M05 relief system

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

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

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 sum-mary 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

SECTION 5

Relief Systems

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

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 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)

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

equip-ment modifications, operations, or changes made to process

pa-rameters, 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

The relief system documentation should demonstrate that

all pressure-containing equipment has been identified and that

the overpressure protection has been analyzed

Documenta-tion 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

cred-ible 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)

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

dispos-al system design, are criticdispos-al components of this review Typicdispos-al

steps in this process are:

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

• 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 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 to protect 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 well

as to comply with codes and laws

Determination of the maximum relief requirements may be difficult Loads for complex systems are determined by conser-vative assumptions and detailed analysis By general assump-

tion, two unrelated emergency conditions caused by unrelated

equipment failures or operator error will not occur

Ro = universal gas constant = 8314 kg J

• 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

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

θ = angle of flare flame from vertical, degrees

µ = viscosity at flowing temperature, mPa • s (centipoise)

μS = viscosity at flowing temperature, Saybolt Universal

Seconds (SSU)

FIG 5-1 (Cont’d) Nomenclature

neously (no double jeopardy) The relationship and sequence of

events must be considered ISO 23251 (API Std 521) provides

fur-ther 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

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 case”

condition 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 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

Blocked Discharge

The outlet of almost any vessel, pump, compressor, fired

heat-er, 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

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 Fire

conditions may overpressure vapor-filled, liquid-filled, or

mixed-phase 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

fail-ure 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

pip-ing 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

sys-tems, 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

ture are: 1) Install a relief device (pressure relief valve or

rup-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 viewed, 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

re-Relief protection for tube rupture is not required for ble pipe heat exchangers, if the internal parts are constructed

dou-of schedule pipe

Control Failure

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 require-ments for these conditions should be based on flow coeffi-cients (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 con-trol 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, depend-ing 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 af-ter switchover, then a design based on the maximum flow through either the control valve, or the bypass valve, which-ever is greater, may be considered In this case the system must be evaluated during the facility hazard review to en-sure 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 pro-tected 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 at-mospheric temperature can necessitate thermal overpressure protection Flashing across the relief valve needs to be consid-

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 installed

in all instances where piping systems may be blocked in by two

valves The decision to install a thermal relief valve for

pip-ing systems is typically based on the followpip-ing factors: length

and size of piping, vapor pressure of the fluid at the elevated

temperature 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 is

common to provide thermal relief valves for cryogenic liquid

ap-plications 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

Utility Failure

Loss of cooling water may occur on an area-wide or

plant-wide 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

Electric power failure, similar to cooling water failure, may

occur on an area-wide or plant-wide basis and may have a

vari-ety 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

compres-sors will also shut down Power failures may result in major

device and flare system relief loads

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

con-sidered

Fans on air cooled heat exchangers or cooling towers

oc-casionally 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

Check Valve Failure

Failure of a check valve to close must be considered A single

check valve is not an effective means for preventing

overpres-sure by reverse flow from a high-presoverpres-sure 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

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 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-spection practices for critical check valves, when relief tion is required, and recommended practices for determining the controlling relief rate

protec-Reflux Failure and/or Loss of Overhead Cooling For Fractionators

The failure of electrical or mechanical equipment that vides cooling or condensation in process streams can cause overpressure 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 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

pro-vs time Care should be exercised when using the dynamic proach since the results can be highly dependent on the specific assumptions used, and may not be conservative

ap-Abnormal Heat Input

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 condi-tion using a modified material balance approach

Process Upset

The source of a process upset can vary depending of the 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

ap-Liquid Overfilling of a Vessel

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

Transients

Transient 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 focus should be on avoiding transient pressure surges through design and 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 design for the maximum possible vacuum In some services (i.e., very large low design pressure vessels) alternate vacuum protection

