m05 - relief system

8/12/2019 M05 - Relief System

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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 separatordrum, and the flare including igniters, tips, sealing devices,purge and steam injection for smokeless burning. Applicationof relief devices must comply with appropriate ASME VesselCodes. Design of relief systems must also comply with applica-ble state and federal codes and laws as well as the requirements

of the insurance underwriter covering the plant or installati

State and federal regulations not only cover safety but aenvironmental considerations such as air and water pollutand noise abatement. This section presents a convenient sumary of relief system information obtained from API and othsources, abridged and modified for this data book. Final deswork should be consistent with the full scope of API, ASMand other code and specification requirements.

SECTION 5

Relief Systems

a = sonic velocity, m/s

A = required discharge area of the valve, cm2. Usevalve with the next larger standard orifice size/area

AB = bellows area, cm2

A = discharge area of the valve, cm2, for valve withnext standard size larger than required dischargearea

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 relievingtemperature [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 specificheats 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

15C and 101.325 kPa (abs); or, if liquid, the relativedensity of liquid at flowing temperature referred towater = 1.00 at 15C

hL1 = enthalpy of saturated liquid at upstreampressure, kJ/kg

hL2 = enthalpy of saturated liquid at downstreampressure, 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

FIG. 5-1

Nomenclature

I = radiation intensity at point X, W/m2

k = specific heat ratio, Cp/Cv(see Section 13) Kb = capacity correction factor due to back pressure

Kc = combination correction for rupture disk = 0.9

= 1.0 no rupture disk installed

Kd = coefficient of discharge

Kn = correction factor for Napier steam equation

Ksh = correction factor due to the amount of superheatin the stream

Kv = capacity correction factor due to viscosity for liquphase pressure relief

Kw = capacity correction factor due to back pressure fobalanced bellows pressure relief valves in liquidservice (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 isthe set pressure plus the allowable overpressureplus the atmospheric pressure

P1g = upstream relieving pressure, kPa (ga). This is theset pressure plus the allowable overpressure

P2 = downstream pressure at the valve outlet, kPa (ab 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), 0C)

r = ratio of downstream pressure to upstream pres-sure, P2/P1

R = distance from flame center to point X, m


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DOCUMENTATION

A facilitys documentation allows the user to determine thatthe facility was designed in accordance with relevant codes andstandards. The relief system design documentation is one facetof the overall facility documentation, which helps demonstratethat the process can be operated in a safe manner. Any equip-ment modifications, operations, or changes made to process pa-rameters, or operating procedures, can have a direct impact onthe relief system, and should therefore be documented as partof a facility management of change (MOC) process.

The relief system documentation should demonstrate thatall pressure-containing equipment has been identified and thatthe overpressure protection has been analyzed. Documenta-tion based on the individual protected systems can facilitateensuring that all systems requiring pressure protection havebeen identified. The documentation should show that potentialcauses of overpressure have been identified, rationale has beenprovided as to whether a scenario is or is not credible, and cred-ible causes of overpressure have been evaluated. The designbasis of the disposal system, including all assumptions madein the determination of controlling load(s), and calculated backpressure at each relief device should be documented. A detailedlist of documentation requirements is presented in ISO 23251

(API Std 521).

HAZARD REVIEWS

Appropriate hazard reviews, as a part of a Process SafetyManagement Program, are required by U.S. OSHA-29 CFRPart 1910 in the United States, and by similar regulations inmost other localities in the world. These reviews are conductedduring the design phase, prior to operation, and periodicallyduring operation. The relief device sizing, and relief and dispos-al system design, are critical components of this review. Typicalsteps in this process are:

Preliminary hazard review using process flow diagramsand a preliminary layout, to identify hazards in the pro-cess, with the proposed facility location, and layout, andwith storage and handling of feed materials or intermedi-ate and final products.

Early engineering hazard review with more advancedwork products.

Detailed hazards review using one of several possible

techniques sanctioned by local authorities (e.g., HAZOP,Hazard and Operability Analysis, What-if, QuantitativeRisk Evaluation), utilizing process and instrumentationdiagrams, plot plan, and other detailed design deliver-ables.

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 toprotect piping and equipment against excessive over-pressure.Proper selection, use, location, and maintenance of relief de-vices are essential to protect personnel and equipment as wellas to comply with codes and laws.

Determination of the maximum relief requirements may bedifficult. Loads for complex systems are determined by conser-vative assumptions and detailed analysis. By general assump-tion, two unrelatedemergency conditions caused by unrelatedequipment failures or operator error will not occur simulta-

Ro = universal gas constant = 8314

J

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 verticalvessel, m/s

V = gas velocity, m/s

Vex = exit velocity, m/s

Vl = flow rate, liters/s at flowing temperature andpressure

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

= prefix, indicates finite increment

= fraction of heat radiated

L = density of liquid, kg/m3

v = density of vapor, kg/m3

= angle of flare flame from vertical, degrees

= viscosity at flowing temperature, mPa s(centipoise)

S = viscosity at flowing temperature, Saybolt UniversalSeconds (SSU)

FIG. 5-1 (Contd)

Nomenclature


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neously (no double jeopardy). The relationship and sequence ofevents must be considered. ISO 23251 (API Std 521) provides fur-ther guidance on these issues.

The development of relief loads requires the engineer to befamiliar with overall process design, including the type of pumpdrives used, cooling water source, spares provided, plant layout,instrumentation, and emergency shutdown philosophy. The de-sign of the proper relieving device must take into consideration,as a minimum, all of the following upset conditions for the indi-

vidual equipment item if such upset can occur. Each upset condi-tion must be carefully evaluated to determine the worst casecondition which will dictate the relieving device capacity.

The following provides guidance for some common overpres-sure scenarios. It must be recognized that it does not and cannotaddress all potential overpressure scenarios that may be relevantfor a specific piece of process equipment. The designer shouldemploy the Hazard Reviews discussed above to ensure that allcredible overpressure scenarios have been incorporated into afacilitys design.

SUMMARY OF COMMONRELIEF SCENARIOS

Blocked DischargeThe outlet of almost any vessel, pump, compressor, fired heat-

er, or other equipment item can be blocked by mechanical failureor human error. The relief load for many cases is the maximumflow into the system, at relief conditions, but must be carefullyanalyzed for each contingency.

Fire Exposure

Fire is one of the least predictable events which may occur ina gas processing facility, but is a condition that may create thegreatest relieving requirements. If fire can occur on a plant-widebasis, this condition may dictate the sizing of the entire relief sys-tem; 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 devel-oped to determine relief loads from vessels exposed to fire. For-mula selection varies with the system and fluid considered. Fireconditions may overpressure vapor-filled, liquid-filled, or mixed-phase systems. See the discussion on Sizing of Relief Devices, fordetails, and relief load calculation methods.

Tube Rupture

The tubes of shell and tube heat exchangers are subject to fail-ure from a number of causes; including corrosion, thermal shock,and vibration. In the event of such a failure, it is possibile that thehigh-pressure stream can overpressure the equipment and pip-ing connected to the low pressure side of the exchanger. A tuberupture 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 sheetto a complete tube rupture where a sharp break occurs in one tube.The loss of containment of the low-pressure side to atmosphere isunlikely to result from a tube rupture, if the resulting pressure onthe low-pressure side, including upstream and downstream sys-tems, does not exceed the corrected hydrostatic test pressure.

Appropriate design options to be considered for protecting thelow pressure side equipment and piping from potential tube rup-ture are: 1) Install a relief device (pressure relief valve or rup-

ture disk) on, or close to, the low pressure side of the heexchanger, 2) ensure there is an adequate open relief paso that the low pressure side will not be over-pressured btube rupture, or 3) design the low pressure side of the hexchanger, and the piping and equipment in the associasystems, such that the corrected hydro-static test pressurethe low pressure system exceeds the high pressure side despressure (in some cases maximum upstream side operatpressure may be used instead of design pressure). The boption for each application is a function of the operating adesign pressure for each side, fluid phase on each side, flutype and service corrosion history, and the heat exchandesign. Systems with gas, two phases, or a liquid which wflash across the tube rupture, on the high pressure side, aa liquid on the low pressure side, should be thoroughly viewed, since a relief valve may be less effective in preventsurges in these circumstances. See ISO 23251 (API Std 5for the definition of corrected hydro-static test pressure adetailed guidance on this subject.

Relief protection for tube rupture is not required for dble pipe heat exchangers, if the internal parts are construcof schedule pipe.

