This section is concerned with the design and operation of pressure relieving systems for gas processing plants. The princi pal elements of pressure relief systems are the individual pres sure relief devices, the flare piping system, the flare separator drum, and the flare — including igniters, tips, sealing devices, purge and steam injection for smokeless burning. Application of relief devices must comply with appropriate ASME Vessel Codes. Design of relief systems must also comply with applica ble state and federal codes and laws as well as the requirements
SECTION Relief Systems of the insurance underwriter covering the plant or installation State and federal regulations not only cover safety but also environmental considerations such as air and water pollution and noise abatement This section presents a convenient summary of relief system information obtained from API and other sources, abridged and modified for this data book Final design work should be consistent with the full scope of API, ASME, and other code and specification requirements This section is concerned with the design and operation of pressure relieving systems for gas processing plants The principal elements of pressure relief systems are the individual pressure relief devices, the flare piping system, the flare separator drum, and the flare — including igniters, tips, sealing devices, purge and steam injection for smokeless burning Application of relief devices must comply with appropriate ASME Vessel Codes Design of relief systems must also comply with applicable state and federal codes and laws as well as the requirements FIG 5-1 Nomenclature I k Kb Kc Kd Kn Ksh = radiation intensity at point X, W/m2 = specific heat ratio, Cp/Cv (see Section 13) = capacity correction factor due to back pressure = combination correction for rupture disk = 0.9 = 1.0 no rupture disk installed = coefficient of discharge = correction factor for Napier steam equation = correction factor due to the amount of superheat in the stream Kv = capacity correction factor due to viscosity for liquid phase pressure relief Kw = capacity correction factor due to back pressure for balanced bellows pressure relief valves in liquid service (Fig 5-14) L = drum length, m L/D = length to diameter ratio of pipe Lf = length of flame, m M = Mach number at pipe outlet MW = molecular mass of gas or vapor MABP = maximum allowable back pressure, kPa (ga) NHV = net heating value of flare gas, kJ/kg P = set pressure, kPa (ga) PCF = critical-flow pressure, kPa (abs) Pn = normal operating gas pressure, kPa (abs) P1 = upstream relieving pressure, kPa (abs) This is the set pressure plus the allowable overpressure plus the atmospheric pressure P1g = upstream relieving pressure, kPa (ga) This is the set pressure plus the allowable overpressure P2 = downstream pressure at the valve outlet, kPa (abs) Pb = back pressure, kPa (ga) ∆P = pressure drop, kPa ∆Pw = pressure drop, mm of water Q = heat input, W Qr = heat released, W Qv = flow through valve, m3/h at standard conditions (101.325 kPa (abs), 0°C) r = ratio of downstream pressure to upstream pressure, P2/P1 R = distance from flame center to point X, m a = sonic velocity, m/s A = required discharge area of the valve, cm2 Use valve with the next larger standard orifice size/area AB = bellows area, cm2 A´ = discharge area of the valve, cm2, for valve with next standard size larger than required discharge area AD = disk area, cm2 AN = nozzle seat area, cm2 AP = piston area, cm2 Aw = total wetted surface area of vessel, m2 A3 = vessel area exposed to fire, m2 B = liquid expansion coefficient, 1/°C, at relieving temperature [or (Vol/Vol)/°C] C = drag coefficient Cp = specific heat at constant pressure, kJ/(kg • K) Cv = specific heat at constant volume, kJ/(kg • K) C1 = coefficient determined by the ratio of specific heats of the gas or vapor at standard conditions d = flare tip diameter, mm D = particle diameter, m f = correction factor based on the ratio of specific heats F = environment factor (see Fig. 5-16) F´ = relief valve factor, dimensionless F* = fraction of heat radiated F2 = coefficient for subcritical flow (Fig 5-12) Fs = spring force, Newtons g = acceleration due to gravity, 9.81 m/s2 G = relative density of gas referred to air = 1.00 at 15°C and 101.325 kPa (abs); or, if liquid, the relative density of liquid at flowing temperature referred to water = 1.00 at 15°C hL1 = enthalpy of saturated liquid at upstream pressure, kJ/kg hL2 = enthalpy of saturated liquid at downstream pressure, kJ/kg hG2 = enthalpy of vapor at downstream pressure, kJ/kg H = height of vapor space of vessel, m Hl = latent heat of the liquid exposed to fire, kJ/kg HS = flare stack height, m 5-1 FIG 5-1 (Cont’d) Nomenclature J Ro = universal gas constant = 8314 kg • mol K Re = Reynolds number (dimensionless) S = specific heat, kJ/(kg • °C) t = temperature, °C T = absolute temperature of the inlet vapor, K Tn = normal operating gas temperature, K T1 = gas temperature, K, at the upstream pressure Tw = vessel wall temperature, K Ud = maximum allowable vapor velocity for vertical vessel, m/s V = gas velocity, m/s Vex = exit velocity, m/s Vl = flow rate, liters/s at flowing temperature and pressure Vw = wind velocity, m/s W = flow, kg/h Whc = hydrocarbon flow, kg/h Wstm = steam flow, kg/h Wf = flare gas flow rate, kg/h Wr = vapor rate to be relieved by the relief valve, kg/h xi = weight fraction of component i in total stream X = distance from the base of the stack to another point at the same elevation, m Xc = dimensional reference for sizing a flare stack (Fig. 5-19) Yc = dimensional reference for sizing a flare stack (Fig. 5-19) Z = compressibility factor at flowing conditions Greek DOCUMENTATION ∆ ε ρL ρv θ µ = prefix, indicates finite increment = fraction of heat radiated = density of liquid, kg/m3 = density of vapor, kg/m3 = angle of flare flame from vertical, degrees = viscosity at flowing temperature, mPa • s (centipoise) μS = viscosity at flowing temperature, Saybolt Universal Seconds (SSU) • Preliminary hazard review using process flow diagrams and a preliminary layout, to identify hazards in the process, with the proposed facility location, and layout, and with storage and handling of feed materials or intermediate and final products A facility’s documentation allows the user to determine that the facility was designed in accordance with relevant codes and standards The relief system design documentation is one facet of the overall facility documentation, which helps demonstrate that the process can be operated in a safe manner Any equipment modifications, operations, or changes made to process parameters, or operating procedures, can have a direct impact on the relief system, and should therefore be documented as part of a facility management of change (MOC) process • Early engineering hazard review with more advanced work products • Detailed hazards review using one of several possible techniques sanctioned by local authorities (e.g., HAZOP, Hazard and Operability Analysis, What-if, Quantitative Risk Evaluation), utilizing process and instrumentation diagrams, plot plan, and other detailed design deliverables The relief system documentation should demonstrate that all pressure-containing equipment has been identified and that the overpressure protection has been analyzed Documentation based on the individual protected systems can facilitate ensuring that all systems requiring pressure protection have been identified The documentation should show that potential causes of overpressure have been identified, rationale has been provided as to whether a scenario is or is not credible, and credible causes of overpressure have been evaluated The design basis of the disposal system, including all assumptions made in the determination of controlling load(s), and calculated back pressure at each relief device should be documented A detailed list of documentation requirements is presented in ISO 23251 (API Std 521) • Safety Integrity Level (SIL) Review • Engineering management of change (MOC) process • Facility management of change (MOC) process • Pre-start-up detailed hazard review • Periodic detailed hazard review CAUSES OF OVERPRESSURE Pressure relief valves or other relieving devices are used to protect piping and equipment against excessive over-pressure Proper selection, use, location, and maintenance of relief devices are essential to protect personnel and equipment as well as to comply with codes and laws HAZARD REVIEWS Appropriate hazard reviews, as a part of a Process Safety Management Program, are required by U.S OSHA-29 CFR Part 1910 in the United States, and by similar regulations in most other localities in the world These reviews are conducted during the design phase, prior to operation, and periodically during operation The relief device sizing, and relief and disposal system design, are critical components of this review Typical steps in this process are: Determination of the maximum relief requirements may be difficult Loads for complex systems are determined by conservative assumptions and detailed analysis By general assumption, two unrelated emergency conditions caused by unrelated equipment failures or operator error will not occur simulta- 5-2 neously (no double jeopardy) The relationship and sequence of events must be considered ISO 23251 (API Std 521) provides further guidance on these issues The development of relief loads requires the engineer to be familiar with overall process design, including the type of pump drives used, cooling water source, spares provided, plant layout, instrumentation, and emergency shutdown philosophy The design of the proper relieving device must take into consideration, as a minimum, all of the following upset conditions for the individual equipment item if such upset can occur Each upset condition must be carefully evaluated to determine the “worst case” condition which will dictate the relieving device capacity The following provides guidance for some common overpressure scenarios It must be recognized that it does not and cannot address all potential overpressure scenarios that may be relevant for a specific piece of process equipment The designer should employ the Hazard Reviews discussed above to ensure that all credible overpressure scenarios have been incorporated into a facility’s design SUMMARY OF COMMON RELIEF SCENARIOS ture disk) on, or close to, the low pressure side of the heat exchanger, 2) ensure there is an adequate open relief path, so that the low pressure side will not be over-pressured by a tube rupture, or 3) design the low pressure side of the heat exchanger, and the piping and equipment in the associated systems, such that the corrected hydro-static test pressure of the low pressure system exceeds the high pressure side design pressure (in some cases maximum upstream side operating pressure may be used instead of design pressure) The best option for each application is a function of the operating and design pressure for each side, fluid phase on each side, fluid type and service corrosion history, and the heat exchanger design Systems with gas, two phases, or a liquid which will flash across the tube rupture, on the high pressure side, and a liquid on the low pressure side, should be thoroughly reviewed, since a relief valve may be less effective in preventing surges in these circumstances See ISO 23251 (API Std 521) for the definition of corrected hydro-static test pressure and detailed guidance on this subject Relief protection for tube rupture is not required for double pipe heat exchangers, if the internal parts are constructed of schedule pipe Control Failure Blocked Discharge The outlet of almost any vessel, pump, compressor, fired heater, or other equipment item can be blocked by mechanical failure or human error The relief load for many cases is the maximum flow into the system, at relief conditions, but must be carefully analyzed for each contingency Fire Exposure Fire is one of the least predictable events which may occur in a gas processing facility, but is a condition that may create the greatest relieving requirements If fire can occur on a plant-wide basis, this condition may dictate the sizing of the entire relief system; however, since equipment may be dispersed geographically, the effect of fire exposure on the relief system may be limited to a specific plot area Various empirical equations have been developed to determine relief loads from vessels exposed to fire Formula selection varies with the system and fluid considered Fire conditions may overpressure vapor-filled, liquid-filled, or mixedphase systems