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Certified Process Design Professional
Lesson # 07
PSV Selection & Sizing
Part 02
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Steps for Pressure Safety Valve (PSV) Sizing Calculation
1. Develop Process Safety Diagram (PSD)
– Establish a diagram showing safety controls, interlocks, and protection systems.
2. Develop relief scenarios
– Identify credible overpressure scenarios based on causes (e.g., blocked outlet, fire,
thermal expansion).
3. Determine required relief area
– Calculate relief area for each scenario considering the phase (Gas, Liquid, or Twophase) and thermodynamic conditions.
4. Choose worst-case scenario
– Identify the scenario with the highest relief requirement to design the PSV.
5. Select proper orifice and valve body
– Use standards (API 520/521/526) to select orifice and body size matching required
flow and set pressure.
6. Calculate inlet line size
– Ensure pressure drop (ΔP) in the inlet line is <3% of the PSV set pressure.
7. Preliminary tail pipe sizing
– Estimate discharge piping to check pressure drop and backpressure implications.
8. Perform flare system modeling
– Simulate discharge into flare header to verify backpressure and optimize tail pipe size.
9. Select PSV type
– Choose between:

Conventional

Balanced Bellows (for high backpressure)

Pilot Operated (for precise performance or high set pressures)
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Develop Process Safety Diagram (PSD):
A Process Safety Diagram (PSD) illustrates the placement of all process safety equipment (e.g.,
PSHH, TSHH, PSVs, BDVs, rupture discs). It serves as the foundation for identifying and evaluating
all potential relief scenarios. The PSD must be created prior to performing any PSV sizing
calculations.
Develop Relief Scenarios:
Identify potential overpressure situations by analyzing general causes (e.g., blocked outlets,
utility failures, fire) using the Process Safety Diagram (PSD) as a reference to ensure all safety
devices and conditions are considered.
Possible Scenarios
Vessel / Column HEX Pump Compressor Line
●
●
●
Blocked Outlet
●
●
Thermal Expansion
●
Tube Rupture
●
Gas Blow-by
●
●
Inlet Control Valve Failure
●
●
●
●
●
Exterior Fire
Note: Exterior Fire is not applicable for PHEX!
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Blocked Outlet / Blocked Discharge
This scenario occurs due to the unintentional closure of a block valve or failure of a control valve
in the closed position on an outlet line. It commonly affects production separators, compressor
discharge piping, and pump discharge piping. In such cases, safety relief valves must be sized to
handle 100% of the expected upstream flow. For multi-phase streams, the relief rate must
account for the total inlet flow — both gas and liquid phases.
Thermal Expansion/ Thermal Relief
Thermal Expansion Relief Valves (TERVs) are needed in liquid-full systems that can be blocked in
and exposed to heat from the atmosphere or process. This heat input can cause fluid expansion
and lead to overpressure if not properly relieved.
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Tube Rupture
A tube rupture in a heat exchanger can cause vapor to rapidly enter the tube or shell side,
resulting in a sudden pressure surge that propagates at sonic velocity. Since PSVs may not
respond quickly enough, rupture discs are typically used for protection in such cases.
Gas Blow-by
Gas blow-by happens when a vessel’s liquid level drops too low—often due to level control
failure—allowing gas to escape through the liquid outlet. This leads to high-pressure gas entering
downstream low-pressure systems, posing a risk of overpressure.
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Inlet Control Valve Failure
In this case, overpressure occurs due to excess inlet flow when an inlet control valve fails. The
relief rate is calculated as the difference between the maximum possible inlet flow and the outlet
flow at relief conditions, assuming no corrective response from outlet valves (i.e., they remain at
their normal operating positions).
External Fire
Production and processing facilities are typically divided into fire zones using barriers like plated
decks, firewalls, or platform edges. In the event of a fire, all equipment within the affected zone
is considered fully exposed. During the fire, it is assumed that no feed or product flows through
the affected system, and all normal heat sources are halted. Additionally, no credit is given for
water spray systems or thermal insulation on vessels.
Fire Type
Pool Fire: Systems containing significant liquid hydrocarbon inventory are evaluated for potential
pool fire scenarios. The heat flux for such fires will be calculated according to API RP 521. A 40%
reduction in heat flux may be considered if there is effective drainage and prompt firefighting
efforts, as outlined in API RP 521.
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Jet Fire: In cases where a jet fire is a potential risk, the relief load will be calculated based on the
higher heat flux generated by the fire. Jet fires produce heat flux ranging from 50 kW/m² to 300
kW/m². However, the actual net heat flux to the fluid depends on several factors, including the
fuel type, vessel temperature, surface emissivity, fire environment, and the radiative and
convective components of the fire.
Vessel Type & Fluid Relief Type
Vessel types can be classified as:

