquids entering the disposal system that may cause low temperature due to auto-refrigeration as liquid depressurizes. In such cases, the system piping and drums will need to be fabricated of materials suitable for low temperature, such as stainless steel, to eliminate the risk of brittle fracture failures. For these reasons, the cold discharges are segregated in the cold/dry flare, which is constructed of stainless steel.
Operation of the LNG facility requires a reliable flare system. A flare system should be spared to some extent that would allow flare maintenance and replacement of individual components of the flare without shutdown of the facility. The maintenance of flare tip, riser, and knockout drums must be carried out without LNG production losses. Elevated flares, if they are installed on the same structure, should be of a dismountable and serviceable type while the other flares are on stream.
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The flare capacity of an LNG plant is typically controlled by the blocked discharge case and is generally very large; consequently, the flare structure is very high and can be over 100 m in height. The flare must be inspected periodically and maintained when necessary to avoid potential hazards, which may take weeks to repair. In most installations, shutdown of an LNG plant because of flare repair would result in significant loss in revenue and is unacceptable. Therefore, special considerations should be made in the design selection and the sparing philosophy, such as a single spare flare versus multiple smaller flares.
The design of each flare system is unique and shall be based on the process calculations and should not be copied from an existing plant. The relief scenarios can be broadly divided into emergency and operational.
Emergency cases are the events that result from plant upsets and emergencies that may exceed the system design capacity and beyond the controllable ranges of the control devices. Operational cases include the controllable events such as startup, shutdown, venting, nitrogen purging, blowdown of equipment, and piping, which are parts of the operation and maintenance procedure.
In the analysis of the relief loads, simultaneous occurrence of separate events that can lead to relief, is considered double jeopardy and generally is not considered. Exceptions to this rule occur when major events with unacceptable consequences of failure have been identified in HAZOPs or design reviews. In some cases, multiple causes of relief may be added together to form the design basis for a single relief case, such as in systems operating at very high pressures, potential of explosion, and material failure.
Plant failure causes
There are two types of plant failure causes. The first one is due to operator error and the second one is due to utility failure.
Operator error is a potential factor causing plant upsets and overpressure. The most common error is the inadvertent closing or opening of block valves. Proper training, safe plant practices, posting of legible instructions and warning signs, and provisions for valves locked or sealed in the open or closed position are among the some of the preventative measures that can reduce the occurrence.
Loss of utilities
The consequences that may develop from the loss of any utility service, whether plantwide or local, may result in partial or total shutdown of the equipment and associated system including the following.
- Pumps for circulating cooling water, boiler feed water, or reflux in columns;
- Fans for air-cooled exchangers, cooling towers, or combustion air;
- Compressors for process gas, instrument air, vacuum, or refrigeration;
- Motor-driven valves.
Cooling water failure
- Reflux condensers for fractionation columns;
- Coolers for process coolers, equipment cooling fluids, lubricating oil, or seal oil;
- Jacket coolers on rotating or reciprocating equipment.
Instrument air failure
- Transmitters and controllers;
- Alarm and shutdown systems;
- Process control valves.
- Steam turbine drivers for pumps, compressors, blowers, combustion air fans, or generators;
- Heat to reboilers;
- Stripping steam for strippers;
- Steam to steam eductors.
Fuel oil/fuel gas failure
- Fuel to operate heaters and boilers;
- Fuel to engine drivers for pumps or electric generators;
- Gas turbine drivers for compressors.
Inert gas failure
- Loss of seal gas to pumps, compressors, and expanders;
- Loss of tank pressure control on nitrogen blanketing;
- Purge for instruments and equipment.
Equipment or operation failure
Reflux failure is one of the more common causes for overpressure. The loss of reflux usually results in overhead condenser flooding. Relief devices are sized to handle relief loads based on total loss of cooling. If the operator fails to respond in time, the condenser can flood and the upset condition is likely to occur.
Steady state analysis of tower relief loads typically requires conservative assumptions based on normal tower compositions and temperature profiles. In reality, tower relieves result from dramatic changes in flows, pressure waves, heat and mass transfer, and other phenomenon that can only be assessed via dynamic analysis. Tower dynamic analysis is usually used to calculate an actual tower relieving load, which can be much lower than the steady state assumption. This is particularly true when the column contains a high boiling point material, which does not produce much vapor during this scenario.