See the discussion on Sizing of Relief Devices, for details, and relief load calculation methods Tube Rupture The tubes of shell and tube heat exchangers are subject to failure from a number of causes; including corrosion, thermal shock, and vibration In the event of such a failure, it is possibile that the high-pressure stream can overpressure the equipment and piping connected to the low pressure side of the exchanger A tube rupture can also cause short duration hydraulic pressure shock, due to the rapid acceleration of the fluid on the low pressure side at the time of rupture An internal failure can vary from a leaking tube or tube sheet to a complete tube rupture where a sharp break occurs in one tube The loss of containment of the low-pressure side to atmosphere is unlikely to result from a tube rupture, if the resulting pressure on the low-pressure side, including upstream and downstream systems, does not exceed the corrected hydrostatic test pressure Appropriate design options to be considered for protecting the low pressure side equipment and piping from potential tube rupture are: 1) Install a relief device (pressure relief valve or rup- 5-3 The failure positions of instruments and control valves must be carefully evaluated In practice, the control valve may not fail in the desired position A valve may stick in the wrong position, or a control loop may fail Relief protection for these factors must be provided Relief valve sizing requirements for these conditions should be based on flow coefficients (manufacturer data) and pressure differentials for the specific control valves and the facility involved Credit can be taken for some downstream flow paths, if ensured to be open throughout the relief event No favorable control valve action may be assumed In addition, the relief load determination should take into account that the liquid level in the upstream vessel may be lost, causing gas blow-by through the open control valve ISO 23251 (API Std 521) describes several relief scenarios that consider the position of a control valve and its bypass valve If during operation, the bypass valve may be opened to provide additional flow, then the total maximum flow (control valve wide open, plus bypass valve at some position, depending on the service and facility practices, must be considered when determining the relief load If the bypass is opened only during maintenance, when the control valve is blocked in after switchover, then a design based on the maximum flow through either the control valve, or the bypass valve, whichever is greater, may be considered In this case the system must be evaluated during the facility hazard review to ensure that the proper administrative controls are in place to prevent a situation in which both the control valve and the bypass are open simultaneously Thermal Expansion If isolation of a process line on the cold side of an exchanger can result in excess pressure due to heat input from the warm side, then the line or cold side of the exchanger should be protected by a relief valve If any equipment item or line can be isolated while full of liquid, a relief valve should be provided for thermal expansion of the contained liquid Low process temperatures, solar radiation, heat tracing, or changes in atmospheric temperature can necessitate thermal overpressure protection Flashing across the relief valve needs to be consid- spection practices for critical check valves, when relief protection is required, and recommended practices for determining the controlling relief rate ered Administrative controls for block valves around heat exchanger are discussed in ASME Section VIII, Appendix M As a practical manner, thermal relief valves are not installed in all instances where piping systems may be blocked in by two valves The decision to install a thermal relief valve for piping systems is typically based on the following factors: length and size of piping, vapor pressure of the fluid at the elevated temperature possible, volatility and/or toxicity of the fluid, potential for valve leakage (metal vs soft seated valves), and the presence of automatic shut down valves in the system It is common to provide thermal relief valves for cryogenic liquid applications Guidance for when to specify thermal relief and for sizing of the valve are provided in ISO 23251 (API Std 521) A sizing equation for a simple thermal relief valve is given later in this chapter A 19 mm × 25 mm relief valve is commonly used for liquid filled, non-flashing piping systems containing non-cryogenic liquids Reflux Failure and/or Loss of Overhead Cooling For Fractionators The failure of electrical or mechanical equipment that provides cooling or condensation in process streams can cause overpressure in fractionators and process vessels The evaluation of relief scenarios for towers, in order to determine the appropriate load for the relief device, is complex Various simplified approaches have been used in the past, however the most common method used today is a modified steady state material balance at relief conditions, as described by Nezami.11 Dynamic simulation may also be applied to evaluate the tower relief load vs time Care should be exercised when using the dynamic approach since the results can be highly dependent on the specific assumptions used, and may not be conservative Utility Failure Abnormal Heat Input Loss of cooling water may occur on an area-wide or plantwide basis Commonly affected are fractionating columns and other equipment utilizing water cooling Cooling water failure must be considered for individual relief devices In addition, it is often the governing case in sizing flare systems Reboilers and other process heating equipment are designed with a specified heat input When they are new or recently cleaned, and/or due to loss of control, additional heat input above the normal design can occur In the event of a failure of temperature control, vapor generation can exceed the process system’s ability to condense or otherwise absorb the build-up of pressure, which may include non-condensables generated by overheating The system should be evaluated at the relief condition using a modified material balance approach Electric power failure, similar to cooling water failure, may occur on an area-wide or plant-wide basis and may have a variety of effects Since electric pump and air cooler fan drives are often employed in process units, a power failure may cause the immediate loss of reflux to fractionators Motor driven compressors will also shut down Power failures may result in major device and flare system relief loads Process Upset Instrument air system failure, whether related to electric power failure or not, must be considered in sizing of the flare system since pneumatic control loops will be interrupted Also control valves will assume the position as specified on “loss of air” and the resulting effect on the flare system must be considered The source of a process upset can vary depending of the application Therefore this contingency must be analyzed individually based on the specific circumstances For example, guidance for fractionation towers is included in reference 11 Fans on air cooled heat exchangers or cooling towers occasionally become inoperative because of a loss of power or a mechanical breakdown On cooling towers and on air cooled exchangers where independent operation of the louvers can be maintained, credit may be taken for the cooling effect obtained by convection and radiation in still air at ambient conditions Vessels are subject to overfilling and must be protected from overpressure from that source The cause can be an loss of control on the inlet, or a failure of the controls or pump on the outlet Liquid Overfilling of a Vessel Transients Transient pressure surges can occur as a result of liquid hammer, steam hammer, or steam condensate induced hammer, A pressure relief valve is normally not effective as a protective device for these causes of overpressure, so the focus should be on avoiding transient pressure surges through design and operation, and/or the use of a surge suppressor device Check Valve Failure Failure of a check valve to close must be considered A single check valve is not an effective means for preventing overpressure by reverse flow from a high-pressure source In most cases, focus should be on prevention of reverse flow It is important to note that, in addition to overpressure of the upstream system, reverse flow through machinery can destroy rotating equipment, causing loss of containment If this hazard is of concern, additional means of backflow prevention should be provided (i.e emergency shut down inter-lock and valve) Vacuum Protection Vessels may be subject to (partial) vacuum from liquid pump out, condensation of volatiles, or other causes Typically, industry practices for vessels containing hydrocarbons is to design for the maximum possible vacuum In some services (i.e., very large low design pressure vessels) alternate vacuum protection is generally necessary For relief purposes, a single check valve is treated as if it is not there, unless specific maintenance and inspection practices are adhered to Two check valves in series reduce the likelihood, and potential magnitude of reverse flow, but over-pressuring of the low pressure side can still take place due to even small check valve leaks, assuming the pressure is high enough ISO 23251 (API Std 521) provides specific guidance both on how to treat check valve failure as a relief scenario, maintenance/in- Relief Scenarios For Specific Equipment Types The following equipment considerations should be followed for relief system design 5-4 (API Std 2000), which sets thermal breathing rates, and fire relief rules for this equipment Note that the fire sizing equations for low pressure equipment covered by ISO 28300 (API Std 2000) differ from those in ISO 23251 (API Std 521) Centrifugal Compressors — Centrifugal compressor systems should be analyzed in order to properly understand the maximum pressure that can occur, and required relief protection (if any) for each part of the system, during operation (normal and upset), start-up, and at shutdown, based on the normal and maximum suction, and/or discharge conditions The maximum settle out pressure for each portion of the system should be calculated based on the configuration of the recycle valves, check valve, seal balance line, and the volumes of the drums, piping and coolers At compressor shutdown, the pressure in one portion of the system may temporarily rise to a higher pressure than the overall final settle out pressure At a minimum, design of overpressure protection for tanks should consider: liquid movement into the tank, tank breathing due to weather changes that heat the tank, inert gas pad and/or purge regulator failure, internal and external heat transfer devices, failure of vent collection systems, utility failure, blow-through of gas from a higher pressure source, composition changes, cooling failure upstream of the tank, fire, and overfilling At a minimum, design of vacuum protection for tanks should consider: liquid movement out of the tank due to pump transfer, liquid movement out of the tank due to opening of a drain valve, tank breathing due to weather changes that cool the tank, failure of inert pads, utility failures Reciprocating Compressors — Each positive displacement compressor must have a relief valve on the discharge upstream of the block and check valves in order to protect the compressor and downstream equipment Commonly, relief valves are also provided on each individual stage to protect the interstage equipment Reciprocating compressor systems should be analyzed in order to properly understand the maximum pressure that can occur, and required relief protection for each part of the system, during operation (normal and upset), start-up, and at shutdown, based on the normal and maximum suction, and/or discharge conditions SPECIAL RELIEF SYSTEM CONSIDERATIONS Administrative Controls Administrative controls are procedures that, in combination with mechanical locking elements, are intended to ensure that personnel actions not compromise the overpressure protection of the equipment They include, as a minimum, documented operation and maintenance procedures, and training of operator and maintenance personnel in these procedures [ASME Boiler & Pressure Vessel Code Section VIII, Appendix M] Fired Heaters — General best practice is to design fired heaters such that the process side cannot be blocked in Typically, the heater control system will shut down the heater in case of loss of