Control Failure

The failure positions of instruments and control valmust be carefully evaluated. In practice, the control vamay not fail in the desired position. A valve may stick in twrong position, or a control loop may fail. Relief protectionthese factors must be provided. Relief valve sizing requiments for these conditions should be based on flow coecients (manufacturer data) and pressure differentials for tspecific control valves and the facility involved. Credit cantaken for some downstream flow paths, if ensured to be opthroughout the relief event. No favorable control valve actmay be assumed. In addition, the relief load determinatshould take into account that the liquid level in the upstrevessel may be lost, causing gas blow-by through the open ctrol valve.

ISO 23251 (API Std 521) describes several relief scenarthat consider the position of a control valve and its bypavalve. If during operation, the bypass valve may be openedprovide additional flow, then the total maximum flow (contvalve wide open, plus bypass valve at some position, depeing on the service and facility practices, must be considewhen determining the relief load. If the bypass is opened oduring maintenance, when the control valve is blocked in ter switchover, then a design based on the maximum flthrough either the control valve, or the bypass valve, whiever is greater, may be considered. In this case the systmust be evaluated during the facility hazard review to sure that the proper administrative controls are in placeprevent a situation in which both the control valve and tbypass are open simultaneously.

Thermal Expansion

If isolation of a process line on the cold side of an exchancan result in excess pressure due to heat input from the waside, then the line or cold side of the exchanger should be ptected by a relief valve. If any equipment item or line can isolated while full of liquid, a relief valve should be providfor thermal expansion of the contained liquid. Low proctemperatures, solar radiation, heat tracing, or changes in mospheric temperature can necessitate thermal overpressuprotection. Flashing across the relief valve needs to be cons


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ered. Administrative controls for block valves around heat ex-changer are discussed in ASME Section VIII, Appendix M.

As a practical manner, thermal relief valves are not installedin all instances where piping systems may be blocked in by twovalves. The decision to install a thermal relief valve for pip-ing systems is typically based on the following factors: lengthand size of piping, vapor pressure of the fluid at the elevatedtemperature possible, volatility and/or toxicity of the fluid, po-tential for valve leakage (metal vs. soft seated valves), and the

presence of automatic shut down valves in the system. It iscommon to provide thermal relief valves for cryogenic liquid ap-plications. Guidance for when to specify thermal relief and forsizing of the valve are provided in ISO 23251 (API Std 521). Asizing equation for a simple thermal relief valve is given laterin this chapter. A 19 mm 25 mm relief valve is commonlyused for liquid filled, non-flashing piping systems containingnon-cryogenic liquids.

Utility Failure

Loss of cooling water may occur on an area-wide or plant-wide basis. Commonly affected are fractionating columns andother equipment utilizing water cooling. Cooling water failuremust be considered for individual relief devices. In addition, itis often the governing case in sizing flare systems.

Electric power failure, similar to cooling water failure, mayoccur on an area-wide or plant-wide basis and may have a vari-ety of effects. Since electric pump and air cooler fan drives areoften employed in process units, a power failure may cause theimmediate loss of reflux to fractionators. Motor driven compres-sors will also shut down. Power failures may result in majordevice and flare system relief loads.

Instrument air system failure, whether related to electricpower failure or not, must be considered in sizing of the flaresystem since pneumatic control loops will be interrupted. Alsocontrol valves will assume the position as specified on loss ofair and the resulting effect on the flare system must be con-sidered.

Fans on air cooled heat exchangers or cooling towers oc-casionally become inoperative because of a loss of power or amechanical breakdown. On cooling towers and on air cooledexchangers where independent operation of the louvers can bemaintained, credit may be taken for the cooling effect obtainedby convection and radiation in still air at ambient conditions.

Check Valve Failure

Failure of a check valve to close must be considered. A singlecheck valve is not an effective means for preventing overpres-sure by reverse flow from a high-pressure source. In most cases,focus should be on prevention of reverse flow. It is important tonote that, in addition to overpressure of the upstream system,reverse flow through machinery can destroy rotating equip-ment, 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).

For relief purposes, a single check valve is treated as if it isnot there, unless specific maintenance and inspection practicesare adhered to. Two check valves in series reduce the likelihood,and potential magnitude of reverse flow, but over-pressuringof the low pressure side can still take place due to even smallcheck valve leaks, assuming the pressure is high enough. ISO23251 (API Std 521) provides specific guidance both on how totreat check valve failure as a relief scenario, maintenance/in-

spection practices for critical check valves, when relief protec-tion is required, and recommended practices for determiningthe controlling relief rate.

Reflux Failure and/or Loss of Overhead

Cooling For Fractionators

The failure of electrical or mechanical equipment that pro-vides cooling or condensation in process streams can causeoverpressure in fractionators and process vessels. The evalua-

tion of relief scenarios for towers, in order to determine the ap-propriate load for the relief device, is complex. Various simpli-fied approaches have been used in the past, however the mostcommon method used today is a modified steady state materialbalance at relief conditions, as described by Nezami.11Dynamicsimulation may also be applied to evaluate the tower relief loadvs. time. Care should be exercised when using the dynamic ap-proach since the results can be highly dependent on the specificassumptions used, and may not be conservative.

Abnormal Heat Input

Reboilers and other process heating equipment are designedwith a specified heat input. When they are new or recentlycleaned, and/or due to loss of control, additional heat inputabove the normal design can occur. In the event of a failure oftemperature control, vapor generation can exceed the processsystems ability to condense or otherwise absorb the build-upof pressure, which may include non-condensables generated byoverheating. The system should be evaluated at the relief condi-tion using a modified material balance approach.

Process Upset

The source of a process upset can vary depending of the ap-plication. Therefore this contingency must be analyzed individ-ually based on the specific circumstances. For example, guid-ance for fractionation towers is included in reference 11.

Liquid Overfilling of a Vessel

Vessels are subject to overfilling and must be protected fromoverpressure from that source. The cause can be an loss of con-trol on the inlet, or a failure of the controls or pump on theoutlet.

TransientsTransient pressure surges can occur as a result of liquid

hammer, steam hammer, or steam condensate induced ham-mer, A pressure relief valve is normally not effective as a pro-tective device for these causes of overpressure, so the focusshould be on avoiding transient pressure surges through designand operation, and/or the use of a surge suppressor device.

Vacuum Protection

Vessels may be subject to (partial) vacuum from liquid pump

out, condensation of volatiles, or other causes. Typically, indus-try practices for vessels containing hydrocarbons is to designfor the maximum possible vacuum. In some services (i.e., verylarge low design pressure vessels) alternate vacuum protectionis generally necessary.

Relief Scenarios For

Specific Equipment Types

The following equipment considerations should be followedfor relief system design.


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Centrifugal Compressors Centrifugal compressor sys-tems should be analyzed in order to properly understand themaximum pressure that can occur, and required relief protec-tion (if any) for each part of the system, during operation (nor-mal and upset), start-up, and at shutdown, based on the normaland maximum suction, and/or discharge conditions. The maxi-mum settle out pressure for each portion of the system shouldbe 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 inone portion of the system may temporarily rise to a higher pres-sure than the overall final settle out pressure.

Reciprocating Compressors Each positive displace-ment compressor must have a relief valve on the discharge up-stream of the block and check valves in order to protect the com-pressor and downstream equipment. Commonly, relief valvesare also provided on each individual stage to protect the inter-stage equipment. Reciprocating compressor systems should beanalyzed in order to properly understand the maximum pres-sure that can occur, and required relief protection for each partof the system, during operation (normal and upset), start-up,and at shutdown, based on the normal and maximum suction,and/or discharge conditions.

Fired Heaters General best practice is to design firedheaters such that the process side cannot be blocked in. Typical-ly, the heater control system will shut down the heater in caseof loss of flow on the process side, but the safety integrity level(SIL) may be inadequate to avoid overpressure. If there is a pos-sibility that the process side of a fired heater may be blocked in,then a relief valve should be provided to protect the heater. Therelief valve should be installed on the downstream of the heaterto help ensure flow through the heater upon blocked outlet.

Pumps Relief valves are required on the discharge ofeach positive displacement pump. Normally, these relief valvesare piped back to the source vessel. In some instances, the reliefdevice discharge can be returned to the suction line, dependingon the service and extent of heat up due to recycle. In either in-stallation, the pressure present at the discharge of the pressure

relief valve must be considered in determining the set pressureof a conventional pressure relief valve. Isolation valves aroundthe pressure relief valves may not be required, if the recycle isto the suction line and the pump itself can be isolated for main-tenance. Many small metering pumps will have built-in inter-nal relief protection. As these internal reliefs are typically notidentified in facility documentation (e.g., P&IDs, critical devicelists, etc.), they are typically not tested or maintained. For thisreason, they generally should not be relied upon as a means toprevent overpressure.