Excessive heat input or steam to a reboiler may cause column overpressure when vapor generation capacity exceeds the condensing capacity. This typically occurs when the reboiler temperature control system fails; steam pressure is higher than design, particularly with oversized heat exchangers.
In addition steam failure may trigger a series of events that could result in overpressure. Over-pressure may result from the loss of steam to any steam turbine driven reflux pump, cooling water pump, or compressor. In a NGL fractionation train, where steam is the source of reboiler heat, loss of steam to the reboiler of the deethanizer will send light NGL to the depropanizer, which will produce excessive vapor that can overpressure the depropanizer. This effect may also be cascaded to the subsequent columns, and eventually the complete fractionation train will be overpressure.
Heat exchanger tube failure
Heat exchanger tubes are subject to failure from a number of causes. The normal mode of failure is small leakage from a heat exchanger tube. However, complete rupture of a single tube should also be considered. A pressure relief valve or rupture disk may not be necessary for protection if the piping and downstream equipment on the low pressure side can handle the fluid from the high pressure source without exceeding the hydrostatic test pressure.
There is a safety caution on tube rupture. The sudden loss of a tube can be followed by acceleration of the fluid on the low pressure side and pressurization of that system. The duration and magnitude of these short-term spikes and their impact on the system can be assessed by a dynamic analysis. This type of analysis is recommended, in addition to the steady state approach, where there is a wide difference in design pressure between the two exchangers, especially where the low-pressure side is liquid-full and the high-pressure side contains a gas or a fluid that flashes across the ruptured tube.
Air fan condenser failure
Air condenser failure may cause overpressure in upstream equipment. For air cooled condensers the relieving quantity may be reduced due to cooling by natural convection. A value of 25 % of normal duty can typically be credited because of natural convection heat transfer. If necessary, a more vigorous simulation can be performed on the heat transfer. If the piping system is unusually large and uninsulated, the effect of heat loss from the piping to the surroundings can also be considered to reduce the relief load.
Cooling water failure
Complete or partial loss of cooling water supply may be caused by power failure or equipment breakdown. The layout of the cooling water piping and system must be analyzed, as it may be too conservative to assume a complete loss of cooling water flow to all units. The standby pump driver usually has an alternate energy source using steam or separate power bus. The maximum quantity relieved under these circumstances can be calculated by heat and material balances around the system. Usually, loss of cooling water to an overhead cooler/condenser system also results in reflux failure.
On detection of low-low cooling water flow, all the trains should be shut down via the DCS. There may be some relief due to the heating up of the train and the loss of reflux in the fractionators.
The main impact in an LNG plant is on the supply of cooling to the propane refrigeration system. The propane compressor discharge pressure will quickly increase, which could lead to the opening of the PSVs of all the trains. To mitigate this problem, several control options can be considered in the design:
- Shutdown of the propane compressor driver on low-low cooling water flow;
- Shutdown of the propane compressor driver on high-high discharge pressure;
- HIPPS on the propane discharge to avoid overpressure.
The purpose is to avoid all the propane compressors of multiple trains relieving at the same time. Assuming that all devices mentioned earlier have been provided, it can generally be assumed that only one propane compressor trip is responsible for the relief, which must be carefully confirmed in the safety and design review.
Loss of inert gas
Loss of inert gas will stop blanketing gas supply to the product storage tanks, which may eventually lead to vacuum relief. It will also cut off the supply of seal gas to rotating equipment, resulting in an unsafe operation. Alarms and a shutdown system to detect loss of seal gas pressure should be provided in the DCS and used for equipment shutdown to stop the hazardous operation.
Instrument air failure
Instrument air failure may be local or total. In the total instrument air failure case, all ESD valves reach their fail safe position and the trains are shutdown and isolated. The main concern may be on the depressurization valves, which, if not supplied with air, will switch to the open position, possibly depressurizing all the trains at once. To resolve with this problem, these shutdown valves should be equipped with instrument air bottles.