Dry or empty vessel

Vessels containing liquid, where the effect of the wetted area of the vessel needs to be
considered.
Fluid relief types can be categorized as:

Sub-critical fluid: Pressure (P) is less than 0.9 times the critical pressure (Pc), i.e., P < 0.9
* Pc.

Near-critical fluid: Pressure is between 0.9 * Pc and 1.1 * Pc, i.e., 0.9 * Pc < P < 1.1 * Pc.

Super-critical (dense phase) fluid: Pressure is greater than 1.1 times the critical
pressure, i.e., P > 1.1 * Pc.
Where:

Pc = Critical Pressure

P = Relieving Pressure
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Totally = 2x2x3 = 12 cases possible
Hence 12 methods of calculation for Fire case.
Determine the required relief area for each case (gas, liquid, or two-phase).
Target of sizing relief valve
1. Determine the relief rate.
2. Determine the required relief area.
3. Select the standard relief area.
Applicable Standards


API RP 520: Guidelines for sizing, selection, and installation of pressure relief devices.
API RP 521: Guidance on pressure relief system design and depressuring analysis.
Relief fluid category
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Determining the relief rate is the first and most critical step in relief valve sizing. Certain
scenarios—such as gas blow-by, tube rupture, and especially fire cases—involve complex
calculations and multiple steps due to varying thermodynamic and process conditions.
While API RP 520 and 521 provide simplified methods for estimating relief rates, these methods
may not cover all possible scenarios or complexities. As a result, many companies have developed
internal procedures and tools to more accurately determine relief rates tailored to their specific
processes and equipment.
Relief Valve Sizing for Single-Phase Vapor Flow
Relief valves handling single-phase vapor flow are sized following the methodology outlined in
API RP 520, Section 3.

The sizing equations are divided into two categories based on the nature of the flow:
o
o

Critical flow
Subcritical flow
To determine which equation to apply, the critical pressure condition must first be
checked using the following formula:
If flow is critical (Pcf > downstream pressure P2), the critical sizing equation is used:
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If flow is subcritical, the following equation will be used (API 520)
Subcritical Flow Coefficient (F₂)
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Relief valves in steam service will be sized as follows:
Relief Valve Sizing for Single-Phase Liquid Flow
For single-phase liquid flow, the sizing is performed using the method specified for certified
relief valves as outlined in API RP 520.

The following equation is applicable only to non-flashing (incompressible) liquids:
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Two-Phase Relief Valve Sizing

For two-phase (liquid/vapor) relief, the sizing must follow the method outlined in API
520 Part 1, Appendix D: "Sizing for Two-Phase Liquid/Vapour Relief".

This updated methodology replaces older API approaches due to findings that previous
methods could significantly underestimate the required relief area in certain scenarios.