Atmospheric Storage Tanks, and Low Pressure Tanks Atmospheric storage tanks are typically protected againstoverpressure and vacuum due to process conditions and atmo-spheric changes. In addition, relief protection for fire and otherupset conditions is required. Tanks are commonly protected by

weighted or spring loaded pallet operated relief devices (con-servation vents). A pilot-operated pressure relief can also beutilized. Storage tanks with diameters of 15 m or larger may befitted with a frangible roof (weak roof to shell attachment whichwill fail upon overpressure); such a roof-to-shell joint serves asemergency pressure relief device in lieu of a separate fire reliefvalve valve (See API Std 650). All other tanks require fire over-pressure protection by an emergency relief vent.

Pressure relief requirements and relief device sizing for at-mospheric tanks and any tanks, vessels, or other equipmentdesigned for less than 103 kPa (ga), are covered by ISO 28300

(API Std 2000), which sets thermal breathing rates, and frelief rules for this equipment. Note that the fire sizing equtions for low pressure equipment covered by ISO 28300 (AStd 2000) differ from those in ISO 23251 (API Std 521).

At a minimum, design of overpressure protection for tanshould consider: liquid movement into the tank, tank breathdue to weather changes that heat the tank, inert gas pad andpurge regulator failure, internal and external heat transfer deves, failure of vent collection systems, utility failure, blow-throu

of gas from a higher pressure source, composition changes, coolfailure upstream of the tank, fire, and overfilling.

At a minimum, design of vacuum protection for tanks shoconsider: liquid movement out of the tank due to pump transfliquid movement out of the tank due to opening of a drain valtank breathing due to weather changes that cool the tank, faure of inert pads, utility failures.

SPECIAL RELIEF SYSTEMCONSIDERATIONS

Administrative Controls

Administrative controls are procedures that, in combinat

with mechanical locking elements, are intended to ensure thpersonnel actions do not compromise the overpressure prottion of the equipment. They include, as a minimum, documeed operation and maintenance procedures, and training of erator and maintenance personnel in these procedures [ASMBoiler & Pressure Vessel Code Section VIII, Appendix M].

Block Valves in the Relief PathASME Section VIII, Appendix M, provides requirements,

cluding specific administrative controls, for block valves assoated with the inlet and outlet of pressure relief devices, blovalves around equipment, such as heat exchangers, which mayisolated and drained for maintenance, and block valves betwetwo pieces of equipment protected by a single relief device.

High Integrity Protection Systems (HIPS)

A High Integrity Protection System (HIPS) is an instmented system that has multiple redundancies to ensure tsystem is reliable and will react with desired effects as close100% of the time as possible. As part of this, the instrumeand valves, and the safeguarding system, are rated and matained to a stricter standard than most instruments. These stems are even on a different control system. The instrumehave a Safety Instrument Level (SIL); the higher the level tmore reliable the system. HIPS are typically used to mitigflare loads that otherwise would become excessively large,where a pressure relief valve would not adequately protect tsystem. See Section 4 of the Data Book for more informationHigh Integrity Protection Systems (HIPS).

In some very limited instances (i.e. loss of control for an

let valve downstream of a large packed pipeline upstreama treating facility, or protection against runaway reaction,High Integrity Protection System may be considered to replthe requirement for a pressure relief device. This is now rognized by ASME Section VIII, Division 1 (UG-140),15withnumber of requirements including:

The user shall ensure that the MAWP of the vesselgreater than the highest pressure that can reasonabbe expected to be achieved by the system. The user shconduct a detailed analysis of all credible overpressuscenarios.


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This analysis shall utilize an organized, systematic processsafety analysis approach such as: a Hazards and Operabil-ity (HAZOP) review; a failure mode, effects and criticalityanalysis (FMECA); fault tree analysis; event tree analysis;what-if analysis, or other similar methodology.

Instrumentation associated with a HIPS shall be testedat regular intervals to ensure it functions per design.

Documentation of the HIPS system design and testing

shall be developed and maintained.The user shall consult ASME Section VIII, Division 1 (UG-

140) for the complete set of requirements for the use of HIPS asa means of overpressure protection.

Emergency Depressuring

Emergency depressuring system are commonly used innatural gas facilities. The system can be automatically actu-ated or operator actuated, on emergency shutdown of a pieceof equipment, a process unit, or an entire facility. The purposeof the depressurization system is one or more of the following:1) minimize risk of loss of containment due to fire/runaway re-action 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, orrelease of toxic gas due to partial or total seal/packing failure ofrotating equipment.

Depressurization systems are often used to prevent poten-tial stress rupture of a vessel when the metal temperature israised above the design temperature due to an abnormal heatsource. This source is usually from a fire, but could also be froma runaway exothermic reaction or other source of heat. Thistype of rupture can occur before a vessel reaches the set pres-sure of relief devices on the vessel. A general guideline is that adepressurization system should be able to reduce the pressurein the vessel to 50% of the design pressure in 15 minutes inthe event of a pool fire. However, the required depressurizationtime is dependent on the vessel material and wall thickness. Adetailed discussion of emergency depressurization design basis

is provided in ISO 23251 (API Std 521).

Another application for a depressurization system is to re-duce the consequences of a leak by quickly reducing the pres-sure of the system/plant/compressor. By reducing the equip-ment pressure, both the leak rate and the total inventory offluid leaked can be reduced. A general criterion for system de-pressurization is to reduce the pressure in the system to 690kPa (ga) in fifteen minutes or less.

For compressors, the depressurization time is partially afunction of the location of the machine, and de-pressurizationtimes of less than 15 minutes is often used. For compressorslocated in buildings, a depressurization time of 3-5 minutes tonear atmospheric pressure are not uncommon.

For each application, the designer must verify that all com-ponents (especially vessel internals and machinery elastomerseals) can withstand the chosen de-pressurization rate. In ad-dition, cold metal temperatures can be developed both in thesource vessel and the flare system during de-pressuring. Bothsystems must be designed for these conditions.

Note that the ASME Pressure Vessel Section VIII code re-quires a pressure relief device or HIPS to be installed to protectthe vessel even if a depressuring system is used.

Low Temperature Flaring

Natural gas plants frequently have more than one flaresystem. (i.e. high pressure flare, low pressure flare, cryogen-ic flare). The segregation of flare systems should be carefullyevaluated, based on the fluid compositions, temperatures, andallowable back pressures in the relief header. Several incidentshave raised industry awareness on the need to properly con-sider segregation of flare headers and systems.

When low temperature streams are relieved, the flare sys-tem piping and equipment exposed to cryogenic temperaturemay require stainless steel or other acceptable alloys. The sys-tem should be designed for the coldest process stream to be re-lieved including the cooling effect of the expanding fluid (Joule-Thomson effect). Materials selection should be made accordingto applicable code recommendations.

Industry experience has shown that formation of limited quan-tity of hydrates at a relief valve outlet can typically be handledsafely. However, relieving large amounts of hydrates, or solidCO2/H2S/ methane solids to a closed flare system should be avoid-ed. Industry experience has shown that pure CO2can be safelyvented to the atmosphere, utilizing proper design practices.

SET PRESSURE FOR PRESSURERELIEF VALVES

Fig. 5-2, extracted from ISO 23251 (API Std 521), shows thecharacteristics of safety relief valves for vessel protection. It canbe used as a general guide in determining the proper set pres-sure of a pressure relief valve, for a protected system. Refer tothe Standard for further guidance on setting single or multiplepressure relief valves.

RELIEVING DEVICES

Several pressure relief devices are certified and approvedunder Section VIII of the ASME Boiler and Pressure VesselCode covering unfired pressure vessels. They include springloaded direct-acting pressure relief valves, pilot operated pres-

sure relief valves, and rupture disks and shearing pin devices.When the governing code is ANSI B31.3 or ANSI B31.8, othertypes of pressure relieving devices such as monitoring regula-tors, 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 theservice and the overall design of the system. See ASME, Sec-tion I, for fired boiler relieving criteria.

Conventional Pressure Relief Valves

In a conventional pressure relief valve, the inlet pressure tothe valve is directly opposed by a spring. Tension on the springis set to keep the valve shut at normal operating pressure butallow the valve to open when the pressure reaches relievingconditions. This is a differential pressure valve. Most conven-

tional safety-relief valves available to the petroleum industryhave disks which have a greater area, AD, than the nozzle seatarea, AN. The effect of back pressure on such valves is illustrat-ed in Fig. 5-3b. If the bonnet is vented to atmospheric pressure,theback pressure acts with the vessel pressure so as to over-come the spring force, FS, thus making the relieving pressureless than when set with atmospheric pressure on the outlet.However, if the spring bonnet is vented to the valve dischargerather than to the atmosphere, the back pressure acts with the


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spring pressure so as to increase the opening pressure. If theback pressure were constant, it could be taken into account inadjusting the set pressure. In operation the back pressure is notconstant when a number of valves discharge into a manifold.

Acut-away of a conventional relief valve is shown inFig. 5-3a. Materials of construction for relief valves vary by service.