Loss of electric power
Loss of electric power can cause a wide range of upsets resulting in overpressure. Power failure may be further classified as local, intermediate, or total.
Local power failure can affect the operation of individual equipment items, such as air fans, reflux pumps, and solenoid valves that are not on uninterruptable power supply (UPS).
Intermediate power failure affects the operation of one electrical distribution center, one motor control center, or one bus. Depending upon how a group of motors are connected to the power source, multiple failure conditions may occur. For example, assume that the reflux pumps of a fractionator are motor driven and connected to the same bus line. If a bus line failure occurs, the accumulator is flooded, eventually resulting in a flooded condenser. The preferred practice is to place motors in complementary service on separate bus bars to minimize the chance of this type of failure.
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Total power failure is assumed to be 100 % loss of electric power except for the UPS. Backup electric power sources should be considered in the analysis of the effects of electric power failure. Emergency power to key equipment, lighting, or buildings is typically supplied by diesel generators that are supposed to start on power failure. The emergency loads are then picked up based on preestablished priorities. There is a time lag between loss of power and having equipment on emergency power start. Critical electronic instrumentation is generally connected to the UPS to ensure safe and orderly shutdown upon loss of normal power supply. This system provides battery backup to assure that electronic instrument functionality is maintained throughout the power failure.
Two possible scenarios may be envisaged for sizing the flare for power failure:
- For the case when the train inlets are closed, the relieves are from within the train, such as loss of reflux in fractionation;
- If the train inlets are not closed, pressure continues to rise in the liquefaction train and the pressure control valves from the feed gas section will start opening. In this scenario, several trains can be relieved to the flare system at the same time.
The UPS is typically designed to last for about 45 minutes. After that, if the emergency diesel generator has not taken over, the solenoids will be deenergized and the depressurization valves open. Therefore, in theory, all depressure valves of all trains may open at the same time, leading to the depressurization of all trains simultaneously, resulting in a large relief.
Fire provides an unanticipated energy input to a system, which results in overpressure by thermal expansion or vaporization of the retained fluid. Depressurization can be used to reduce the pressure of vessels, equipment, and piping below normal operating pressure to prevent rupture caused by localized fire heating.
The procedures given in API standards or recommended practices (API ST 521 or API ST 2 000) are to be utilized, unless otherwise ruled by local (or country) regulations. In some countries different calculation methods than API (for example, those countries that have adopted Japanese standards) are used. In the United States, some states dictate the use of methods in the NFPA codes. Therefore, it is important to define the fire load calculation methods at the beginning of any project.
Protection of process plant systems from the impact of a fire involves a combination of approaches such as fireproofing, fire monitors, equipment location, and equipment depressurizing, in addition to the use of pressure relief devices. The following basic assumptions are generally used in determining the fire case relief loads:
- The process is assumed to be shut down and isolated from other vessels, sources of process fluids, or other relief paths;
- Liquid inventories are assumed to be at maximum operating level at the high level alarm set point;
- Heat input to process equipment is calculated based on empirical equations required by codes and standards based on installation and environments;
- All fire heat input is assumed to be used for vaporizing the vessel contents instantaneously.
Depressurizing can be used to reduce the pressure of vessels, equipment, and piping below normal operating pressure to prevent rupture caused by localized fire heating. To cope with this problem, the depressurizing sequence can be configured using a timer that allows depressurizing one train at a time in a timely ordered manner.
Emergency depressurizing of a high pressure system can impact the design of both the unit and the flare system. Internal to the unit, equipment temperatures will be lowered by the JT effect cooling during depressurizing. Flare capacity may also be impacted by high pressure drop and low temperature during depressurizing. Depressurization should be performed under emergency conditions only after a major incident. After depressurization, sufficient time should be allowed for the equipment to warm up to avoid temperature stress on the equipment. It is not envisaged to restart, hence repressurize, the train just after a depressurization has occurred.