flow on the process side, but the safety integrity level (SIL) may be inadequate to avoid overpressure If there is a possibility that the process side of a fired heater may be blocked in, then a relief valve should be provided to protect the heater The relief valve should be installed on the downstream of the heater to help ensure flow through the heater upon blocked outlet Block Valves in the Relief Path ASME Section VIII, Appendix M, provides requirements, including specific administrative controls, for block valves associated with the inlet and outlet of pressure relief devices, block valves around equipment, such as heat exchangers, which may be isolated and drained for maintenance, and block valves between two pieces of equipment protected by a single relief device Pumps — Relief valves are required on the discharge of each positive displacement pump Normally, these relief valves are piped back to the source vessel In some instances, the relief device discharge can be returned to the suction line, depending on the service and extent of heat up due to recycle In either installation, the pressure present at the discharge of the pressure relief valve must be considered in determining the set pressure of a conventional pressure relief valve Isolation valves around the pressure relief valves may not be required, if the recycle is to the suction line and the pump itself can be isolated for maintenance Many small metering pumps will have built-in internal relief protection As these internal reliefs are typically not identified in facility documentation (e.g., P&IDs, critical device lists, etc.), they are typically not tested or maintained For this reason, they generally should not be relied upon as a means to prevent overpressure High Integrity Protection Systems (HIPS) A High Integrity Protection System (HIPS) is an instrumented system that has multiple redundancies to ensure the system is reliable and will react with desired effects as close to 100% of the time as possible As part of this, the instruments and valves, and the safeguarding system, are rated and maintained to a stricter standard than most instruments These systems are even on a different control system The instruments have a Safety Instrument Level (SIL); the higher the level the more reliable the system HIPS are typically used to mitigate flare loads that otherwise would become excessively large, or where a pressure relief valve would not adequately protect the system See Section of the Data Book for more information on High Integrity Protection Systems (HIPS) Atmospheric Storage Tanks, and Low Pressure Tanks — Atmospheric storage tanks are typically protected against overpressure and vacuum due to process conditions and atmospheric changes In addition, relief protection for fire and other upset conditions is required Tanks are commonly protected by weighted or spring loaded pallet operated relief devices (conservation vents) A pilot-operated pressure relief can also be utilized Storage tanks with diameters of 15 m or larger may be fitted with a frangible roof (weak roof to shell attachment which will fail upon overpressure); such a roof-to-shell joint serves as emergency pressure relief device in lieu of a separate fire relief valve valve (See API Std 650) All other tanks require fire overpressure protection by an emergency relief vent In some very limited instances (i.e loss of control for an inlet valve downstream of a large packed pipeline upstream of a treating facility, or protection against runaway reaction,) a High Integrity Protection System may be considered to replace the requirement for a pressure relief device This is now recognized by ASME Section VIII, Division (UG-140),15 with a number of requirements including: • The user shall ensure that the MAWP of the vessel is greater than the highest pressure that can reasonably be expected to be achieved by the system The user shall conduct a detailed analysis of all credible overpressure scenarios Pressure relief requirements and relief device sizing for atmospheric tanks and any tanks, vessels, or other equipment designed for less than 103 kPa (ga), are covered by ISO 28300 5-5 Low Temperature Flaring • This analysis shall utilize an organized, systematic process safety analysis approach such as: a Hazards and Operability (HAZOP) review; a failure mode, effects and criticality analysis (FMECA); fault tree analysis; event tree analysis; what-if analysis, or other similar methodology Natural gas plants frequently have more than one flare system (i.e high pressure flare, low pressure flare, cryogenic flare) The segregation of flare systems should be carefully evaluated, based on the fluid compositions, temperatures, and allowable back pressures in the relief header Several incidents have raised industry awareness on the need to properly consider segregation of flare headers and systems • Instrumentation associated with a HIPS shall be tested at regular intervals to ensure it functions per design • Documentation of the HIPS system design and testing shall be developed and maintained When low temperature streams are relieved, the flare system piping and equipment exposed to cryogenic temperature may require stainless steel or other acceptable alloys The system should be designed for the coldest process stream to be relieved including the cooling effect of the expanding fluid (JouleThomson effect) Materials selection should be made according to applicable code recommendations The user shall consult ASME Section VIII, Division (UG140) for the complete set of requirements for the use of HIPS as a means of overpressure protection Emergency Depressuring Emergency depressuring system are commonly used in natural gas facilities The system can be automatically actuated or operator actuated, on emergency shutdown of a piece of equipment, a process unit, or an entire facility The purpose of the depressurization system is one or more of the following: 1) minimize risk of loss of containment due to fire/runaway reaction for pressure vessels, 2) minimize risk of fire, explosion, or release of toxic gas due to partial loss of containment (e.g., piping or flange leak), or 3) minimize risk of fire, explosion, or release of toxic gas due to partial or total seal/packing failure of rotating equipment Industry experience has shown that formation of limited quantity of hydrates at a relief valve outlet can typically be handled safely However, relieving large amounts of hydrates, or solid CO2/H2S/ methane solids to a closed flare system should be avoided Industry experience has shown that pure CO2 can be safely vented to the atmosphere, utilizing proper design practices SET PRESSURE FOR PRESSURE RELIEF VALVES Fig 5-2, extracted from ISO 23251 (API Std 521), shows the characteristics of safety relief valves for vessel protection It can be used as a general guide in determining the proper set pressure of a pressure relief valve, for a protected system Refer to the Standard for further guidance on setting single or multiple pressure relief valves Depressurization systems are often used to prevent potential stress rupture of a vessel when the metal temperature is raised above the design temperature due to an abnormal heat source This source is usually from a fire, but could also be from a runaway exothermic reaction or other source of heat This type of rupture can occur before a vessel reaches the set pressure of relief devices on the vessel A general guideline is that a depressurization system should be able to reduce the pressure in the vessel to 50% of the design pressure in 15 minutes in the event of a pool fire However, the required depressurization time is dependent on the vessel material and wall thickness A detailed discussion of emergency depressurization design basis is provided in ISO 23251 (API Std 521) RELIEVING DEVICES Several pressure relief devices are certified and approved under Section VIII of the ASME Boiler and Pressure Vessel Code covering unfired pressure vessels They include spring loaded direct-acting pressure relief valves, pilot operated pressure relief valves, and rupture disks and shearing pin devices When the governing code is ANSI B31.3 or ANSI B31.8, other types of pressure relieving devices such as monitoring regulators, series regulators, weight-loaded relief valves, liquid seals, etc are permitted The discussion below is limited to ASME, Section VIII, devices The devices must be compatible with the service and the overall design of the system See ASME, Section I, for fired boiler relieving criteria Another application for a depressurization system is to reduce the consequences of a leak by quickly reducing the pressure of the system/plant/compressor By reducing the equipment pressure, both the leak rate and the total inventory of fluid leaked can be reduced A general criterion for system depressurization is to reduce the pressure in the system to 690 kPa (ga) in fifteen minutes or less Conventional Pressure Relief Valves For compressors, the depressurization time is partially a function of the location of the machine, and de-pressurization times of less than 15 minutes is often used For compressors located in buildings, a depressurization time of 3-5 minutes to near atmospheric pressure are not uncommon In a conventional pressure relief valve, the inlet pressure to the valve is directly opposed by a spring Tension on the spring is set to keep the valve shut at normal operating pressure but allow the valve to open when the pressure reaches relieving conditions This is a differential pressure valve Most conventional safety-relief valves available to the petroleum industry have disks which have a greater area, AD, than the nozzle seat area, AN The effect of back pressure on such valves is illustrated in Fig 5-3b If the bonnet is vented to atmospheric pressure, the back pressure acts with the vessel pressure so as to overcome the spring force, FS, thus making the relieving pressure less than when set with atmospheric pressure on the outlet However, if the spring bonnet is vented to the valve discharge rather than to the atmosphere, the back pressure acts with the For each application, the designer must verify that all components (especially vessel internals and machinery elastomer seals) can withstand the chosen de-pressurization rate In addition, cold metal temperatures can be developed both in the source vessel and the flare system during de-pressuring Both systems must be designed for these conditions Note that the ASME Pressure Vessel Section VIII code requires a pressure relief device or HIPS to be installed to protect the vessel even if a depressuring system is used 5-6 A typical pilot operated relief valve is shown in Fig. 5-5 Pilot operated valves may be used in liquid or vapor services These valves contain nonmetallic components (elastomers), therefore fluid pressure and temperature, fluid characteristics, polymerization, fouling, solids, and corrosion can limit their use spring pressure so as to increase the opening pressure If the back pressure were constant, it could be taken into account in adjusting the set pressure In operation the back pressure is not constant when a number of valves discharge into a manifold A cut-away of a conventional relief valve is shown in Fig 53a Materials of construction for relief valves vary by service Pilot operated valves are available with snap-action or modulating action The modulating type relieves only the amount of fluid required to control the overpressure Balanced Pressure Relief Valves Balanced safety-relief valves incorporate means for minimizing the effect of back pressure on the performance characteristics — opening pressure, closing pressure, lift, and relieving capacity When specifying pilot operated pressure relief valves, the elastomers chosen for the o-rings, and seals should be carefully considered Temperature (maximum and minimum), chemical compatibility (for the principle and trace components, and for potential liquid carryover), and resistance to explosive de-compression, are all factors in the choice of elastomers These valves are of two types, the piston type and the bellows type A cross section drawing of a balanced (bellows) relief valve is shown in Fig 5-4a In the piston type, of which several variations are manufactured, the guide is vented so that the back pressure on opposing faces of the valve disk cancels itself; the top face of the piston, which has the same area, AP, as the nozzle seat area, AN, is subjected to atmospheric pressure by venting the bonnet The bonnet-vented gases from balanced piston-type valves should be disposed of with a minimum