Balanced Pressure Relief Valves

Balanced safety-relief valves incorporate means for mini-mizing the effect of back pressure on the performance charac-teristics opening pressure, closing pressure, lift, and reliev-ing capacity.

These valves are of two types, the piston type and the bel-lows type. A cross section drawing of a balanced (bellows) reliefvalve is shown inFig. 5-4a. In the piston type, of which severalvariations are manufactured, the guide is vented so that theback pressure on opposing faces of the valve disk cancels itself;the top face of the piston, which has the same area, AP, as thenozzle seat area, AN, is subjected to atmospheric pressure byventing the bonnet. The bonnet-vented gases from balanced pis-ton-type valves should be disposed of with a minimum restric-tion and in a safe manner.

In the bellows type of balanced valve, the effective bellowsarea, AB, is the same as the nozzle seat area, AN, and, by at-tachment to the valve body, excludes the back pressure fromacting on the top side of that area of the disk. The disk area ex-tending beyond the bellows and seat area cancel, so that thereare no unbalanced forces under any downstream pressure. Thebellows covers the disk guide so as to exclude the working fluidfrom the bonnet. To provide for a possible bellows failure orleak, the bonnet must be vented separately from the discharge.The balanced safety-relief valve makes higher pressures inthe relief discharge manifolds possible. Balanced-type valvesshould have bonnet vents large enough to assure no appreciableback pressure during design flow conditions. If the valve is ina location in which atmospheric venting (usually not a largeamount) presents a hazard, the vent should be piped to a safelocation independent of the valve discharge system. The user

should obtain performance data on the specific type of valvebeing considered. A diagram of the force balance for piston andbellows balanced pressure relief valves is shown in Fig. 5-4b.

Pilot Operated Pressure Relief Valves

A pilot operated pressure relief valve consists of two princi-pal parts, a main valve and a pilot. The valve utilizes a pistoninstead of a shaft. Inlet pressure is directed to the top of themain valve piston. More area is exposed to pressure on the topof 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 themain valve to open fully. For some applications, pilot-operatedrelief valves are available in minimum friction, light-weightdiaphragm construction (in place of heavy pistons).

Pilot operated valves can allow backflow if downstreampressure exceeds set points. Backflow prevention is requiredon valves, connected to common relief headers, where protectedequipment can be depressured and isolated while connected toan active flare header, where a vacuum could occur at the inlet,or where the downstream is connected to a system or vesselwhere the pressure could exceed the inlet pressure.

A check valve, split piston type valve, or backflow preventerin the pilot line can be used.

Atypical pilot operated relief valve is shown in Fig. 5-5. Poperated valves may be used in liquid or vapor services. Thvalves contain nonmetallic components (elastomers), thereffluid pressure and temperature, fluid characteristics, polymization, fouling, solids, and corrosion can limit their use.

Pilot operated valves are available with snap-action or mulating action. The modulating type relieves only the amounfluid required to control the overpressure.

When specifying pilot operated pressure relief valves, telastomers chosen for the o-rings, and seals should be carefuconsidered. Temperature (maximum and minimum), chemicompatibility (for the principle and trace components, and potential liquid carryover), and resistance to explosive de-copression, are all factors in the choice of elastomers.

Seat Leakage, and Resilient

Pressure Seat Relief Valves

Some leakage can be expected through the seats of with mal-to-metal seated, conventional or balanced type relief valvwhen the operating pressure rises too close to the set pressu

Allowable seat leakage rates are specified in API Std 527.16 Rsilient seat pressure relief valves (see Fig. 5-6), with eitherO-ring seat seal or a plastic seat, can provide seat integrit

which are significantly higher than metal seated valves. AStd 52716specifies that, soft seated, pressure relief valves shhave zero bubbles/minute leakage at the same test pressuresmetal seated valves. This can allow bubble tight operation90%, of the set pressure, or higher. Proper elastomer choicecritical for resilient seat pressure relief valves.

Vapor Trim vs. Liquid Trim

For Pressure Relief Valves

Pressure relief valves handling gas or vapor are supplwith vapor trim. Valves which releive liquid, two-phase, or tentially two-phase fluids, require a liquid trim. It is importathat the supplier is properly informed of the full range of expeed operation when procuring pressure relief valves. In additi

liquid trim pressure relief valves have a significantly highblowdown as compared to vapor trim. In these applications tdesigner must be prudent to allow sufficient pressure margbetween the operating pressure and the relief valve set prsure to ensure reclosure of the valve following a relief event

Rupture Disk

A rupture disk consists of a thin diaphragm held betweflanges. The disk is designed to rupture and relieve pressuwithin tolerances established by ASME Code Section VIII. Rture disks can be used in gas processing plants, upstreamrelief valves, to reduce minor leakage and valve deterioratiIn these installations, the pressure in the cavity between trupture disk and the relief valve should be monitored to deta ruptured or leaking disk. In some applications a rupture d

with a higher pressure rating is installed in parallel to a revalve.

Rupture disks should be used as the primary relieving vice only if using a pressure relief valve is not practical. Soexamples of such situations are:

(a) Rapid rates of pressure rise. A pressure relief valve stem does not react fast enough or cannot be made larenough to prevent overpressure (e.g., an exchanger rutured tube case or a runaway reaction in a vessel).


8/26

5-8

(b) Large relieving area required. Because of extremelyhigh flow rates and/or low relieving pressure, providingthe required relieving area with a pressure relief valvesystem is not practical.

(c) A pressure relief valve system is susceptible to beingplugged, and thus inoperable, during service.

All rupture disks have a manufacturing design range (MDR),which essentially specifies the users tolerancefor variations in

the burst pressure. Furthermore, disk temperature can have asignificant affect on the pressure at which the disk will open.Therefore, it is essential that the designer communicate the de-sired MDR and the full range of expected operating and relieftemperatures when specifying requirements for a rupture disk.This will help ensure that the disk ruptures and provides relief

flow at the desired pressure rather than at a pressure higher orlower than the stamped pressure.

A rupture disk is subject to fatigue failure due to operatingpressure cycles. To establish recommended replacement inter-vals, consult rupture disk suppliers.

Shearing Pin Device (Rupture Pin)

A shearing pin device is a non-closing pressure relief-device

actuated by differential pressure, or static inlet pressure, de-signed to function by the shearing of a load-carrying memberthat supports a pressure-containing member. The devices aresanctioned by ASME Section VIII, and may be used for circum-stances where rupture disks may also be appropriate. Theyhave the advantage that the pin can be replaced without re-moving a piping flange.

FIG. 5-2

Pressure Level Relationships for Pressure Relief Valves14

Courtesy American Petroleum Institute


9/26

5-9

FIG. 5-4a

Balanced Bellows Pressure Relief Valve14

FIG. 5-4b

Effect of Back Pressure on Set Pressure ofBalanced Pressure Relief Valve14

FIG. 5-3b

Effect of Back Pressure for ConventionalPressure Relief Valve14

FIG. 5-3a

Conventional Pressure Relief Valve14

Courtesy of American Petroleum Institute

Courtesy of American Petroleum Institute

Courtesy of American Petroleum InstituteCourtesy of American Petroleum Institute


10/26


11/26

5-11

SIZING OF RELIEF DEVICES

After the required relief capacity of a relief valve has beendetermined, the minimum orifice area required must be calcu-lated. Industry standards for orifice designation, orifice area,valve dimensions, valve body sizes, and pressure ratings areavailable. The standard orifices available by letter designa-tion, orifice area, and valve body size are shown in Fig. 5-7.

In addition to the standard sizes, many relief valves are

manufactured with orifice areas smaller than D, and somepilot-operated relief valves contain orifice areas larger thanT. Manufacturers should be contacted for information on non-standard sizes.

The set pressure and the overpressure allowed must be with-in the limits permitted by the applicable codes. System analysismust include downstream piping. For example, consider the useof a relief valve made for a vessel with a maximum allowableworking pressure of 1000 kPa (ga). The relief valve set pressureis 1000 kPa (ga), and the maximum allowable overpressure is10% [100 kPa (ga)]. The vessel pressure, when relieving, mustbe limited to 1100 kPa (ga) [1000 kPa (ga) set pressure plus 100kPa (ga) maximum overpressure]. Pressure buildup downstreamof the relief valve should never cause the vessel pressure to ex-ceed the maximum allowable overpressure.

API vs. Pressure Relief Valve Supplier

Discharge Coefficient/Orifice Area

API Std 520 Part I (clause 5.2)14 provides a thorough discus-sion of the distinctions between the API effective area and theactual flow area of a pressure relief valve, as well as those be-tween the API effective coefficient of discharge and the ASMEcertified coefficient of discharge. The designer is cautioned nev-er to mix the API effective orifice area and discharge coefficientwith the certified values of these parameters. Furthermore,final selection of pressure relief valve and sizing of associated(inlet/outlet) piping should always use the certified values.