Depressurization should be manually actuated from the Central Control Room with hard wired connections. A depressurization system actuated from the Central Control Room is mandatory for a piece of equipment or a process system isolated by ESD valves. The depressurization is achieved through a blowdown valve (on/off air actuated ball valve) and a restriction orifice, which set the depressurization rate. To determine the flow rate the following assumptions can be made:
- The initial pressure is the design pressure of the system;
- The system is exposed to an outside pool-type fire;
- The pressure of the section to be reached within the time set below is typically half the design pressure or as required by local codes and standards;
- The time allowed for depressurization is not to exceed 15 minutes.
Thermal expansion or hydraulic expansion is the increase in liquid volume caused by an increase or decrease in temperature. It can result from several causes, the most common of which are the piping or vessels blocked in while they are filled with cold liquid and are subsequently heated, or an exchanger that is blocked in on the cold side with continuous flow on the hot side.
In certain installations such as in cooling circuits, equipment arrangements and operating pro-cedures may eliminate the case for an expansion relieving scenario. For example, when one block valve on the cold side of a multiple shell and tube exchanger is locked open, it will eliminate the possibility of blocking and expanding the enclosed liquid in the entire train.
For Brazed Aluminum Exchanger, the maximum operating temperature is limited to 150 °F. Heat source with high temperature must be avoided by a shutdown system that is necessary to avoid material failure of the aluminum exchanger.
Under different circumstances, some of the same factors that lead to overpressure can lead to a drop in operating pressure to the extent that vacuum relief may be required to prevent the equipment from collapsing under the vacuum. Such occurrence includes the quenching of steam in a vessel during startup, and the withdrawal of liquid from a low pressure tank without makeup gas.
Feed inlet control valves open
Every control valve must be considered as subject to inadvertent operation from the fully open to fully closed position independent of the failure position. Some control devices are designed to remain sta-tionary in the last controlled position when the control signal or operating power fails. Since predicting the position of the valve at the time of failure is not possible, such devices could be considered either open or closed; therefore, no reduction in relief capacity should be considered when such devices are used.
The cause of control valve failure may be due to one of the following incidents:
- Loss of transmission signal to the valve positioner;
- Failure of control valve operating medium (air, hydraulic oil, electricity, etc.);
- Process measuring element failure;
- Process measuring element transmitter failure.
For these cases, the required relief capacity is the difference between the maximum inlet flow and the normal outlet flow at relieving conditions, assuming that the other valves in the system are still in normal operating position. If one or more of the outlet valves are closed by the same failure that caused the inlet valve to open, the required relief capacity is the difference between the maximum inlet flow and the minimum flow from the outlet valves that remain open.
If the gas is dry, the inlet gas can be routed to the cold/dry flare and in that case the flow is most likely less than that from the blocked discharge case from one of the propane compressors. The block feed inlet and the compressor block outlet should not be considered coincidental.
If the gas is wet, it is likely to be the sizing case for the wet/warm flare. Note that due to the JT cooling effect, the temperature may drop below the hydrate temperature of the wet gas, which may cause plugging problems in the flare system.
In the event of loss of upstream liquid level, vapor may pass into the downstream system at high rates determined by the differential pressure between the systems. In some cases the maximum vapor rate may cause the upstream system to gradually depressure and result in gradually declining flow.
Blocked discharge situations apply to compressors, pumps, and other process systems. Generally, omission of block valves on vessels or locked open valves and equipment in series can simplify and avoid the pressure relieving scenarios.
In applying administrative controls, such as locks or car seals and associated procedures, to minimize the potential for block valve closure, consideration should be given to the potential con-sequences if the administrative procedure is circumvented and the block valve is accidentally closed.
For compressor block discharge cases, such as the propane compressor and MR compressor, the maximum flow should be based on vendor’s compressor curves and the turbine driver operating at its maximum speed. For multiple compressors operating in parallel, two compressor outlet valves closed at the same time is typically not a credible scenario. The block compressor discharge case is generally the sizing case for the high pressure dry/cold flare.
Amine absorber level control valve failure
When the amine absorber valve fails open, the feed gas flow can be sent directly to the amine flash drum through the level valve, potentially overloading the flare system. The relief rate depends mainly on the size of the level and the valve characteristics \( (C_v) \), and the Crew Evaluation Test online for seamans about Basic Hydraulic Systemsystem hydraulics and piping sizes. In most cases, the high pressure differential may result in a large vapor breakthrough, which can be one of the sizing cases for the wet /warm flare.