restriction and in a safe manner eat Leakage, and Resilient S Pressure Seat Relief Valves Some leakage can be expected through the seats of with metal-to-metal seated, conventional or balanced type relief valves, when the operating pressure rises too close to the set pressure Allowable seat leakage rates are specified in API Std 527.16 Resilient seat pressure relief valves (see Fig 5-6), with either an O-ring seat seal or a plastic seat, can provide seat integrities which are significantly higher than metal seated valves API Std 52716 specifies that, soft seated, pressure relief valves shall have zero bubbles/minute leakage at the same test pressures as metal seated valves This can allow bubble tight operation to 90%, of the set pressure, or higher. Proper elastomer choice is critical for resilient seat pressure relief valves In the bellows type of balanced valve, the effective bellows area, AB, is the same as the nozzle seat area, AN, and, by attachment to the valve body, excludes the back pressure from acting on the top side of that area of the disk The disk area extending beyond the bellows and seat area cancel, so that there are no unbalanced forces under any downstream pressure The bellows covers the disk guide so as to exclude the working fluid from the bonnet To provide for a possible bellows failure or leak, the bonnet must be vented separately from the discharge The balanced safety-relief valve makes higher pressures in the relief discharge manifolds possible Balanced-type valves should have bonnet vents large enough to assure no appreciable back pressure during design flow conditions If the valve is in a location in which atmospheric venting (usually not a large amount) presents a hazard, the vent should be piped to a safe location independent of the valve discharge system The user should obtain performance data on the specific type of valve being considered A diagram of the force balance for piston and bellows balanced pressure relief valves is shown in Fig 5-4b Vapor Trim vs Liquid Trim For Pressure Relief Valves Pressure relief valves handling gas or vapor are supplied with vapor trim Valves which releive liquid, two-phase, or potentially two-phase fluids, require a liquid trim It is important that the supplier is properly informed of the full range of expected operation when procuring pressure relief valves In addition, liquid trim pressure relief valves have a significantly higher blowdown as compared to vapor trim In these applications the designer must be prudent to allow sufficient pressure margin between the operating pressure and the relief valve set pressure to ensure reclosure of the valve following a relief event Pilot Operated Pressure Relief Valves Rupture Disk A pilot operated pressure relief valve consists of two principal parts, a main valve and a pilot The valve utilizes a piston instead of a shaft Inlet pressure is directed to the top of the main valve piston More area is exposed to pressure on the top of the piston than on the bottom so pressure, instead of a spring, holds the main valve closed At the set pressure, the pilot opens, reducing the pressure on top of the piston thereby allowing the main valve to open fully For some applications, pilot-operated relief valves are available in minimum friction, light-weight diaphragm construction (in place of heavy pistons) A rupture disk consists of a thin diaphragm held between flanges The disk is designed to rupture and relieve pressure within tolerances established by ASME Code Section VIII Rupture disks can be used in gas processing plants, upstream of relief valves, to reduce minor leakage and valve deterioration In these installations, the pressure in the cavity between the rupture disk and the relief valve should be monitored to detect a ruptured or leaking disk In some applications a rupture disk with a higher pressure rating is installed in parallel to a relief valve Pilot operated valves can allow backflow if downstream pressure exceeds set points Backflow prevention is required on valves, connected to common relief headers, where protected equipment can be depressured and isolated while connected to an active flare header, where a vacuum could occur at the inlet, or where the downstream is connected to a system or vessel where the pressure could exceed the inlet pressure Rupture disks should be used as the primary relieving device only if using a pressure relief valve is not practical Some examples of such situations are: (a) Rapid rates of pressure rise A pressure relief valve system does not react fast enough or cannot be made large enough to prevent overpressure (e.g., an exchanger ruptured tube case or a runaway reaction in a vessel) A check valve, split piston type valve, or backflow preventer in the pilot line can be used 5-7 (b) Large relieving area required Because of extremely high flow rates and/or low relieving pressure, providing the required relieving area with a pressure relief valve system is not practical flow at the desired pressure rather than at a pressure higher or lower than the stamped pressure A rupture disk is subject to fatigue failure due to operating pressure cycles To establish recommended replacement intervals, consult rupture disk suppliers (c) A pressure relief valve system is susceptible to being plugged, and thus inoperable, during service Shearing Pin Device (Rupture Pin) All rupture disks have a manufacturing design range (MDR), which essentially specifies the user’s tolerancefor variations in the burst pressure Furthermore, disk temperature can have a significant affect on the pressure at which the disk will open Therefore, it is essential that the designer communicate the desired MDR and the full range of expected operating and relief temperatures when specifying requirements for a rupture disk This will help ensure that the disk ruptures and provides relief A shearing pin device is a non-closing pressure relief-device actuated by differential pressure, or static inlet pressure, designed to function by the shearing of a load-carrying member that supports a pressure-containing member The devices are sanctioned by ASME Section VIII, and may be used for circumstances where rupture disks may also be appropriate They have the advantage that the pin can be replaced without removing a piping flange FIG 5-2 Pressure Level Relationships for Pressure Relief Valves14 Courtesy American Petroleum Institute 5-8 FIG 5-4a FIG 5-3a Balanced Bellows Pressure Relief Valve14 14 Conventional Pressure Relief Valve Courtesy of American Petroleum Institute Courtesy of American Petroleum Institute FIG 5-3b Effect of Back Pressure for Conventional Pressure Relief Valve14 FIG 5-4b Effect of Back Pressure on Set Pressure of Balanced Pressure Relief Valve14 Courtesy of American Petroleum Institute Courtesy of American Petroleum Institute 5-9 FIG 5-6 FIG 5-5 O-Ring Seals — For Conventional and Bellows Pressure Relief Valves Pilot Operated Pressure Relief Valve14 Courtesy of American Petroleum Institute DISC RETAINING RING DISC RETAINER SCREW O-RING SEAT SEAL O-RING RETAINER Courtesy Lonergan Company 5-10 Sizing for Liquid Relief Turbulent Flow — Conventional and balanced bellows relief valves in liquid service may be sized by use of Equation 58.14 Pilot-operated relief valves should be used in liquid service only when the manufacturer has approved the specific application A = (7.07) (Vl) √ G (Kd) (Kc) (Kw) (Kv) √ (P1 – Pb) Eq 5-8 Laminar Flow — For liquid flow with Reynolds numbers less than 4,000, the valve should be sized first with Kv = in order to obtain a preliminary required discharge area, A From manufacturer standard orifice sizes, the next larger orifice size, A´, should be used in determining the Reynolds number, Re, from the following relationship:14 (Vl) (112 654) (G) Re = Eq 5-9 µ √ A´ (511 300) • (l/s) Re = µ √ A´ determined for the geographic area and applied to the surface area to approximate Q (W) When the flow rate is calculated, the necessary area for relief may be found from the turbulent liquid flow equations Sizing a Pressure Relief Device for Two Phase Flow For two phase fluids and flashing liquids, a choking phenomenon limits the flow through the pressure relief valve nozzle, in a manner similar to the choking of a gas in critical flow In order to estimate the relief capacity of a nozzle, it is necessary to estimate the choking pressure and then determine the two phase physical properties at these conditions The historical method of calculating areas for liquid and vapor relief separately, and then adding the two areas together to get the total orifice size does not produce a conservative relief device size Improved sizing methods have been developed using the following assumptions: • The fluid is in thermodynamic equilibrium through the nozzle Eq 5-10 S After the Reynolds number is determined, the factor Kv is obtained from Fig. 5-15 Divide the preliminary area (A´) by Kv to obtain an area corrected for viscosity If the corrected area exceeds the standard orifice area chosen, repeat the procedure using the next larger standard orifice Sizing for Thermal Relief The following may be used to approximate relieving rates of liquids expanded by thermal forces where no vapor is generated at relief valve setting and maximum temperature These calculations assume the liquid is non-compressible.13 (B) (Q) Vl = 1000 • (G) (S) Eq 5-11 Typical values of the liquid expansion coefficient, B, at 15°C are: API Gravity Relative Density, G Liquid Expansion Coefficient, B, 1/°C Water 1.000 0.00018 - 34.9 1.052 - 0.850 0.00072 35 - 50.9 0.850 - 0.775 0.0009 51 - 63.9 0.775 - 0.724 0.00108 64 - 78.9 0.724 - 0.672 0.00126 79 - 88.9 0.672 - 0.642 0.00144 89 - 93.9 0.642 - 0.628 0.00153 94 - 100 0.628 - 0.611 0.00162 n-Butane 0.584 0.0020 Isobutane 0.563 0.0022 Propane 0.507 0.0029 For heating by atmospheric conditions, such as solar radiation, the surface area of the item or line in question should be calculated Solar radiation [typically 787–1040 W/m2] should be • The overall fluid is well mixed and can be represented by weighted averaging the gas and liquid densities (this is sometimes referred to as the non-slip assumption) Use of these assumptions has been found to produce a result which in most instances is close to the real flow rate through the nozzle, and which almost always will result in a conservative calculation of the required nozzle area However, these methods require additional equilibrium data along the isentropic expansion path through the relief valve Refer to API Std 520, Part 1, for a description of the sizing methods for two-phase liquid vapor relief Two methods are described in API Std 520, Part 1, Annex C; the Omega method and the Mass FluxIsentropic Expansion Method.14 izing for Fire for Partially S Liquid Filled Systems The method of calculating the relief rate for fire sizing may be obtained from ISO 23251 (API Std 521), API Standard 2510, NFPA 58, and possibly other local codes or standards Each of these references approach the problem in a slightly different manner Note that NFPA-58 applies only to U.S marine terminals, or U.S terminals at the end of DOT regulated pipelines Most systems requiring fire relief will contain liquids and/or liquids in equilibrium with vapor Fire relief capacity in this situation is equal to the amount of vaporized liquid generated from the heat energy released from the fire and absorbed by the liquid containing vessel The difficult part of this procedure is the determination of heat absorbed Several methods are available, including ISO/API, and U.S National Fire Protection Association ISO 23251 (API Std 521) applies to the Petroleum and Natural Gas Industries, and is the standard most commonly used to assess fire heat load in these services ISO 23251/API Std 52113 expresses relief requirements in terms of heat input from the fire to a vessel containing liquids, where adequate drainage and fire fighting equipment exist Q = (43 200) (F) (Aw)0.82 Eq 5-12 The environment factor, F, in Equation 5-12 is determined from Fig 5-16 Credit for insulation can be taken only if the insulation system can withstand the fire and the impact of water 5-12 from a fire hose Specific criteria are provided in ISO 23251/ API Std 521 The appropriate equation to use where adequate drainage and fire fighting equipment not exist is also provided in this Standard configuration, and location of the relief device For many gas plant applications, the assumption of single phase vapor relief is adequate for pressure relief valve sizing See ISO 23251 (API Std 521) for further guidance Awin equation 5-12 is the total wetted surface, in