Centrifugal Compressors — Centrifugal compressor

sys-tems should be analyzed in order to properly understand the

maximum pressure that can occur, and required relief

protec-tion (if any) for each part of the system, during operaprotec-tion

(nor-mal and upset), start-up, and at shutdown, based on the nor(nor-mal

and maximum suction, and/or discharge conditions The

maxi-mum 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

pres-sure than the overall final settle out prespres-sure

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 valves

are also provided on each individual stage to protect the

inter-stage equipment Reciprocating compressor systems should be

analyzed in order to properly understand the maximum

pres-sure 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

Fired Heaters — General best practice is to design fired

heaters such that the process side cannot be blocked in

Typical-ly, 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

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 The

relief valve should be installed on the downstream of the heater

to help ensure flow through the heater upon blocked outlet

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

in-stallation, 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

main-tenance Many small metering pumps will have built-in

inter-nal relief protection As these interinter-nal 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

Atmospheric Storage Tanks, and Low Pressure Tanks

— Atmospheric storage tanks are typically protected against

overpressure and vacuum due to process conditions and

atmo-spheric 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

(con-servation 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

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 equipment

designed for less than 103 kPa (ga), are covered by ISO 28300

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

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 devic-

es, 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, fail-ure of inert pads, utility failures

SPECIAL RELIEF SYSTEM CONSIDERATIONS

Administrative Controls

Administrative controls are procedures that, in combination with mechanical locking elements, are intended to ensure that personnel actions do not compromise the overpressure protec-tion of the equipment They include, as a minimum, document-

ed operation and maintenance procedures, and training of erator and maintenance personnel in these procedures [ASME Boiler & Pressure Vessel Code Section VIII, Appendix M]

op-Block Valves in the Relief Path

ASME Section VIII, Appendix M, provides requirements, cluding specific administrative controls, for block valves associ-ated 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

in-High Integrity Protection Systems (HIPS)

A High Integrity Protection System (HIPS) is an mented 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 main-tained to a stricter standard than most instruments These sys-tems 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 4 of the Data Book for more information on High Integrity Protection Systems (HIPS)

instru-In some very limited instances (i.e loss of control for an let valve downstream of a large packed pipeline upstream of

in-a trein-ating fin-acility, or protection in-agin-ainst runin-awin-ay rein-action,) in-a High Integrity Protection System may be considered to replace the requirement for a pressure relief device This is now rec-ognized by ASME Section VIII, Division 1 (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

• This analysis shall utilize an organized, systematic process

safety analysis approach such as: a Hazards and

Operabil-ity (HAZOP) review; a failure mode, effects and criticalOperabil-ity

analysis (FMECA); fault tree analysis; event tree analysis;

what-if analysis, or other similar methodology

• 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

The user shall consult ASME Section VIII, Division 1

(UG-140) 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

actu-ated or operator actuactu-ated, 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

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, or

release of toxic gas due to partial or total seal/packing failure of

rotating equipment

Depressurization systems are often used to prevent

poten-tial 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

pres-sure 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)

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 of

fluid leaked can be reduced A general criterion for system

de-pressurization is to reduce the pressure in the system to 690

kPa (ga) in fifteen minutes or less

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

For each application, the designer must verify that all

com-ponents (especially vessel internals and machinery elastomer

seals) can withstand the chosen de-pressurization rate In

ad-dition, 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

re-quires a pressure relief device or HIPS to be installed to protect

the vessel even if a depressuring system is used

Low Temperature Flaring

Natural gas plants frequently have more than one flare system (i.e high pressure flare, low pressure flare, cryogen-

ic 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 con-sider segregation of flare headers and systems

When low temperature streams are relieved, the flare tem piping and equipment exposed to cryogenic temperature may 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 according

sys-to applicable code recommendations

Industry experience has shown that formation of limited tity of hydrates at a relief valve outlet can typically be handled safely However, relieving large amounts of hydrates, or solid

quan-CO2/H2S/ methane solids to a closed flare system should be

avoid-ed Industry experience has shown that pure CO2 can be safely vented to the atmosphere, utilizing proper design practices

SET PRESSURE FOR PRESSURE

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 pres-sure relief valves, and rupture disks and shearing pin devices When the governing code is ANSI B31.3or ANSI B31.8, other types 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 the service 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 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 conven-tional 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 illustrat-

ed in Fig 5-3b If the bonnet is vented to atmospheric pressure, the back pressure acts with the vessel pressure so as to over-come 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

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

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 (belbel-lows) 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