Control valve bypasses
Control valve bypasses are provided for the purpose of maintenance of the main control valve and are subject to inadvertent opening due to misoperation.
Simultaneous full opening of a control valve and its bypass normally is considered to be double jeopardy. Either full opening of the control valve with the bypass in the normally closed position or full opening of the bypass with the control valve in its normal operating condition is generally considered as a credible case. In some instances, control valve bypasses have greater capacity than the control valve itself and may constitute a controlling factor in overpressuring of the downstream equipment. In such cases, installation of a reduced size bypass valve or restrictor can reduce the relief flow.
JT valves open during MCHE and MR compressor shutdown
In the case of liquefaction unit trips, the MR compressor will be shut down, the suction valves closed, and JT valves closed. The discharge stays at a high pressure. If the JT valves are reset, a large quantity of MR will flow to the shell, vaporize, and the pressure might reach the design pressure of the shell. The relief flow is routed to the low pressure dry/cold flare.
Warm LNG excursion
If the temperature control valve downstream of the main exchanger opens widely by error some warm LNG would be directed to the LNG storage and generate a significant amount of gas.
Since the ship loading flares are not designed for this large flow, a HIPPS system should be designed specifically for such a case. The HIPPS system consists of several independent temperature detectors, hard wiring, voting systems, several ESD valves, and triplicate redundant modular control system.
The decision to take credit for operator response must be carefully evaluated. Credits are given only after determining the relieving conditions considering the complexity of the process and controls, speediness to respond to the emergency situation, technically qualified personnel, and the risk asso-ciated with the failure of operator response. The minimum response time for operators typically ranges from 10 to 30 minutes. Among the factors that must be considered are:
- Operator response time is considered additional to the time required for an operator to recognize the emergency situation;
- Operating personnel must be able to correct or stop the event with a simple response before relief is required.
Special caution should be observed when using operator response to mitigate liquid overfill, due to the occurrence of several major industrial incidents that have resulted from liquid overfill. The effectiveness of operator response must be evaluated. Note that a correct response may reduce but may not totally eliminate the safety problem.
Scrub column startup
During the startup and cooldown of the liquefaction plant, the pressure of the scrub column overhead must be maintained by venting the overhead gas from the scrub column reflux drum to the cold dry flare. At the same time, before the NGL fractionation is placed on stream, the scrub column bottoms are also routed to the cold flare for disposal.
Liquefaction train startup
During liquefaction plant startup, the warm LNG (gas liquid mixture) at the outlet of the MCHE is sent to the cold flare till the LNG product temperature is cooled to the design condition that can be accepted by the LNG storage tanks.
NGL fractionation startup
When the scrub column is stabilized, the NGL can be routed to the NGL fractionation train. Off-spec liquid products from the depropanizer and debutanizer are routed to flare.
Vapor return from LNG tankers
During ship loading, the boil-off vapor is routed to a tank boil-off vapor header that feeds the boil-off compressor. The compressed gas vapor can be used as fuel gas; any excess is disposed of in the flare system.
Vapor return from LPG tankers
Most of the tankers have their own on-board system to dispose of excess gas and some of the tankers have a reliquefaction unit. Therefore relief from the LPG tankers is infrequent but emergency flow needs to be considered. Overpressure can also be avoided by reducing the ship loading rate until the system is in balance.
Ship loading dock relief
The followings are some of the loads that may contribute to the relief sizing during ship loading:
- LNG carrier is being loaded, generating vapors from pump heat;
- LNG pumps operating and on recycle, generating excessive vapors;
- LNG boil-off compressor out of service for maintenance;
- Heat leaks from storage tank, rundown lines, and loading lines;
- Maximum barometric pressure drop during a hurricane;
- Instrument air failure;
- Vacuum break gas valves failure;
- LNG tankers vapor return blowers malfunction;
- Total plant power failure.