square meters Wetted surface is the surface wetted by liquid when the vessel is filled to the maximum operating level It includes at least that portion of a vessel within a height of m above grade In the case of spheres and spheroids, the term applies to that portion of the vessel up to the elevation of its maximum horizontal diameter or a height of m, whichever is greater Grade usually refers to ground grade but may be any level at which a sizable area of exposed flammable liquid may be present Sizing for Fire For Supercritical Fluids Sometimes, the phase condition at the relieving pressure and temperature will be supercritical API recommends to consider a dynamic approach where the vessel contents are assumed to be single phase (supercritical), and a step by step heat flux is applied to the vessel walls [See ISO 23251 (API Std 521),] and Ouderkirk10 for details The same methodology can also be applied for gas filled systems Heavy hydrocarbons can be assumed to crack (i.e., to thermally decompose), and it is the user’s responsibility to estimate the effective or equivalent latent heat for these applications Traditionally, a minimum latent heat value of 116 kJ/kg has been used if the conditions can not be quantified The amount of vapor generated is calculated from the latent heat of the material at the relieving pressure of the valve For fire relief only, this may be calculated at 121% of maximum allowable working pressure All other conditions must be calculated at 110% of maximum allowable working pressure for single relief devices When a vessel is subjected to fire temperatures, the resulting metal temperature may greatly reduce the pressure rating of the vessel, in particular for vessels in vapor service Design for this situation should consider an emergency depressuring system and/or a water spray system to keep metal temperatures cooler For additional discussion on temperatures and flow rates due to depressurization and fires refer to Reference Latent heat data may be obtained by performing flash calculations Mixed hydrocarbons will boil over a temperature range depending on the liquid composition; therefore, consideration must be given to the condition on the batch distillation curve which will cause the largest relief valve orifice area requirements due to the heat input of a fire Generally the calculation is continued until some fraction of the fluid is boiled off Other dynamic simulation methods are also available The latent heat of pure and some mixed paraffin hydrocarbon materials may be estimated using Fig A.1 of ISO 23251 / API Std 521.13 RELIEF VALVE INSTALLATION Relief valve installation requires careful consideration of inlet piping, pressure sensing lines (where used), and startup procedures Poor installation may render the safety relief valve inoperable or severely restrict the valve’s relieving capacity Either condition compromises the safety of the facility Many relief valve installations have block valves before and after the relief valve for in-service testing or removal; however, these block valves must be sealed or locked open, and administrative controls must be in place, to prevent inadvertent closure When the latent heat is determined, required relieving capacity may be found by:13 W = Q / Hl Eq 5-13 The value W is used to size the relief valve orifice using Equation 5-1 or Equation 5-4 For vessels containing only vapor, ISO 23251 (API Std 521)13 has recommended the following equation for determining required relief area based on fire: 183.3 (F´) (A3) A = √ P1 Inlet Piping The proper design of inlet piping to safety relief valves is extremely important Relief valves should not be installed at physically convenient locations unless inlet pressure losses are given careful consideration The ideal location is the direct connection to protected equipment to minimize inlet losses API STD 520, Part II recommends a maximum non-recoverable pressure loss to a relief valve of three percent of set pressure, except for remote sensing pilot-operated pressure relief valves This pressure loss shall be the total of the inlet loss, line loss, and the block valve loss (if used) The loss should be calculated using the maximum rated flow through the safety relief valve Eq 5-14 F´ can be determined using Equation 5-15.13 If the result is less than 0.01, then use F´ = 0.01 If insufficient information is available to use Equation 5-15, then use F´ = 0.045 F´ 0.1406 = (C1) (Kd) (Tw – T1) T10.6506 1.25 Eq 5-15 To take credit for insulation, ISO 23251 (API Std 521) requires the insulation material to function effectively at temperatures of 900°C, and to retain its shape, and most of its integrity in covering the vessel in a fire, and during fire fighting Typically, this requires proper insulation, plus an insulation jacket constructed of a suitable material, and banding that can withstand the fire conditions However, other systems may be able to meet these requirements Discharge Piping and Backpressure Proper discharge and relief header piping size is critical for the functioning of a pressure relief valve Inadequate piping can result in reduced relief valve capacity, cause unstable operation, and/or, relief device damage The pressure existing at the outlet of a pressure relief valve is defined as backpressure Backpressure which is present at the outlet of a pressure relief valve, when it is required to operate, is defined as superimposed backpressure Backpressure which develops in the discharge system, after the pressure relief valve opens, is built-up backpressure The magnitude of pressure which exists at the outlet of the pressure relief valve, Sizing for Fire for Liquid Full or Nearly Full Equipment For totally or near totally liquid filled systems, the controlling relief condition can be single vapor phase, liquid phase, or two phase, depending on the fluid, liquid level, vessel size and 5-13 FIG 5-7 API Pressure Relief Valve Designations Standard Orifice Designation Orifice Area cm2 Orifice Area (in.2) D 0.710 0.110 • • • E 1.265 0.196 • • • • • • F 1.981 0.307 G 3.245 0.503 • • H 5.065 0.785 • • J 8.303 1.287 K 11.858 1.838 • L 18.406 2.853 • M 23.226 3.60 • N 28.000 4.34 • P 41.161 6.38 • Q 71.290 11.05 • R 103.226 16.0 • • T 167.742 26.0 in 1ì2 1.5 × 1.5 × mm 25 × 50 38 × 50 38 × 75 2×3 3×4 3×6 4×6 6×8 × 10 × 10 50 × 75 75 × 100 75 × 150 100 × 150 150 × 200 150 × 250 200 × 250 Valve Body Size (Inlet Diameter times Outlet Diameter) FIG 5-9 Values of C1 for Various Gases FIG 5-8 Acetylene Air Ammonia Argon Benzene Carbon disulfide Carbon dioxide Carbon monoxide Chlorine Cyclohexane Ethane Ethylene Helium Hexane Hydrochloric acid Hydrogen Hydrogen sulfide Iso-butane Methane Methyl alcohol Methyl chloride N-butane Natural gas Nitrogen Oxygen Pentane Propane Sulfur dioxide Values of Coefficient C1 vs k k 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0 2.1 2.2 C1 216.9274 238.8252 257.7858 274.5192 289.494 303.0392 315.37* 326.7473 337.2362 346.9764 356.0604 364.5641 372.5513 380.0755 387.1823 393.9112 400.2962 406.3669 412.1494 *Interpolated values since C1 becomes indeterminate as k approaches 1.00 Note: Calculated from Eq 5-3 5-14 Mol mass 26 29 17 40 78 76 44 28 71 84 30 28 4 86 36.5 34 58 16 32 50.5 58 19 28 32 72 44 64 k 1.28 1.40 1.33 1.66 1.10 1.21 1.28 1.40 1.36 1.08 1.22 1.20 1.66 1.08 1.40 1.40 1.32 1.11 1.30 1.20 1.20 1.11 1.27 1.40 1.40 1.09 1.14 1.26 C1 345 356 351 377 327 338 345 356 352 324 339 337 377 324 356 356 348 328 346 337 337 328 345 356 356 325 331 342 FIG 5-10 Back Pressure Correction Factor, Kb, for Conventional Pressure Relief Valves (Vapors and Gases)14 Courtesy American Petroleum Institute FIG 5-11 Back-Pressure Correction Factor, Kb, for Balanced Bellows Pressure Relief Valves (Vapors and Gases)14 Note: The above curves represent a compromise of the values recommended by a number of relief valve manufacturers and may be used when the make of valve or the actual critical-flow pressure point for the vapor or gas is unknown When the make is known, the manufacturer should be consulted for the correction factor These curves are for set pressures of 350 kPa gauge and above They are limited to back pressure below critical-flow pressure for a given set pressure For subcritical-flow back pressures below 350 kPa gauge, the manufacturer must be consulted for the values of Kb Courtesy American Petroleum Institute 5-15 FIG 5-12 Values of F2 for Subcritical Flow14 Courtesy American Petroleum Institute FIG 5-13 Superheat Correction Factors for Pressure Relief Valves in Steam Service14 Set Pressure kPa (ga) Total Temperature Superheated Steam, °C 149 204 260 316 371 427 Correction Factor, Ksh 100 140 275 415 550 690 830 1 1 1 0.98 0.98 0.99 0.99 0.99 0.99 0.99 0.93 0.93 0.93 0.93 0.94 0.94 0.94 0.88 0.88 0.88 0.88 0.88 0.89 0.89 0.84 0.84 0.84 0.84 0.84 0.84 0.84 970 100 250 380 520 660 790 930 070 410 760 450 140 520 900 620 10 350 12 070 13 790 17 240 20 690 1 1 0.99 0.99 0.99 0.99 0.99 1 1 1 1 0.94 0.94 0.94 0.95 0.95 0.95 0.95 0.96 0.96 0.96 0.96 0.96 0.97 1 0.89 0.89 0.89 0.89 0.89 0.9 0.9 0.9 0.9 0.9 0.91 0.92 0.92 0.95 0.96 0.97 1 1 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.86 0.86 0.86 0.87 0.88 0.89 0.91 0.93 0.94 0.95 0.95 482 538 593 649 0.8 0.8 0.81 0.81 0.81 0.81 0.81 0.77 0.77 0.77 0.77 0.77 0.77 0.78 0.74 0.74 0.74 0.75 0.75 0.75 0.75 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.81 0.81 0.81 0.81 0.81 0.81 0.81 0.81 0.81 0.82 0.82 0.82 0.82 0.83 0.84 0.85 0.86 0.86 0.86 0.85 0.82 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.79 0.79 0.78 0.8 0.81 0.81 0.8 0.78 0.74 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.76 0.76 0.77 0.77 0.77 0.76 0.73 0.69 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.73 0.73 0.73 0.73 0.74 0.74 0.73 0.72 0.69 0.65 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.71 0.71 0.71 0.7 0.69 0.66 0.62 Courtesy American Petroleum Institute 5-16 FIG 5-14 Back-Pressure Sizing Correction Factor Kw for 25 Percent Overpressure on Balanced Bellows Pressure Relief Valves (Liquids Only)14 Note: The above curve represents a compromise of the values recommended by a number of relief-valve manufacturers This curve may be used when the make of the valve is not known When the make is known, the manufacturer should be consulted for the correction factor Courtesy American Petroleum Institute FIG 5-15 Capacity Correction Factor Due to Viscosity for Liquid Phase Pressure Relief14 Courtesy American Petroleum Institute 5-17 FIG 5-16 Fire Sizing Environmental Factors Environment1 Bare metal vessel Insulation Water-application facilities Depressuring facilities Underground storage Earth-covered storage F Factor 1.0 Note 1.0 1.0 0.0 0.03 Notes: See ISO 23251 (API Std 521) for appropriate use of these environmental factors See ISO 23251 (API Std 521) for the equations to use if insulation credit is taken after it is opened, is the total of the super imposed and built-up backpressure, and is commonly referred to a “total backpressure.” The total backpressure, for all pressure relief valve styles, can affect the capacity of the valve For gas service the capacity will be affected if the flow through the valve is sub-critical For liquid service the outlet backpressure will directly affect the capacity This is shown by Equations 5-2 through 5-10 For a conventional (spring loaded) pressure relief valve, super imposed backpressure at the outlet of the valve acts to hold the valve disc closed with a force additive to the spring force (see Fig 5-3b) The pressure relief valve set pressure is essentially increased by the amount of super imposed backpressure present Conventional spring loaded pressure relief valves exhibit unacceptable performance (unstable operation, and possible chatter), when excessive backpressure develops during a relief incident due to the flow through the valve and outlet piping For this reason API-520-1 specifies that the built-up backpressure for conventional pressure relief valves should not exceed 10% of the set pressure, at 10% allowable overpressure (process relief scenarios).14 Higher allowable built-up backpressure may be acceptable for other, allowable overpressures (see API-520-1 for specifics) A balanced pressure relief valve, Fig 5-4a and 5-4b, can be applied where the built-up backpressure is too high for a conventional pressure relief valve, and/or the superimposed or total backpressure is unacceptable for a conventional valve The balanced style can typically be used up to a total backpressure of 50% (consult with manufacturer for specific limits) The set pressure for a balanced pressure relief valve is not affected by superimposed