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 bellows

area, AB, is the same as the nozzle seat area, AN, and, by

at-tachment to the valve body, excludes the back pressure from

acting on the top side of that area of the disk The disk area

ex-tending 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

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 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)

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

A check valve, split piston type valve, or backflow preventer

in the pilot line can be used

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, polymer-ization, fouling, solids, and corrosion can limit their use.Pilot operated valves are available with snap-action or mod-ulating action The modulating type relieves only the amount of fluid required to control the overpressure

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-com-pression, 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 al-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 Re-silient 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

met-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 po-tentially two-phase fluids, require a liquid trim It is important that the supplier is properly informed of the full range of expect-

ed 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 pres-sure to ensure reclosure of the valve following a relief event

Rupture Disk

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 Rup-ture 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

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

de-(a) Rapid rates of pressure rise A pressure relief valve tem does not react fast enough or cannot be made large enough to prevent overpressure (e.g., an exchanger rup-tured tube case or a runaway reaction in a vessel)

sys-(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

(c) A pressure relief valve system is susceptible to being

plugged, and thus inoperable, during service

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

de-sired 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

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 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 member that supports a pressure-containing member The devices are sanctioned by ASME Section VIII, and may be used for circum-stances where rupture disks may also be appropriate They have the advantage that the pin can be replaced without re-moving a piping flange

FIG 5-2 Pressure Level Relationships for Pressure Relief Valves 14

Courtesy American Petroleum Institute

FIG 5-4a Balanced Bellows Pressure Relief Valve 14

FIG 5-4b Effect of Back Pressure on Set Pressure of Balanced Pressure Relief Valve 14

FIG 5-3b Effect of Back Pressure for Conventional

Pressure Relief Valve 14

FIG 5-3a Conventional Pressure Relief Valve 14

Courtesy of American Petroleum Institute

Courtesy of American Petroleum Institute

Courtesy of American Petroleum Institute Courtesy of American Petroleum Institute

FIG 5-6 O-Ring Seals — For Conventional and Bellows

Pressure Relief Valves

RETAINERSCREW

Courtesy Lonergan Company

FIG 5-5

Pilot Operated Pressure Relief Valve 14

Courtesy of American Petroleum Institute

SIZING OF RELIEF DEVICES

After the required relief capacity of a relief valve has been

determined, the minimum orifice area required must be

calcu-lated Industry standards for orifice designation, orifice area,

valve dimensions, valve body sizes, and pressure ratings are

available 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 some

pilot-operated relief valves contain orifice areas larger than

“T.” 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 analysis

must include downstream piping For example, consider the use

of a relief valve made for a vessel with a maximum allowable

working pressure of 1000 kPa (ga) The relief valve set pressure

is 1000 kPa (ga), and the maximum allowable overpressure is

10% [100 kPa (ga)] The vessel pressure, when relieving, must

be limited to 1100 kPa (ga) [1000 kPa (ga) set pressure plus 100

kPa (ga) maximum overpressure] Pressure buildup downstream

of 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 the

actual flow area of a pressure relief valve, as well as those

be-tween the API effective coefficient of discharge and the ASME

certified coefficient of discharge The designer is cautioned

nev-er to mix the API effective orifice area and discharge coefficient

with 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 dependent

on the absolute upstream pressure (as indicated in Equation

5-1, Equation 5-2, and Equation 5-3) and is independent of the

downstream pressure as long as the downstream pressure is

less than the critical-flow pressure (See API Std 520-1)

Howev-er, if the downstream pressure increases above the critical-flow

pressure, 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 relief

valve is greater than one-half of the valve inlet pressure (both

pressures in absolute units), then the relief valve nozzle will

experience subcritical flow

Critical Flow — Safety valves in gas or vapor service may

be sized by use of one of these equations:14

C1 can be obtained from Figs 5-8, and 5-9 Note that the

ideal gas specific heat ratio k = Cp/Cv has to be used for the

determination of C1 in Equation 5-3 The ideal gas specific heat ratio is independent of pressure The heat capacity ratio used should be based on the upstream relieving temperature Note that most process simulators will provide real gas specific heats

at the process pressure and temperature These should not be used in the above equation because if this value is used, the pressure relief device may be undersized For real gases with

a compressibility of less than 0.8 or greater than 1.1, API Std

520 Part I states that use of the ideal gas specific heat ratio can introduce significant error, and a more thermodynamically sound approach should be considered.14 The Theoretical Mass Flux Isentropic Expansion Method as described in API Std 520 Part I provides this foundation