Sizing for Gas or Vapor Relief

The rate of flow through a relief valve nozzle is dependenton the absolute upstream pressure (as indicated in Equation 5-1, Equation 5-2, and Equation 5-3) and is independent of thedownstream pressure as long as the downstream pressure isless than the critical-flow pressure (See API Std 520-1). Howev-er, if the downstream pressure increases above the critical-flowpressure, the flow through the relief valve is materially reduced(e.g., when the downstream pressure equals the upstream pres-sure, there is no flow).

The critical-flow pressure, PCF, may be estimated by the per-fect gas relationship shown in Equation 5-5.

As a rule of thumb if the downstream pressure at the reliefvalve is greater than one-half of the valve inlet pressure (bothpressures in absolute units), then the relief valve nozzle will

experience subcritical flow.

Critical Flow Safety valves in gas or vapor service maybe sized by use of one of these equations:14

A = 131.6W

(T1) (Z)

(C1) (Kd) (P1) (Kb) (Kc) MW

Eq 5-1

A = 5.875Qv

(T1) ( MW) (Z)

(C1) (Kd) (P1) (Kb) (Kc)Eq 5-2

C1 = 520

Eq 5 2 k + 1

k k + 1

k 1

C1 can be obtained from Figs. 5-8, and 5-9. Note that idealgas specific heat ratio k = Cp/Cv has to be used for tdetermination of C1in Equation 5-3. The ideal gas specific hratio is independent of pressure. The heat capacity ratio usshould be based on the upstream relieving temperature. Nthat most process simulators will provide real gas specific he

at the process pressure and temperature. These should notused in the above equation because if this value is used, tpressure relief device may be undersized. For real gases wa compressibility of less than 0.8 or greater than 1.1, API S520 Part I states that use of the ideal gas specific heat racan introduce significant error, and a more thermodynamicasound approach should be considered.14The Theoretical MFlux Isentropic Expansion Method as described in API Std 5Part I provides this foundation.

Kbcan be obtained fromFigs. 5-10and 5-11. For final sign, Kd should be obtained from the valve manufacturervalue for Kdof 0.975 may be used for preliminary sizing.

Subcritical Flow For downstream pressures, P2, in cess of the critical-flow pressure, PCF, the flow through the pr

sure relief valve is subcritical. Under these conditions, Equat5-414may be used to calculate the required effective dischaarea for a conventional relief valve that has its spring settiadjusted to compensate for superimposed backpressure, or fopilot operated relief valve.

= 0.179 W

A Z T1

Eq 5 (F2) (Kd Kc)

MW (P1) (P1 P2)

F2is taken fromFig. 5-12.

PCF = P1Eq 5 2

k

k + 1k 1

Balanced pressure relief valves should be sized using Equat5-1 or Equation 5-2 and the back pressure correction factor su

plied by the valve manufacturer.

Sizing for Steam Relief

Safety-relief valves in steam service are sized by a mofication of Napiers steam flow formula. Valve manufacturcan supply saturated steam capacity tables. A correction ftor, Ksh, must be applied for safety valves in superheated steservice.

For safety-relief valves in steam service, the required armay be estimated from the following equations from the ASMCode Section VIII, Div. 1 and API-520-1:14

A = (1.905) W

(P1) (Ksh) KdKbKcKnEq 5

Kn = 1 for P1< 10 339 kPa (abs)

Kn =0.02764 P1 1000

0.03324 P1 1061

Eq 5

for P1> 10 339 kPa (abs) and 22 057 kPa (abs), Kn= 1.0 whP1 13 339 kPa (abs).

See Fig. 5-13forsuperheat correction factors. For saturasteam at any pressure, Ksh= 1.0.


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5-12

Sizing for Liquid Relief

Turbulent Flow Conventional and balanced bellows re-lief valves in liquid service may be sized by use of Equation 5-8.14 Pilot-operated relief valves should be used in liquid serviceonly when the manufacturer has approved the specific applica-tion.

A = (7.07) (Vl)

G

(Kd) (Kc) (Kw) (Kv) (P1 Pb)

Eq 5-8

Laminar Flow For liquid flow with Reynolds numbersless than 4,000, the valve should be sized first with Kv= 1 inorder to obtain a preliminary required discharge area, A. Frommanufacturer 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 A

(511 300) (l/s)Re = Eq 5-10 S

A

After theReynolds number is determined, the factor Kv isobtained from Fig. 5-15. Divide the preliminary area (A) by Kvto obtain anarea corrected for viscosity. If the corrected areaexceeds the standard orifice area chosen, repeat the procedureusing the next larger standard orifice.

Sizing for Thermal Relief

The following may be used to approximate relieving rates ofliquids expanded by thermal forces where no vapor is generatedat relief valve setting and maximum temperature.These calcu-lations assume the liquid is non-compressible.13

(B) (Q)Vl = Eq 5-11 1000 (G) (S)

Typical values of the liquid expansion coefficient, B, at 15Care:

API

GravityRelative Density, G

Liquid Expansion

Coefficient, B, 1/C

Water 1.000 0.00018

3 - 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 radia-tion, the surface area of the item or line in question should becalculated. Solar radiation [typically 7871040 W/m2] should be

determined for the geographic area and applied to the surfacearea to approximate Q (W).

When the flow rate is calculated, the necessary area for re-lief 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 phenom-

enon limits the flow through the pressure relief valve nozzle, ina manner similar to the choking of a gas in critical flow. In orderto estimate the relief capacity of a nozzle, it is necessary to es-timate the choking pressure and then determine the two phasephysical properties at these conditions. The historical methodof calculating areas for liquid and vapor relief separately, andthen adding the two areas together to get the total orifice sizedoes not produce a conservative relief device size.

Improved sizing methods have been developed using the fol-lowing assumptions:

The fluid is in thermodynamic equilibrium through thenozzle.

The overall fluid is well mixed and can be represented byweighted averaging the gas and liquid densities (this issometimes referred to as the non-slip assumption).

Use of these assumptions has been found to produce a resultwhich in most instances is close to the real flow rate through thenozzle, and which almost always will result in a conservativecalculation of the required nozzle area. However, these methodsrequire additional equilibrium data along the isentropic expan-sion path through the relief valve. Refer to API Std 520, Part1, for a description of the sizing methods for two-phase liquidvapor relief. Two methods are described in API Std. 520, Part1, Annex C; the Omega method and the Mass FluxIsentropicExpansion Method.14

Sizing for Fire for Partially

Liquid Filled Systems

The method of calculating the relief rate for fire sizing maybe obtained from ISO 23251 (API Std 521), API Standard 2510,NFPA 58, and possibly other local codes or standards. Each ofthese references approach the problem in a slightly differentmanner. Note that NFPA-58 applies only to U.S. marine termi-nals, or U.S. terminals at the end of DOT regulated pipelines.

Most systems requiring fire relief will contain liquids and/orliquids in equilibrium with vapor. Fire relief capacity in thissituation is equal to the amount of vaporized liquid generatedfrom the heat energy released from the fire and absorbed by theliquid containing vessel. The difficult part of this procedure isthe determination of heat absorbed. Several methods are avail-able, including ISO/API, and U.S. National Fire Protection As-sociation. ISO 23251 (API Std 521) applies to the Petroleum

and Natural Gas Industries, and is the standard most common-ly used to assess fire heat load in these services.

ISO 23251/API Std 52113expresses relief requirements interms 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 determinedfrom Fig. 5-16. Credit for insulation can be taken only if the in-sulation system can withstand the fire and the impact of water


13/26

5-13

from a fire hose. Specific criteria are provided in ISO 23251/API Std 521. The appropriate equation to use where adequatedrainage and fire fighting equipment do not exist is also pro-vided in this Standard.

Awin equation 5-12 is the total wetted surface, in square me-ters. Wetted surface is the surface wetted by liquid when the ves-sel is filled to the maximum operating level. It includes at leastthat portion of a vessel within a height of 8 m above grade. Inthe case of spheres and spheroids, the term applies to that por-

tion of the vessel up to the elevation of its maximum horizontaldiameter or a height of 8 m, whichever is greater. Grade usuallyrefers to ground grade but may be any level at which a sizablearea of exposed flammable liquid may be present.

The amount of vapor generated is calculated from the latentheat of the material at the relieving pressure of the valve. Forfire relief only, this may be calculated at 121% of maximumallowable working pressure. All other conditions must be cal-culated at 110% of maximum allowable working pressure forsingle relief devices.