backpressure The capacity of a balance pressure relief valve, however, can be affected by total backpressure, due to a reduction in lift caused by a closing force on the unbalance portion of the disk at high backpressure See Figs 5-11 and 5-14 for typical capacity correction factors for gas and liquid service for balanced pressure relief valve The lift and set pressure of pilot operated relief valves, where the pilot is vented to the atmosphere (typical configu- ration), are not affected by backpressure Therefore, for most applications the performance of pilot operating pressure relief valves it not affected by either superimposed or built-up backpressure The relief valve capacity can be affected if the flow becomes sub-critical for gases, or due to reduced pressure drop available for liquids In addition, if the discharge pressure can exceed the inlet pressure (e.g., tanks storing low vapor pressure material), a back-flow pre-venter is required for pilot operated pressure relief valve Pressure relief valve discharge piping must be at least the same diameter as the valve outlet, but generally must be larger to minimize backpressure Reactive Force On high pressure valves, the reactive forces during relief are substantial and external bracing may be required See equations in API RP 520-II for computing this force Rapid Cycling Rapid cycling can occur when the pressure at the valve inlet decreases at the start of relief valve flow because of excessive pressure loss in the piping to the valve, or excessive back-pressure Pressure relief valves are designed with a given blow-down (difference between the set pressure and closing pressure of a pressure relief valve), that is adjustable within limits Under conditions of high inlet loss, the valve may cycle at a rapid rate which is referred to as “chattering.” Rapid cycling reduces capacity and is destructive to the valve seat, subjects all the moving parts in the valve to excessive wear, and can induce potentially destructive vibration in the piping system The valve responds to the pressure at its inlet If the pressure decreases during flow to below the valve reseat point, the valve will close; however, as soon as the flow stops, the inlet pipe pressure loss becomes zero and the pressure at the valve inlet rises to relieving pressure once again If the vessel pressure is still equal to or greater than the relief valve set pressure, the valve will open and close again The mechanism of chatter is complicated and not uniquely associated with inlet pressure loss However, experience has shown that chattering can be prevented if the non-recoverable inlet pressure loss is limited to 3% of the set pressure Excessive back-pressure for conventional and balanced-bellows pressure relief valves can also cause chatter, and must be avoided An oversized relief valve may chatter since the valve may quickly relieve enough contained fluid to allow the vessel pressure to momentarily fall back to below set pressure only to rapidly increase again In some cases multiple relief valves, may be preferred, depending on the relief contingencies Resonant Chatter Resonant chatter can occur with pressure relief valves when the inlet piping produces excessive pressure losses at the valve inlet and the natural acoustical frequency of the inlet piping approaches the natural mechanical frequency of the valve’s basic moving parts The higher the set pressure, the larger the valve size, or the greater the inlet pipe pressure loss, the more likely resonant chatter will occur Resonant chatter is uncontrollable; that is, once started it cannot be stopped unless the pressure is removed from the valve inlet In actual application, however, the valve can self-destruct before a shutdown can take place because of the very large magnitude of the impact forces involved 5-18 DESIGN OF RELIEF SYSTEM TO FLARE Back Pressure Consideration Grouping of Systems The next step in the analysis involves setting a preliminary maximum back pressure for the system at various locations in the flare system, and choosing between conventional, pilot operated, or balanced pressure relief valves for the various relief stations A pressure relief device inventory should be prepared, summarizing set pressure, estimated relieving temperature, and approximate capacity, if available The flare style should be considered, as well as the maximum pressure expected at the flare base The first step in designing a flare system for a facility is to determine the number of segregated vent and flare headers, if more than one, which are required Depending on plot plan, the range of equipment design pressures, desirability of isolating certain streams, temperature of the relief streams, possibility of liquid carryover, heating value of the streams, and quantities of the relief streams, it may prove desirable to provide two or more segregated headers to the flare K.O drum, or even to use totally independent flare systems Separation of high pressure and low pressure headers, or low-temperature and wet headers, is not uncommon Some large integrated gas treating facilities have a high pressure, low pressure, and a cryogenic flare Pressure relief valves that can tolerate higher back pressure (e.g., balanced or pilot operated pressure relief valves) may be selected if the back pressure is too high for conventional pressure relief valves Excessive built-up back pressure will affect the operation of conventional pressure relief valves; high superimposed back pressure will affect the set point of these valves Load Determination Flare Header Sizing Methods The first step in determining controlling loads for a relief header and flare system is to identify the credible major flaring scenarios These scenarios may be associated with pressure relief, emergency depressuring, or transitory operating (e.g., startup, shutdown, etc.) events A case may be controlling because of the back-pressure it will generate in the relief header, the heat release at the flare stack, or the nature of the fluid to be flared (i.e low heating value, composition of the fluid, low temperature, high liquid flow rate, etc.) This analysis may include dividing the plant into fire zones (fire zone size is discussed in ISO 23251 (API Std 521), identifying large individual process relief loads, identifying common mode process failure loads, identifying common mode local or plant wide utility failure, identifying which process valves that discharge to the flare may already be open when an upset occurs (e.g., during startup or shutdown), identifying maximum depressurization rates, and identifying possible common events of pressure relief and venting or depressurization Line sizing for flare headers and relief lines requires the use of compressible flow equations Computer programs are normally used to size flare headers and to calculate the back pressure at the relief devices The header sizes are checked for the major relief scenarios and then fixed Based on these header sizes, each pressure relief device is checked for proper style, backpressure, and the effect of other devices on the set pressure and operation of the valve API RP 520-II requires that the pressure relief valve inlet and outlet piping be sized for the rated relief device capacity for all devices except modulating pilot operated relief valves, while header systems may be sized using the required capacity of the controlling scenario(s) A manual sizing method is outlined below: Start at the flare tip, where the outlet pressure is atmospheric, use design flows and work toward the individual relief valves (pressure drop across the tip will vary with the style of the flare and available system pressure drop – check with the tip manufacturer) Some favorable instrument response may be included in the design of flare systems ISO 23251 (API Std 521), Fifth Edition states, “Although favorable response of conventional instrumentation should not be assumed when sizing individual process equipment pressure relief, in the design of some components of a relieving system, such as the blow-down header, flare, and flare tip, favorable response of some instruments can be assumed.” In practice, the relief system design basis should be thoroughly analyzed using appropriate methodology (i.e layers of protection analysis, SIL review, quantitative method), before credit is taken The basis of the flare design load determination should be part of the plant formal hazard review Establish equivalent pipe lengths between points in the system and establish losses through fittings, expansion, and contraction losses Many users limit the maximum allowed velocity at any part of the flare system to Mach 0.7 This limit is intended to minimize the possible effects of acoustically or flow induced vibration on the piping in the flare system More detailed methods to evaluate these effects are presented in references and Estimate properties of gases in the headers from the following mixture relationships (i indicates the ith component) For gas plants, another key decision is whether to design the flare system for the maximum inlet flow of the production header or inlet pipeline, or instead rely on a shutdown system at the plant inlet, and/or an automatic or manual well shut-in Provisions also may be needed to allow venting some or all of the produced gas to the flare on facility start-up, pipeline depressurization, or during an emergency in one process unit MW = ∑ Wi / ∑ (W / MW)i Eq 5-16 T = ∑ Wi Ti / ∑ Wi Eq 5-17 µ xi µi (MW)i0.5 Flare Location = ∑ /∑ xi (MW)i0.5 Eq 5-18 Calculate the inlet pressure for each section of the line by adding the calculated pressure drop for that section to the known outlet pressure After the load is determined, it is necessary to decide on the location of the flares, and size of the headers and flare lines Location and height of the flares must consider flare stack height, thermal radiation, emissions during flaring, ground level concentrations in case of a flame-out, consequences of liquid carryover, and noise Frequently, the controlling criterion for flare location is the minimum distance to continuously operating equipment, which may require maintenance Calculate sections of pipe individually using the inlet pressure of a calculated section as the outlet pressure for the new section Continue calculations, working towards the relief valve or other flow source 5-19 Check calculated maximum superimposed backpressure, built-up backpressure, and total back pressure at the relief valve against piping design pressure and the maximum allowable back pressure (MABP) of the flow source See “Discharge Piping and Backpressure,” in this section for a definition of these terms, and API Std 520-I for maximum allowable values Adjust line size of headers until the calculated back pressure is less than both the MABP for each valve in the system and the design pressure of the associated piping The method outlined above employs sizing equations which assume isothermal flow in the flare header This is adequate for most uses; however, if the actual flow condition differs greatly from isothermal, the use of more complex equations and methods is required to predict pressure and more accurately and temperature profiles for the headers The choice of piping material other than carbon steel may be dictated by temperatures and pressures in some parts of the flare system Flare systems relieving fluids that produce cryogenic temperatures may require special metallurgy Flare Knockout Drums Gas streams from reliefs are frequently at or near their dew point, where condensation may occur, and some systems may relieve liquids or two-phase fluids in an overpressure event A knockout drum is usually provided near the flare base, and serves to recover liquid hydrocarbons or water, prevent liquid slugs, and remove large (300–600 micron diameter and larger) liquid particles The knockout drum reduces hazards caused by burning liquid that could escape from the flare stack All flare lines should be sloped toward the knockout drum to permit condensed liquid to drain into the drum for removal Liquid traps in flare lines should be avoided If liquid traps are unavoidable, a method for liquid removal should be provided The location of the flare knockout drum also needs to take into account radiation effect from the burning flare Typically these drums are located between the flare and the process area, where the maximum flare radiation exposure may be higher than allowable for continuously operating equipment, but reasonable enough to allow properly trained personnel appropriate time to leave in a major flaring event A molecular