Kb can be obtained from Figs 5-10 and 5-11 For final sign, Kd should be obtained from the valve manufacturer A value for Kd of 0.975 may be used for preliminary sizing

de-Subcritical Flow — For downstream pressures, P2, in cess of the critical-flow pressure, PCF, the flow through the pres-sure relief valve is subcritical Under these conditions, Equation 5-414 may be used to calculate the required effective discharge area for a conventional relief valve that has its spring setting adjusted to compensate for superimposed backpressure, or for a pilot operated relief valve

Sizing for Steam Relief

Safety-relief valves in steam service are sized by a fication of Napier’s steam flow formula Valve manufacturers can supply saturated steam capacity tables A correction fac-tor, Ksh, must be applied for safety valves in superheated steam service

modi-For safety-relief valves in steam service, the required area may be estimated from the following equations from the ASME Code Section VIII, Div 1 and API-520-1:14

A = (1.905) W (P1) (Ksh) • Kd Kb Kc Kn Eq 5-6

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

Turbulent­Flow — 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 service

only when the manufacturer has approved the specific

applica-tion

A = (7.07) (Vl) √ G

(Kd) (Kc) (Kw) (Kv) √ (P1 – Pb) Eq­5-8

Laminar­Flow — For liquid flow with Reynolds numbers

less than 4,000, the valve should be sized first with Kv = 1 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

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

­Sizing­for­Thermal­Relief

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

calcu-lations assume the liquid is non-compressible.13

(B) (Q)

Vl = 1000 Eq­5-11

• (G) (S)Typical values of the liquid expansion coefficient, B, at 15°C

For heating by atmospheric conditions, such as solar

radia-tion, the surface area of the item or line in question should be

calculated Solar radiation [typically 787–1040 W/m2] should be

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 lief may be found from the turbulent liquid flow equations

re-­Sizing­a­Pressure­Relief­Device­­

for­Two­Phase­Flow

For two phase fluids and flashing liquids, a choking enon limits the flow through the pressure relief valve nozzle, in

phenom-a mphenom-anner similphenom-ar to the choking of phenom-a gphenom-as in criticphenom-al flow In order

to estimate the relief capacity of a nozzle, it is necessary to timate the choking pressure and then determine the two phase physical properties at these conditions The historical method

es-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 lowing assumptions:

fol-• The fluid is in thermodynamic equilibrium through the nozzle

• 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 expan-sion 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

­Sizing­for­Fire­for­Partially­­

Liquid­Filled­Systems

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 termi-nals, 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 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 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

The environment factor, F, in Equation 5-12 is determined from Fig 5-16 Credit for insulation can be taken only if the in-sulation system can withstand the fire and the impact of water

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 do not exist is also

pro-vided in this Standard

A w in 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 least

that portion of a vessel within a height of 8 m above grade In

the case of spheres and spheroids, the term applies to that

por-tion of the vessel up to the elevapor-tion of its maximum horizontal

diameter or a height of 8 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

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

cal-culated at 110% of maximum allowable working pressure for

single relief devices

Latent heat data may be obtained by performing flash

calcu-lations 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

require-ments 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

When the latent heat is determined, required relieving

ca-pacity may be found by: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

re-quired relief area based on fire:

183.3 (F´) (A3)

A = Eq 5-14

­ ­ √ P1

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   (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 900°C, 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 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

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, or

two phase, depending on the fluid, liquid level, vessel size and

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

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 ap-plied for gas filled systems

Heavy hydrocarbons can be assumed to crack (i.e., to mally 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

ther-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 7

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

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 con-nection 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

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 opera-tion, 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 op-erate, is defined as superimposed backpressure Backpressure which develops in the discharge system, after the pressure re-lief valve opens, is built-up backpressure The magnitude of pressure which exists at the outlet of the pressure relief valve,