The design pressure for the equipment that will be relieving to the flare defines the service requirements for the relief system. Often, a small increase in the design pressure can reduce the cost and complexity of the relief system or even eliminate the need for pressure relief for particular contingencies. If the equipment design pressure is low or the anticipated relieving rates are high, additional care should be taken in this selection. It should be kept in mind that higher design pressure selection may reduce or eliminate frequent venting to the flare system.
The flare seal drum, knockout drum, and the flare piping are typically designed for 50 psig. However, higher pressures shall be specified if required by hydraulic evaluation.
It is possible to develop a vacuum condition in the relief header due to cooling and condensation of hot relieving vapors through ambient heat loss from the relief header, although the resulting event is the introduction of atmospheric air through the flare tip. Since this is undesirable because of potential explosion hazards, the flare design should provide an emergency purge (inert) gas addition through a control valve that opens when a hot flare relieving condition is detected in the flare header.
In any event, the relief header, flare seal drum, and flare K.O drum should be designed for at least half vacuum condition for these cases and for potential steam-out conditions during startup and maintenance. This should normally not impact the vessel and piping mechanical design because this equipment is typically designed for 50 psig.
Maximum allowable working pressure
Design pressure and design temperature are used as the basis for design of ASME Section VIII pressure vessels. A required thickness for the walls is calculated and the next commercially available size is selected. Since this typically results in the actual vessel wall thickness being higher than the calculated wall thickness, the vessel will be able to withstand a higher pressure than the specified design pressure. The higher pressure is referred to as the vessel maximum allowable working pressure (MAWP). The higher pressure margin can be used to optimize the flare design by increasing relief valve set pressures and relief capacity, provided all other components in the system are also suitable for the higher design pressure.
Since all relieving scenarios are considered to be under abnormal operation (i.e., either startup/shut- down or emergency operation), the normal condition for the flare system is with no flow other than the purge gas. Therefore, the normal operating temperature is considered to be the temperature of the purge gas even though the flow is so small that the physical reality is that the pipe and equipment wall temperatures will be at the ambient temperature.
Minimum design temperature
The application of auto-refrigeration temperatures in setting the minimum design temperature for the flare system should consider the relevant relief rate and duration, as well as the system metal mass and ambient temperature.
Maximum Design Temperature (MDT): All the potential flare relieving scenarios to determine those with the highest associated temperatures should be analyzed. Most scenarios, such as fire, cooling water failure, and power failure would be considered short-term upsets. The application of these short-term temperatures excursion in setting the maximum design temperature for the flare system should be considered.
Longer duration scenarios such as startup and shutdown should also be considered in selecting the flare system design temperature.
Caution: Selecting an unnecessarily high design temperature for the flare header will result in significant cost and plot plan impact as numerous large expansion loops will need to be included in the design to account for the thermal stresses.
Other design considerations
Use of restriction orifice
A restriction orifice or reduced trim valve can be used to limit the flow, such as that from amine absorber level valve to the flash drum. The use of restriction orifice can be used on other letdown stations to limit the vapor or liquid flow that may be due to operator errors or equipment failure.
High integrity pressure protection systems
High integrity pressure protection systems (HIPPS) may be considered for the following duties:
- Propane compressor blocked discharge;
- MR compressor blocked discharge;
- High feed gas pressure when the upstream operation can be higher than the LNG plant design pressure;
- LNG tank overflow.
Purge gas supply to stack and pilots
It has to be stressed that the source of purge gas should be fully reliable, redundant, and with backup to avoid any disaster. If the purge gas has a density lower than air, which is generally the case in LNG plants, there is a risk of having a vacuum situation in the flare header in case of low purge gas flow, hence a risk of air ingress.
Many hydraulic programs have been developed and can be used specifically for relief system networks hydraulic design and evaluation. The following are some of the latest programs that are available in the industry.
- FLARENET is created for Flare Networks. It is a design and analysis tool with a steady state model of the flare network from PSV to flare tip;
- VISUAL FLOW ranges from line sizing and vessel depressurizing to the rating of complex relief systems. Process and Safety engineers can design, rate, and analyze processes with this rigorous steady-state simulator.
iam interseted for a new technology to recover flare gaz in LNG industry as you mentionned above; flare system:For the cold flare, i would like to know if there is solution for used this flare gas