purge reduction seal is a seal device, installed in a flare stack, which uses the difference in relative molecular masses of purge gas and infiltrating air to reduce the rate at which air will enter the stack A velocity seal is a purge reduction seal which operates on the principle that air infiltrating the stack counter to the purge flow hugs the inner wall of the flare tip The seal looks like one or more orifices located below the flare tip, which forces the air to the center of the stack where it is swept up by the purge gas To be effective, purge reduction seals require a purge gas, typically natural gas or nitrogen These seals not stop flashback, but rather minimize the chances that the air concentration below the flare tip becomes high enough to support flashback These devices reduce the flow rate of purge gas which otherwise would be required to accomplish this The minimum seal purge gas rate will be specified by flare supplier Purge gas is normally supplied at the end of all major flare headers and sub-headers, to ensure that the flare headers are free of air Changes in ambient temperature, or cooling of the flare header after a hot relief could cause a partial vacuum in the flare header if no purge is provided In most cases, the sum of the purge rates needed for the flare headers is greater than the purge needed for the flare seal Flare systems are commonly designed for a mechanical design pressure of at least 335 kPa (ga), to minimize the chances of equipment damage due to a flashback FLARE SYSTEMS Types of Flares A number of different types of flares are used in natural gas processing facilities The most common can be classified as: Elevated Pipe Flares — This style consists of an elevated flare riser with typically a flame stability device constructed of stainless steel at the tip The degree of smokeless operation is dependent on the gas composition and discharge velocity (natural gas lean in NGL may burn relatively smokelessly) Elevated Assisted Smokeless Flare — A general classification of several different styles of elevated flares, designed to minimize smoke formation The mechanism is improved combustion due to the turbulence caused by the assist gas Assist gas mixing can be external at the flare tip exit, internal to the flare tip, or both These flares can operate from below 0.5 Mach to sonic The decision depends on the acceptable back-pressure for the flare header, the availability of utility streams, and the particular design of the flare tip The required quantity of assist gas depends on the type Knockout drums may be vertical external to the flare stack, built into the bottom of a self supporting flare stack, or horizontal external to the flare stack Internals which may break free and block the relief path are not allowed in a flare knock out drum Additional material on design and sizing for flare knock out drums, including sizing examples are provided in ISO 23252 (API Std 521) Flare Seals and Flare System Purging • Steam assisted flare tip: most common type of flare used in refinery and natural gas service where sufficient steam is available Can achieve a smokeless operation over a wide range of flared fluids and operating conditions A seal is provided in the flare system between the knockout drum and the flaretip to prevent flashbacks due to air ingress., which can result in a sudden substantial increase in pressure in the flare system, and potential damage Several types of seals can be used: 1) a water seal drum, 2) a molecular purge reduction seal (buoyancy seal), or 3) a velocity purge reduction seal • Low Pressure Air Assist: commonly uses air supplied by a blower in a channel around the flare stack to promote smokeless operation Generally, these systems will permit smokeless operation during dayto-day operation, but not necessarily at full flaring rate A water seal drum is almost always installed in refinery flare systems, and is sometimes used in natural gas processing plants It separates the flare system from the flare stack and provides a water barrier which is capable of stopping flashback 5-20 Several non-proprietary methods for predicting thermal radiation from flares are available One method based on flare supplier input, which can be used for preliminary calculations for simple flares with smokeless capacity of 10% or less, at tip mach number of 0.5 or less, is presented below ISO 23521 (API Std 521)13 presents a similar method, which in general will produce more conservative results This and other radiation models are reviewed in a paper by Schwartz and White.6 • Natural gas assisted Flare: uses high pressure natural gas to provide the discharge turbulence required for smokeless operation High Pressure Elevated Staged Flare — Flare tips operating at sonic velocity, which use pressure energy to promote smokeless burning Typically, the flare tips are staged using valves at the flare base This design is most efficient when the flare stream is high pressure natural gas Preliminary Elevated Flare — Thermal Radiation Calculation — Horizontal Ground Flare — A ground flare typically consists of a flare system operated with the flame horizontally on the ground The most common style is similar to staged flare tips They are often used in remote locations where emissions, noise and flame visibility are not of significant concern Spherical Radiation Intensity Formula: (Wf) (NHV) (ε) I = 14.4 π (R2) Eq 5-19 This equation has been found to be accurate for distances as close to the flame as one flame length Enclosed Ground Flare — an enclosed ground flare consisting of a burner surrounded by a shell The system operates by introducing the flare gas into the unit via a burner Air enters the bottom of the shell via air louvers Enclosed ground flares are normally used only for small capacity, low pressure flaring operations (such as tank flares) where an elevated flare is inconvenient, and for high capacity situations where an elevated flare is not practical due to thermal radiation or community visibility concerns Special flame arrestor burners are used in tank applications to minimize the possibility of back flash Equation 5-19 is valid so long as the proper value of fraction of heat radiated, ε, is inserted Classically, ε has been considered a fuel property alone Brzustowski et al.2 experimentally observed a dependence of ε on jet exit velocity Other authors have presented models that consider the carbon particle concentration in the flame The fraction of heat radiated is a function of many variables including gas composition, tip diameter, flare burner design, flowrate and velocity, flame temperature, air-fuel mixing, and steam or air injection; therefore a flare supplier should be consulted to determine the specific values for a given application A list of vendor recommended fraction of heat radiated values for the most frequently flared gases is shown in Fig 5-18 Loading and Tank Flares — Several designs of elevated flares are available that are tailored to the destruction of vapors during truck loading and from tanks These designs deal with the problems of low pressure, large variation in flow rate, and the potential of air ingress FIG 5-17 Permissible Design Flare Thermal Radiation Levels13 Elevated Flare Allowable Thermal Radiation Permissible design level K (kW/m2) Thermal radiation is a prime concern in flare design and location Thermal radiation calculations must be performed to avoid dangerous exposure to personnel, equipment, and the surrounding area (trees, grass) Thermal radiation exposure limits, and the effects on personnel, equipment and instrumentation on shown in Fig 5-17 from ISO-23251 (API Std 521).13 9.46 Maximum radiant heat intensity at any location where urgent emergency action by personnel is required When personnel enter or work in an area with the potential for radiant heat intensity greater than 6.31 kW/m2 (2000 Btu/h·ft2), then radiation shielding and/or special protective apparel (e.g a fire approach suit) should be considered SAFETY PRECAUTION — It is important to recognize that personnel with appropriate clothing a cannot tolerate thermal radiation at 6.31 kW/m2 (2000 Btu/h·ft2) for more than a few seconds 6.31 Maximum radiant heat intensity in areas where emergency actions lasting up to 30 s can be required by personnel without shielding but with appropriate clothinga 4.73 Maximum radiant heat intensity in areas where emergency actions lasting to can be required by personnel without shielding but with appropriate clothinga 1.58 Maximum radiant heat intensity at any location where personnel with appropriate clothing a can be continuously exposed Equipment protection should be evaluated on a case by case basis, as various pieces of equipment have different protection needs Solar radiation may add to the calculated flame radiation and is dependent upon specific atmospheric conditions and site location A typical design range for a temperate climate is 0.79 to 1.04 kW/m2, but depends on the location The decision to include solar radiation, is dependent on design critieria, and is dependent and the site and the intent of the evaluation Determining Elevated Flare Thermal Radiation Flare suppliers have developed proprietary radiation modeling programs based on equations and empirical values, and these are commonly used to assess the effects of flare radiation, and set the flare height The F* factor (fraction of heat radiated) values used in these programs are specific to the equations used, and are generally not interchangeable with the F* factor values used in other methods These programs have not been subject to review and verification in the open literature, and are specific to a particular flare design and exit velocity Conditions ppropriate clothing consists of hard hat, long-sleeved shirts with cuffs butA toned, work gloves, long-legged pants and work shoes Appropriate clothing minimizes direct skin exposure to thermal radiation a 5-21 To calculate the intensity of radiation at different locations, it is necessary to determine the length of the flame and its angle in relation to the stack (see Fig. 5-19) A convenient expression to estimate length of flame, Lf, is shown below, based on information from equipment suppliers Lf = (0.12) (d) √ ∆Pw 1400 Eq 5-20 For conventional (open pipe) subsonic flares, an estimate of total flare pressure drop is 1.5 velocity heads based on nominal flare tip diameter The pressure drop equivalent to velocity head is given by: ρ V2 (0.102) ρ V2 ∆Pw = = 19.62 Eq 5-21 The coordinates of the flame center with respect to the tip are: d = √ 0.5 3.23 • 10–5 • W ỉ Z • T ö • ỗ ữ P2 M ố k • MW ø 1000 Eq 5-22 • Sonic velocity of a gas is given by: √ a = k R0 T MW = (Lf / 3) (sin θ) Eq 5-26 Yc = (Lf / 3) (cos θ) Eq 5-27 The distance from any point on the ground level to the center of the flame is: R = √ (X – Xc)2 + (Hs + Yc)2 Eq 5-28 Equations 5-19 and 5-28 allow radiation to be calculated at any location The stack height results from considering the worst position vertically below the center of the flame for a given condition of gas flow and wind velocities (see Fig. 5-19) R2 = (Hs + Yc)2 ∆Pw is the pressure drop at the tip in mm of water After determining tip diameter, d, using Equation 5-22, and the maximum required relieving capacity, flame length for conditions other than maximum flow can be calculated using Equation 5-20 The flare radiation method applies to flare tip Mach number of 0.50 or less in Equation 5-22 Xc R Eq 5-29 = (Hs + Yc) Eq 5-30 Hs = (R – Yc) Eq 5-31 Hs = R – [(Lf / 3) (cos θ)] Eq 5-32 This method assumes that for different wind velocities the length of the flame remains constant In reality this is not true When the wind blows at more than 25 m/s, the flame tends to shorten For practical design, this effect is neglected API Preliminary Elevated Flare — Thermal Radiation Method — ISO 23251 (API Std 521) presents a similar methodology for calculation of flare radiation The API method is generally more conservative to that shown above The following are the major differences Eq 5-23 FIG 5-19 Dimensional References for Sizing a Flare Stack The center of the flame is assumed to be located at a distance equal to 1/3 the length of the flame from the tip The angle of the flame results from the vectorial addition of the velocity of the wind and the gas exit velocity Vw θ = tan–1 Vex Eq 5-24 Eq 5-25 √ ∆P w V ex = 168 1400 θ Lf WIND yC XC d FIG 5-18 Typical Fraction of Heat Radiated Values for Flared Gases R HS + Y C HS Carbon Monoxide 0.075 Hydrogen 0.075 Hydrogen Sulfide 0.070 Ammonia 0.070 Methane 0.10 Propane 0.11 Butane 0.12 Ethylene 0.12 Propylene 0.13 The