Latent heat data may be obtained by performing flash calcu-lations. Mixed hydrocarbons will boil over a temperature rangedepending on the liquid composition; therefore, considerationmust be given to the condition on the batch distillation curve

which will cause the largest relief valve orifice area require-ments due to the heat input of a fire. Generally the calculationis continued until some fraction of the fluid is boiled off. Otherdynamic simulation methods are also available. The latent heatof pure and some mixed paraffin hydrocarbon materials may beestimated using Fig. A.1 of ISO 23251 / API Std 521.13

When the latent heat is determined, required relieving ca-pacity may be found by:13

W = Q / Hl Eq 5-13

The value W is used to size the relief valve orifice usingEquation 5-1 or Equation 5-4.

For vessels containing only vapor, ISO 23251 (API Std 521)13has recommended the following equation for determining re-

quired relief area based on fire:

183.3 (F) (A3)A = Eq 5-14 P1

F can be determined using Equation 5-15.13If the result isless than 0.01, then use F = 0.01. If insufficient information isavailable to use Equation 5-15, then use F = 0.045.

F = 0.1406 (Tw T1)1.25 Eq 5-15

(C1) (Kd) T10.6506 To take credit for insulation, ISO 23251 (API Std 521) re-

quires the insulation material to function effectively at tem-peratures of 900C, and to retain its shape, and most of its in-

tegrity in covering the vessel in a fire, and during fire fighting.Typically, this requires proper insulation, plus an insulationjacket constructed of a suitable material, and banding that canwithstand the fire conditions. However, other systems may beable to meet these requirements.

Sizing for Fire for Liquid

Full or Nearly Full Equipment

For totally or near totally liquid filled systems, the control-ling relief condition can be single vapor phase, liquid phase, ortwo phase, depending on the fluid, liquid level, vessel size and

configuration, and location of the relief device. For many gplant applications, the assumption of single phase vapor reis adequate for pressure relief valve sizing. See ISO 23251 (AStd 521) for further guidance.

Sizing for Fire For Supercritical Fluids

Sometimes, the phase condition at the relieving pressure atemperature will be supercritical. API recommends to consia dynamic approach where the vessel contents are assumed

be single phase (supercritical), and a step by step heat fluxapplied to the vessel walls [See ISO 23251 (API Std 521),] aOuderkirk10for details. The same methodology can also be plied for gas filled systems.

Heavy hydrocarbons can be assumed to crack (i.e., to thmally decompose), and it is the users responsibility to estimthe effective or equivalent latent heat for these applicatioTraditionally, a minimum latent heat value of 116 kJ/kg hbeen used if the conditions can not be quantified.

When a vessel is subjected to fire temperatures, the resultmetal temperature may greatly reduce the pressure rating of vessel, in particular for vessels in vapor service. Design for tsituation should consider an emergency depressuring systand/or a water spray system to keep metal temperatures coo

For additional discussion on temperatures and flow rates duedepressurization and fires refer to Reference 7.

RELIEF VALVE INSTALLATION

Relief valve installation requires careful considerationinlet piping, pressure sensing lines (where used), and startprocedures. Poor installation may render the safety relief vainoperable or severely restrict the valves relieving capaciEither condition compromises the safety of the facility. Marelief valve installations have block valves before and after trelief valve for in-service testing or removal; however, theblock valves must be sealed or locked open, and administratcontrols must be in place, to prevent inadvertent closure.

Inlet PipingThe proper design of inlet piping to safety relief valves

extremely important. Relief valves should not be installedphysically convenient locations unless inlet pressure losses agiven careful consideration. The ideal location is the direct cnection to protected equipment to minimize inlet losses. ASTD 520, Part II recommends a maximum non-recoverapressure loss to a relief valve of three percent of set pressuexcept for remote sensing pilot-operated pressure relief valvThis pressure loss shall be the total of the inlet loss, line loand the block valve loss (if used). The loss should be calculausing the maximum rated flow through the safety relief valv

Discharge Piping and Backpressure

Proper discharge and relief header piping size is critical the functioning of a pressure relief valve. Inadequate piping cresult in reduced relief valve capacity, cause unstable opetion, and/or, relief device damage.

The pressure existing at the outlet of a pressure relief vais defined as backpressure. Backpressure which is presentthe outlet of a pressure relief valve, when it is required to erate, is defined as superimposed backpressure. Backpressuwhich develops in the discharge system, after the pressure lief valve opens, is built-up backpressure. The magnitudepressure which exists at the outlet of the pressure relief val


14/26

5-14

OrificeAreacm2

OrificeArea(in.2)

D 0.710 0.110

StandardOrificeDesignation

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. 1 2 1.5 2 1.5 3 2 3 3 4 3 6 4 6 6 8 6 10 8 10

mm 25 50 38 50 38 75 50 75 75 100 75 150 100 150 150 200 150 250 200 250

Valve Body Size (Inlet Diameter times Outlet Diameter)

FIG. 5-7

API Pressure Relief Valve Designations

k C1

0.4 216.9274

0.5 238.8252

0.6 257.7858

0.7 274.5192

0.8 289.494

0.9 303.0392

1.0 315.37*

1.1 326.7473

1.2 337.2362

1.3 346.9764

1.4 356.0604

1.5 364.5641

1.6 372.5513

1.7 380.0755

1.8 387.1823

1.9 393.9112

2.0 400.2962

2.1 406.3669

2.2 412.1494

*Interpolated values since C1becomes indeterminate as k approaches 1.00

Note: Calculated from Eq. 5-3.

FIG. 5-8

Values of Coefficient C1 vs. k

Mol mass k C1

Acetylene 26 1.28 345

Air 29 1.40 356

Ammonia 17 1.33 351

Argon 40 1.66 377

Benzene 78 1.10 327

Carbon disulfide 76 1.21 338Carbon dioxide 44 1.28 345

Carbon monoxide 28 1.40 356

Chlorine 71 1.36 352

Cyclohexane 84 1.08 324

Ethane 30 1.22 339

Ethylene 28 1.20 337

Helium 4 1.66 377

Hexane 86 1.08 324

Hydrochloric acid 36.5 1.40 356

Hydrogen 2 1.40 356

Hydrogen sulfide 34 1.32 348

Iso-butane 58 1.11 328

Methane 16 1.30 346Methyl alcohol 32 1.20 337

Methyl chloride 50.5 1.20 337

N-butane 58 1.11 328

Natural gas 19 1.27 345

Nitrogen 28 1.40 356

Oxygen 32 1.40 356

Pentane 72 1.09 325

Propane 44 1.14 331

Sulfur dioxide 64 1.26 342

FIG. 5-9

Values of C1for Various Gases


15/26


16/26

5-16

Set

Pressure

kPa (ga)

Total Temperature Superheated Steam, C

149 204 260 316 371 427 482 538 593 649

Correction Factor, Ksh

100 1 0.98 0.93 0.88 0.84 0.8 0.77 0.74 0.72 0.7

140 1 0.98 0.93 0.88 0.84 0.8 0.77 0.74 0.72 0.7

275 1 0.99 0.93 0.88 0.84 0.81 0.77 0.74 0.72 0.7

415 1 0.99 0.93 0.88 0.84 0.81 0.77 0.75 0.72 0.7

550 1 0.99 0.94 0.88 0.84 0.81 0.77 0.75 0.72 0.7

690 1 0.99 0.94 0.89 0.84 0.81 0.77 0.75 0.72 0.7830 1 0.99 0.94 0.89 0.84 0.81 0.78 0.75 0.72 0.7

970 1 0.99 0.94 0.89 0.85 0.81 0.78 0.75 0.72 0.7

1 100 1 0.99 0.94 0.89 0.85 0.81 0.78 0.75 0.72 0.7

1 250 1 0.99 0.94 0.89 0.85 0.81 0.78 0.75 0.72 0.7

1 380 1 0.99 0.95 0.89 0.85 0.81 0.78 0.75 0.72 0.7

1 520 1 0.99 0.95 0.89 0.85 0.81 0.78 0.75 0.72 0.7

1 660 1 0.95 0.9 0.85 0.81 0.78 0.75 0.72 0.7

1 790 1 0.95 0.9 0.85 0.81 0.78 0.75 0.72 0.7

1 930 1 0.96 0.9 0.85 0.81 0.78 0.75 0.72 0.7

2 070 1 0.96 0.9 0.85 0.81 0.78 0.75 0.72 0.7

2 410 1 0.96 0.9 0.86 0.82 0.78 0.75 0.72 0.7

2 760 1 0.96 0.91 0.86 0.82 0.78 0.75 0.72 0.7

3 450 1 0.96 0.92 0.86 0.82 0.78 0.75 0.73 0.7

4 140 1 0.97 0.92 0.87 0.82 0.79 0.75 0.73 0.75 520 1 0.95 0.88 0.83 0.79 0.76 0.73 0.7

6 900 1 0.96 0.89 0.84 0.78 0.76 0.73 0.71

8 620 1 0.97 0.91 0.85 0.8 0.77 0.74 0.71

10 350 1 0.93 0.86 0.81 0.77 0.74 0.71

12 070 1 0.94 0.86 0.81 0.77 0.73 0.7

13 790 1 0.95 0.86 0.8 0.76 0.72 0.69

17 240 1 0.95 0.85 0.78 0.73 0.69 0.66

20 690 1 0.82 0.74 0.69 0.65 0.62


FIG. 5-13

Superheat Correction Factors for Pressure Relief Valves in Steam Service14

FIG. 5-12

Values of F2for Subcritical Flow14



17/26

5-17

FIG. 5-14

Back-Pressure Sizing Correction Factor Kwfor 25 Percent Overpressure on BalancedBellows 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.