maximum value of ε for any gas is 0.13 X - XC X Courtesy American Petroleum Institute 5-22 mittent and non-scheduled The flare must be instantly available for full emergency duty to prevent any possibility of a hazardous or environmentally offensive discharge to the atmosphere Wind-shields and flame-retention devices may be used to ensure continuous piloting under the most adverse conditions Most pilots are designed to operate at wind velocities of 160 km/h and higher Multiple pilots are generally provided • Different equation used for length flame • Different values used for fraction of heat radiated for flared gas by component • The API method gives a leaner flame angle Low Heating Value Gas Flaring The most common flare pilot ignition system is a flame front generator, where a flame generated by compressed air and fuel gas is sent through a pipe at high velocity up the flare stack to ignite the pilot gas Spark plug type igniters are sometimes used as well Low heating value gases are common in many gas plants; for example, vent gas from a sweet gas amine system or the feed gas to a sulfur plant These streams can be a challenge for a flare system A number of tests were performed in the 1980s to assess flare flame stability, and combustion efficiency, for a wide range of fluids Based on this testing it was concluded that high heating value gases can be flared with a thermal destruction efficiency of greater than 98% over a wide range of flare types and flare tip velocities For low heating value gas, however, the testing found that a minimum heating value is needed, and that flare tip velocity must be limited in order to achieve high destruction efficiency To flare gas streams with low heating value, the gas must be supplemented by natural gas injection in the flare header or at the flare tip, to ensure a minimum heating value of approximately 7450 kJ/Nm3 for an unassisted flare and 9315 to 11 180 kJ/Nm3 for an assisted flare, and the maximum flare tip velocity must be substantially limited Proper flame monitoring is critical to flare operation Typical systems consist of multiple flame detectors, or multiple thermocouples, along with closed-circuit television Flare Siting and Regulations Flare design must comply with local, state, and federal regulations regarding pollution, noise, and location Permits are usually required prior to construction Flaring of gas for the purpose of emissions control (as opposed to relief), is regulated in the U.S.A by the Environmental Protection Agency (EPA), and specific maximum flare tip velocities may apply Standards for design of flare systems are covered by API Std 537 and ISO23251 (API Std 521) Smokeless Operation Most smokeless flares utilize outside motive forces to produce efficient gas/air mixing and turbulence from the momentum transferred by the high velocities of the external motive jet streams (steam, fuel, gas, etc.) The assist medium mass flow requirements are low for steam and fuel gas because of their high velocity relative to the flare gas Flare suppliers should be consulted, because the assist gas rate is dependent on the flare design Atmospheric Vent Stacks Atmospheric vent stacks can be used to dispose of non-toxic hydrocarbons to the atmosphere, under the proper conditions In the natural gas industry, vent stacks for hydrocarbons are typically limited to atmospheric disposal of lighter-than-air gases Stacks are many times used in natural gas compressor stations to vent an individual compressor or the entire station to the atmosphere on an emergency shutdown ISO 23251 (API Std 521) presents a table with suggested injection steam rates based on the type of gas being flared The following fitting equation may be used for calculation of the injection steam rate for a mixture of paraffins (reference 12): 10.8 Wstm = Whc 0.49 – MW Before designing a vent stack system for a facility, it is important to consider a number of factors: vent stack location relative to plant and public facilities (permanent or temporary), vent stack height, possibility of a combustible or toxic mixture at grade or at an elevated platform, layers of protection in place at upstream equipment, level controls to prevent overflow of volatile liquids into the stack, appropriately sized knock out drum, possibility of explosive release of energy due to detonation of a vapor cloud, radiation due to a jet fire at the vent stack tip caused by static ignition or lightning The decision to discharge hydrocarbons or other flammable or hazardous vapors to the atmosphere usually requires that a dispersion analysis be carried out to ensure that disposal can be accomplished without creating a hazard These topics are covered extensively in ISO 23251 (API Std 521) Eq 5-33 For a mixture of olefins, the fitting equation becomes: 10.8 Wstm = Whc 0.79 – MW Eq 5-34 The water spray and air blower methods provide necessary mixing with low velocities and greater mass flow rates The required assist fluid injection rate is highly dependent upon the method of injection and atomization Wind also has a significant effect on water spray flares and may greatly reduce their effectiveness APPLICABLE CODES, STANDARDS, AND RECOMMENDED PRACTICES The blower assisted flare uses air to produce smokeless operation Forced draft from a blower assists combustion and air/ gas turbulence, promoting smokeless operation With blower assisted flares it is common, for high capacity flares, to design the air assist for a the portion of the maximum capacity expected during operation, and to allow a degree of smoke during the full emergency relief This, however, is dependant on local requirements The designers of relief systems should be familiar with the following documents related to pressure relief valves in process plants and natural-gas systems ASME Boiler and Pressure Vessel Code, Section I, Rules for Construction of Power Boilers ASME Boiler and Pressure Vessel Code, Section VIII Pilots and Ignition ASME B31.1 — Power Piping Reliable pilot operation under all wind and weather conditions is essential Flaring operations are for the most part inter- ASME B31.3 — Process Piping 5-23 ASME B31.4 — Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids ASME B31.8 — Gas Transmission & Distribution Systems API Std 520-I — Sizing, Selection, and Installation of Pressure-Relieving Devices in Refineries, Part I – Sizing and Selection OSHA Publications — OSHA Title 29, Part 1910 — Part 1910 includes handling, storage, and safety requirements for LPG and ammonia CGA (Compressed Gas Association) Publications — Series of standards covering transportation, handling, and storage of compressed gases including: Pamphlet S-1.2 Safety Relief Device Standards API RP 520-II — Sizing, Selection, and Installation of Pressure-Relieving Devices in Refineries, Part II - Installation Part 2: Cargo and portable tanks for compressed gases API Std 526 — Flanged Steel Pressure Relief Valves Pamphlet S-1.3 Safety Relief Service Standards API Std 527 — Seat Tightness of Pressure Relief Valves Part 3: Compressed Gas Storage Containers API Std 537 — Flare details for General Refinery and Petrochemical Service REFERENCES Min, T C., Fauske, H K., Patrick, M., Industrial Engineering Chemical Fundamentals, (1966), pp. 50-51 Brzustowski, T A., “Flaring In The Energy Industry”, Process Energy Combustion Science, Pergamon Press, Great Britain, V. 2, pp. 129-144, 1976 Straitz III, J F., Nomograms “Determining Proper Flame Tip Diameter and Height”, Oil Gas and Petroleum Equipment, Tulsa, Oklahoma, July and August, 1979 “Recommendations and Guidelines — Gasoline Plants, Pamphlet 301”, Oil Insurance Association, 175 West Jackson Blvd., Chicago, Illinois 60604, August 1971 Van Boskirk, B A., “Sensitivity of Relief Valves to Inlet and Outlet Line Lengths,” Chemical Engineering, August 23, 1982, pages 77-82 Schwartz, Robert E and White, Jeff W., “Predict Radiation From Flares,” Chemical Engineering Progress, Vol 93, pp 42-49, July 1997 Overa, Sverre J., Strange, Ellen and Salater, Per, “Determination of Temperatures and Flare Rates During Depressurization and Fire,” GPA Convention, San Antonio, Texas, 15–17 March, 1993 API Bulletin 2521 — Use of Pressure Vacuum Vent Valves for Atmospheric Pressure Tanks to Reduce Evaporation Loss National Board — Pressure Relief Device Certifications NB18 (RedBook) Carucci, V.M., and Mueller, R.T., “Acoustically Induced Piping Vibration in High Capacity Pressure Reducing Systems,” ASME Paper 82-WA/PVP-8, 1982 Energy Institute, IP SAFE Hydrocarbon Leak Reduction Volume 2.00, Guidelines for the Avoidance of Vibration Induced Fatigue in Process Pipework, ISBN 9780852934630, 2nd edition, March 2008 API Standard 620 — Design and Construction of Large, Welded, Low-Pressure Storage Tanks API Standard 650 — Welded Steel Tanks for Oil Storage API STD 2508 — Design and Construction of Ethane and Ethylene Installations at Marine and Pipeline Terminals, Natural Gas Processing Plants, Refineries, Petrochemical Plants, and Tank Farms — Covers the design, construction, and location of refrigerated (including autorefrigerated) liquefied ethane and ethylene installations, which may be associated with one or more of the following: railroad, truck, pipeline stations, or marine loading or unloading racks or docks API STD 2510 — Design and Construction of LPG Installations Covers LPG Storage Vessels, Loading and Unloading Facilities at Marine and Pipeline Terminals, Natural Gas Processing Plants, Refineries, Petrochemical Plants, and Tank Farms API Specification 12F — Specification for Shop Welded Tanks for Storage of Production Liquids API Specification 12D — Specification for Field Welded Tanks for Storage of Production Liquids ISO 15156/NACE MR0175 Petroleum and Natural Gas Industries — Materials for Use in H2S-containing Environments in Oil and Gas Production ISO 23251 (API Std 521), Pressure-Relieving and Depressuring Systems ISO 28300 (API Std 2000), Venting Atmospheric and LowPressure Storage Tanks (Nonrefrigerated and Refrigerated) NFPA 30 — Flammable and Combustible Liquids Code NFPA 58 — Liquefied Petroleum Gas Code NFPA 59 — LP-Gas, Plant Code (Note: For Utility Plants) NFPA 59A — Production Storage and Handling of Liquid Natural Gas (LNG) NFPA 68 — Standard of Explosion Prevention by Deflagration Venting NFPA 69 — Standard of Explosion Prevention Systems 10 Ouderkirk, R., Rigorously Size Relief Valves for Supercritical Fluids, Chemical Engineering Progress, August 2002 11 Nezami, P.L., Distillation Column Relief Loads – Part 1, Hydrocarbon Processing, April 2008, and Part – May 2008 12 O.C Leite, “Smokeless, Efficient, Non-toxic Flaring,” Hydrocarbon Processing, March 1991, page 77 13 ISO 23251 API Std 521 — Pressure-relieving and Depressuring Systems (Fifth Edition, 2007), American Petroleum Institute, 1220 L Street, NW, Washington, DC 20005 14 API 520-520-I — Recommended Practice for the Design of Pressure Relieving Systems in Refineries (Eighth Edition, 2008, American Petroleum Institute, 1220 L Street, NW, Washington, DC 20005 15 “ASME Boiler and Pressure Vessel Code,” Section VIII, Div 1, 2010 16 API Std 527, “Seat Tightness for Pressure Relief Valves,” Reaffirmed 2007 5-24 BIBLIOGRAPHY traitz III, J F., “Solving Flare-Noise Problems”, Inter Noise 78, San S Francisco 8-10, May 1978, Pages 1-6 Chiu, C H “Apply Depressuring Analysis to Cryogenic Plant Safety”, Hydrocarbon Processing, November 1982, Pages 255-264 Straitz III, J F., “Flaring for Safety and Environmental Protection”, Drilling-DCW, November 1977 Kandell, Paul “Program Sizes Pipe and Flare Manifolds for Compressible Flow”, Chemical Engineering, June 29, 1981, Pages 89-93 Straitz III, J F., “Make the Flare Protect the Environment”, Hydrocarbon Processing, October 1977 Powell, W W., and Papa, D M., “Precision Valves for Industry”, Anderson, Greenwood Company, Houston, Texas, 1982, Pages 52-61 an, S H., “Flare Systems Design Simplified”, Hydrocarbon ProcessT ing (Waste Treatment & Flare Stack Design Handbook) 1968, Pages 81-85 5-25 NOTES: 5-26 ... operation The relief device sizing, and relief and disposal system design, are critical components of this review Typical steps in this process are: Determination of the maximum relief requirements... condition may dictate the sizing of the entire relief system; however, since equipment may be dispersed geographically, the effect of fire exposure on the relief system may be limited to a specific plot... manner, thermal relief valves are not installed in all instances where piping systems may be blocked in by two valves The decision to install a thermal relief valve for piping systems is typically