FIG. 5-15

Capacity Correction Factor Due to Viscosity for Liquid Phase Pressure Relief14

Courtesy American Petroleum Institut


18/26

5-18

after it is opened, is the total of the super imposed and built-upbackpressure, and is commonly referred to a total backpres-

sure.

The total backpressure, for all pressure relief valve styles,can affect the capacity of the valve. For gas service the capacitywill be affected if the flow through the valve is sub-critical. Forliquid service the outlet backpressure will directly affect the ca-pacity. This is shown by Equations 5-2 through 5-10.

For a conventional (spring loaded) pressure relief valve, su-per imposed backpressure at the outlet of the valve acts to holdthe valve disc closed with a force additive to the spring force(see Fig. 5-3b). The pressure relief valve set pressure is essen-tially increased by the amount of super imposed backpressurepresent.

Conventional spring loaded pressure relief valves exhibit

unacceptable performance (unstable operation, and possiblechatter), when excessive backpressure develops during a reliefincident due to the flow through the valve and outlet piping.For this reason API-520-1 specifies that the built-up backpres-sure for conventional pressure relief valves should not exceed10% of the set pressure, at 10% allowable overpressure (processrelief scenarios).14Higher allowable built-up backpressure maybe acceptable for other, allowable overpressures (see API-520-1for specifics).

A balanced pressure relief valve, Fig. 5-4a and 5-4b, can beapplied where the built-up backpressure is toohigh for a con-ventional pressure relief valve, and/or the superimposed or to-tal backpressure is unacceptable for a conventional valve. Thebalanced style can typically be used up to a total backpressureof 50% (consult with manufacturer for specific limits). The set

pressure for a balanced pressure relief valve is not affected bysuperimposed backpressure. The capacity of a balance pressurerelief valve, however, can be affected by total backpressure, dueto a reduction in lift caused by a closing force on the unbalanceportionof the disk at high backpressure. See Figs. 5-11 and5-14 for typical capacity correction factors for gas and liquidservicefor 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 mostapplications the performance of pilot operating pressure reliefvalves it not affected by either superimposed or built-up back-pressure. The relief valve capacity can be affected if the flowbecomes sub-critical for gases, or due to reduced pressure dropavailable for liquids. In addition, if the discharge pressure canexceed the inlet pressure (e.g., tanks storing low vapor pressurematerial), a back-flow pre-venter is required for pilot operatedpressure relief valve.

Pressure relief valve discharge piping must be at least thesame diameter as the valve outlet, but generally must be largerto minimize backpressure.

Reactive Force

On high pressure valves, the reactive forces during relief aresubstantial and external bracing may be required. See equa-tions in API RP 520-II for computing this force.

Rapid Cycling

Rapid cycling can occur when the pressure at the valve inletdecreases at the start of relief valve flow because of excessivepressure loss in the piping to the valve, or excessive back-pres-sure.

Pressure relief valves are designed with a given blow-down(difference between the set pressure and closing pressure of apressure relief valve), that is adjustable within limits. Underconditions of high inlet loss, the valve may cycle at a rapid ratewhich is referred to as chattering. Rapid cycling reduces capac-ity and is destructive to the valve seat, subjects all the movingparts in the valve to excessive wear, and can induce potentiallydestructive vibration in the piping system. The valve respondsto the pressure at its inlet. If the pressure decreases during flowto below the valve reseat point, the valve will close; however, assoon as the flow stops, the inlet pipe pressure loss becomes zeroand the pressure at the valve inlet rises to relieving pressureonce again. If the vessel pressure is still equal to or greater thanthe relief valve set pressure, the valve will open and close again.The mechanism of chatter is complicated and not uniquely as-

sociated with inlet pressure loss. However, experience hasshown that chattering can be prevented if the non-recoverableinlet pressure loss is limited to 3% of the set pressure. Excessiveback-pressure for conventional and balanced-bellows pressurerelief valves can also cause chatter, and must be avoided. Anoversized relief valve may chatter since the valve may quicklyrelieve enough contained fluid to allow the vessel pressure tomomentarily fall back to below set pressure only to rapidly in-crease again. In some cases multiple relief valves, may be pre-ferred, depending on the relief contingencies.

Resonant Chatter

Resonant chatter can occur with pressure relief valves whenthe inlet piping produces excessive pressure losses at the valveinlet and the natural acoustical frequency of the inlet piping ap-proaches the natural mechanical frequency of the valves basicmoving parts. The higher the set pressure, the larger the valvesize, or the greater the inlet pipe pressure loss, the more likelyresonant chatter will occur. Resonant chatter is uncontrollable;that is, once started it cannot be stopped unless the pressure isremoved from the valve inlet. In actual application, however, thevalve can self-destruct before a shutdown can take place becauseof the very large magnitude of the impact forces involved.

FIG. 5-16

Fire Sizing Environmental Factors

Environment1 F Factor

Bare metal vessel 1.0

Insulation Note 2

Water-application facilities 1.0

Depressuring facilities 1.0

Underground storage 0.0

Earth-covered storage 0.03

Notes:

1See ISO 23251 (API Std 521) for appropriate use of these environmental

factors.

2See ISO 23251 (API Std 521) for the equations to use if insulation credit

is taken.


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DESIGN OF RELIEF SYSTEM TO FLARE

Grouping of Systems

The first step in designing a flare system for a facility is todetermine the number of segregated vent and flare headers, ifmore than one, which are required. Depending on plot plan, therange of equipment design pressures, desirability of isolatingcertain streams, temperature of the relief streams, possibility ofliquid carryover, heating value of the streams, and quantities of

the relief streams, it may prove desirable to provide two or moresegregated headers to the flare K.O. drum, or even to use totallyindependent flare systems. Separation of high pressure and lowpressure headers, or low-temperature and wet headers, is notuncommon. Some large integrated gas treating facilities have ahigh pressure, low pressure, and a cryogenic flare.

Load Determination

The first step in determining controlling loads for a reliefheader and flare system is to identify the credible major flar-ing scenarios. These scenarios may be associated with pressurerelief, emergency depressuring, or transitory operating (e.g.,startup, shutdown, etc.) events. A case may be controlling be-cause of the back-pressure it will generate in the relief header,the heat release at the flare stack, or the nature of the fluid tobe flared (i.e. low heating value, composition of the fluid, lowtemperature, high liquid flow rate, etc.). This analysis may in-clude dividing the plant into fire zones (fire zone size is dis-cussed in ISO 23251 (API Std 521), identifying large individualprocess relief loads, identifying common mode process failureloads, identifying common mode local or plant wide utility fail-ure, identifying which process valves that discharge to the flaremay already be open when an upset occurs (e.g., during startupor shutdown), identifying maximum depressurization rates,and identifying possible common events of pressure relief andventing or depressurization.

Some favorable instrument response may be included in thedesign of flare systems. ISO 23251 (API Std 521), Fifth Editionstates, Although favorable response of conventional instrumen-

tation should not be assumed when sizing individual processequipment pressure relief, in the design of some componentsof a relieving system, such as the blow-down header, flare, andflare tip, favorable response of some instruments can be as-sumed. In practice, the relief system design basis should bethoroughly analyzed using appropriate methodology (i.e. layersof protection analysis, SIL review, quantitative method), beforecredit is taken. The basis of the flare design load determinationshould be part of the plant formal hazard review.

For gas plants, another key decision is whether to designthe flare system for the maximum inlet flow of the productionheader or inlet pipeline, or instead rely on a shutdown systemat the plant inlet, and/or an automatic or manual well shut-in.Provisions also may be needed to allow venting some or all ofthe produced gas to the flare on facility start-up, pipeline de-

pressurization, or during an emergency in one process unit.

Flare Location

After the load is determined, it is necessary to decide on thelocation of the flares, and size of the headers and flare lines. Lo-cation and height of the flares must consider flare stack height,thermal radiation, emissions during flaring, ground level con-centrations in case of a flame-out, consequences of liquid car-ryover, and noise. Frequently, the controlling criterion for flarelocation is the minimum distance to continuously operatingequipment, which may require maintenance.

Back Pressure Consideration

The next step in the analysis involves setting a preliminmaximum back pressure for the system at various locationsthe flare system, and choosing between conventional, pilot erated, or balanced pressure relief valves for the various restations. A pressure relief device inventory should be preparsummarizing set pressure, estimated relieving temperatuand approximate capacity, if available. The flare style shoube considered, as well as the maximum pressure expected

the flare base.

Pressure relief valves that can tolerate higher back pressu(e.g., balanced or pilot operated pressure relief valves) mayselected if the back pressure is too high for conventional prsure relief valves. Excessive built-up back pressure will affthe operation of conventional pressure relief valves; high supimposed back pressure will affect the set point of these valve

Flare Header Sizing Methods

Line sizing for flare headers and relief lines requires tuse of compressible flow equations. Computer programs normally used to size flare headers and to calculate the bapressure at the relief devices. The header sizes are checked the major relief scenarios and then fixed. Based on these hea

sizes, each pressure relief device is checked for proper stybackpressure, and the effect of other devices on the set prsure and operation of the valve. API RP 520-II requires that tpressure relief valve inlet and outlet piping be sized for the red relief device capacity for all devices except modulating pioperated relief valves, while header systems may be sized usthe required capacity of the controlling scenario(s). A manusizing method is outlined below:

1. Start at the flare tip, where the outlet pressure is atmpheric, use design flows and work toward the individurelief valves (pressure drop across the tip will vary withe style of the flare and available system pressure dr

check with the tip manufacturer).

2. Establish equivalent pipe lengths between points in t

system and establish losses through fittings, expansioand contraction losses.

3. Many users limit the maximum allowed velocity at apart of the flare system to Mach 0.7. This limit is intened to minimize the possible effects of acoustically or flinduced vibration on the piping in the flare system. Modetailed methods to evaluate these effects are presentin references 8 and 9.

4. Estimate properties of gases in the headers from the flowing mixture relationships (i indicates the ith comnent).

MW = Wi/ (W / MW)i Eq 5-

T = WiTi/ Wi Eq 5-

= xii(MW)i0.5/ xi(MW)i0.5 Eq 5-

5. Calculate the inlet pressure for each section of the liby adding the calculated pressure drop for that sectionthe known outlet pressure.

6. Calculate sections of pipe individually using the inpressure of a calculated section as the outlet pressure the new section.

7. Continue calculations, working towards the relief vaor other flow source.


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8. Check calculated maximum superimposed backpressure,built-up backpressure, and total back pressure at the re-lief valve against piping design pressure and the maxi-mum allowable back pressure (MABP) of the flow source.See Discharge Piping and Backpressure, in this sectionfor a definition of these terms, and API Std 520-I for maxi-mum allowable values.

9. Adjust line size of headers until the calculated back pres-sure 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 whichassume isothermal flow in the flare header. This is adequate formost uses; however, if the actual flow condition differs greatlyfrom isothermal, the use of more complex equations and meth-ods is required to predict pressure and more accurately andtemperature profiles for the headers.

The choice of piping material other than carbon steel maybe dictated by temperatures and pressures in some parts of theflare system. Flare systems relieving fluids that produce cryo-genic temperatures may require special metallurgy.

Flare Knockout Drums

Gas streams from reliefs are frequently at or near their dewpoint, where condensation may occur, and some systems mayrelieve liquids or two-phase fluids in an overpressure event.

A knockout drum is usually provided near the flare base, andserves to recover liquid hydrocarbons or water, prevent liquidslugs, and remove large (300600 micron diameter and larger)liquid particles. The knockout drum reduces hazards caused byburning liquid that could escape from the flare stack. All flarelines should be sloped toward the knockout drum to permit con-densed liquid to drain into the drum for removal. Liquid trapsin flare lines should be avoided. If liquid traps are unavoidable,a method for liquid removal should be provided. The location ofthe flare knockout drum also needs to take into account radia-tion effect from the burning flare. Typically these drums arelocated between the flare and the process area, where the maxi-mum flare radiation exposure may be higher than allowable for

continuously operating equipment, but reasonable enough toallow properly trained personnel appropriate time to leave ina major flaring event.

Knockout drums may be vertical external to the flare stack,built into the bottom of a self supporting flare stack, or hori-zontal external to the flare stack. Internals which may breakfree and block the relief path are not allowed in a flare knockout drum.

Additional material on design and sizing for flare knock outdrums, including sizing examples are provided in ISO 23252(API Std 521).

Flare Seals and Flare System Purging

A seal is provided in the flare system between the knockoutdrum and the flaretip to prevent flashbacks due to air ingress.,which can result in a sudden substantial increase in pressure inthe flare system, and potential damage. Several types of sealscan be used: 1) a water seal drum, 2) a molecular purge reduc-tion seal (buoyancy seal), or 3) a velocity purge reduction seal.

A water seal drum is almost always installed in refineryflare systems, and is sometimes used in natural gas processingplants. It separates the flare system from the flare stack andprovides a water barrier which is capable of stopping flashback.

A molecular purge reduction seal is a seal device, installed ina flare stack, which uses the difference in relative molecularmasses of purge gas and infiltrating air to reduce the rate atwhich air will enter the stack. A velocity seal is a purge reduc-tion seal which operates on the principle that air infiltratingthe stack counter to the purge flow hugs the inner wall of theflare tip. The seal looks like one or more orifices located be-low the flare tip, which forces the air to the center of the stackwhere 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 do not stop flash-back, but rather minimize the chances that the air concentra-tion below the flare tip becomes high enough to support flash-back. These devices reduce the flow rate of purge gas whichotherwise would be required to accomplish this. The minimumseal purge gas rate will be specified by flare supplier.

Purge gas is normally supplied at the end of all major flareheaders and sub-headers, to ensure that the flare headers arefree of air. Changes in ambient temperature, or cooling of theflare header after a hot relief could cause a partial vacuum inthe flare header if no purge is provided. In most cases, the sumof the purge rates needed for the flare headers is greater thanthe purge needed for the flare seal.

Flare systems are commonly designed for a mechanical de-sign pressure of at least 335 kPa (ga), to minimize the chancesof equipment damage due to a flashback.

FLARE SYSTEMS

Types of Flares

A number of different types of flares are used in natural gasprocessing facilities. The most common can be classified as:

1. Elevated Pipe Flares This style consists of an el-evated flare riser with typically a flame stability deviceconstructed of stainless steel at the tip. The degree ofsmokeless operation is dependent on the gas composi-tion and discharge velocity (natural gas lean in NGL may

burn relatively smokelessly)

2. Elevated Assisted Smokeless Flare A general clas-sification of several different styles of elevated flares, de-signed to minimize smoke formation. The mechanism isimproved combustion due to the turbulence caused by theassist gas. Assist gas mixing can be external at the flaretip exit, internal to the flare tip, or both. These flares canoperate from below 0.5 Mach to sonic. The decision de-pends on the acceptable back-pressure for the flare head-er, the availability of utility streams, and the particulardesign of the flare tip. The required quantity of assist gasdepends on the type.

Steam assisted flare tip: most common type of flareused in refinery and natural gas service where suf-

ficient steam is available. Can achieve a smokelessoperation over a wide range of flared fluids and oper-ating conditions

Low Pressure Air Assist: commonly uses air suppliedby a blower in a channel around the flare stack topromote smokeless operation. Generally, these sys-tems will permit smokeless operation during day-to-day operation, but not necessarily at full flaringrate.


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Natural gas assisted Flare: uses high pressure natu-ral gas to provide the discharge turbulence requiredfor smokeless operation.

3. High Pressure Elevated Staged Flare Flare tipsoperating at sonic velocity, which use pressure energyto promote smokeless burning. Typically, the flare tipsare staged using valves at the flare base. This design ismost efficient when the flare stream is high pressurenatural gas.

4. Horizontal Ground Flare A ground flare typicallyconsists of a flare system operated with the flame hori-zontally on the ground. The most common style is similarto staged flare tips. They are often used in remote loca-tions where emissions, noise and flame visibility are notof significant concern.

5. Enclosed Ground Flare an enclosed ground flareconsisting of a burner surrounded by a shell. The systemoperates by introducing the flare gas into the unit viaa burner. Air enters the bottom of the shell via air lou-vers. Enclosed ground flares are normally used only forsmall capacity, low pressure flaring operations (such astank flares) where an elevated flare is inconvenient, andfor high capacity situations where an elevated flare is not

practical due to thermal radiation or community visibilityconcerns. Special flame arrestor burners are used in tankapplications to minimize the possibility of back flash.

6. Load

m05 - relief system

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