The method is based on the Leung Omega Method, which is rooted in the
Homogeneous Equilibrium Model (HEM)—assuming both thermal and mechanical
equilibrium between liquid and vapor phases.
Determine required relief area for each case (Gas, Liquid, 2-Phases)
Required relief area is calculated from relief rate. Hence relief rate calculation is very important
step
Choose the worst case scenario to be a governing case
The case which giving the maximum relief area will be a governing case.
Select proper orifice and valve body size based on STD
The standard orifice sizes for pressure relief valves are selected based on:

API RP 526

Or GPSA Data Book, Chapter 5, Figure 5-7
The valve body size—defined by inlet × outlet flange diameter—must comply with:

API Standard 526: “Flanged Steel Pressure Relief Valves,” 4th Edition, June 1995
To calculate the inlet line size for a pressure relief valve, the pressure drop (ΔP) across the inlet
line should be less than 3% of the set relieving pressure (RP), as per API RP 520 Part II guidelines.
This is to avoid excessive pressure loss that could affect valve performance.
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Inlet Line Design Considerations for Relief Valves

The inlet pipe diameter must be at least equal to the PSV inlet flange size.

The inlet piping should slope upward continuously from the source vessel to the valve to
prevent liquid accumulation or traps.

Heat tracing is recommended if there's a risk of freezing or solidification, especially for
viscous or congealable liquids.

A continuous clean purge should be installed if there is potential for coke, polymer
buildup, or solids deposition in the relief path.

Car Seal Open (CSO) valves should be installed with the stem in a horizontal or vertically
downward orientation to prevent accumulation of debris or fluid at the stem.
Perform Preliminary Estimate Of Tail Pipe

Discharge line must be sized so that the Mach number remains below 0.75 to ensure
non-choked flow.
Tail Pipe Design Considerations

The discharge line diameter must be equal to or greater than the PSV outlet flange size.

Closed discharge piping must slope continuously downward to the header to prevent
liquid accumulation.

No check valves, orifice plates, or other flow restrictions are allowed in relief valve
discharge lines.

Design must account for thermal expansion from hot or cold relief streams.

Consider the effects of auto-refrigeration, which may require brittle fracture-resistant
materials.
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
Risers must discharge at least 10 ft above any platform located within 50 ft horizontally.

Must include a drain hole to avoid accumulation of liquids.

Radiant heat from potential ignition of discharge must be evaluated in the design.

CSO (Car Seal Open) valves should be installed with the stem oriented horizontally or
vertically downward.
Perform Flare system modeling to indicate total back pressure and most suitable tail pipe size.
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Select PSV type (Conventional, Balanced Bellow, Pilot Operated)
Back Pressure
Type
Effects on Valves: Gas Applications
Value (% of
set pressure)
< 30%
30–50%
Constant
Conventional
Balanced Bellow
No effect
Set point increased by
back pressure
> 50%
Set point increased by
back pressure; Flow
becomes sonic
< 10%
Set point varies with back
pressure
Lift/Capacity
reduced
No effect
Lift/Capacity
reduced
Unstable — Do not use
< 10%
No effect
No effect
Lift/Capacity
reduced
10–30%
Unstable — Do not use
> 50%
Back Pressure
20–50%
Constant
Variable
Superimposed
No effect
Generally unstable
— Do not use
Flow
becomes
subsonic
Effects on Valves: Liquid Applications
Value (% of
set pressure)
< 20%
Flow
becomes
subsonic
Generally unstable
— Do not use
> 50%
Type
Flow
becomes
subsonic
No effect
30–50%
Variable Built-up
No effect
Generally unstable
Do not use
10–30%
Variable
Superimposed
Pilot
Operated
Conventional
Set point increased by back
pressure
Balanced Bellow
No effect
Lift/Capacity
reduced
> 50%
Set point increased by back
Generally unstable
pressure; Flow becomes
— Do not use
sonic
< 10%
Set point varies with back
pressure
10–20%
Unstable — Do not use
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Pilot
Operated
No effect
No effect
No effect
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Back Pressure
Type
Effects on Valves: Liquid Applications
Value (% of
set pressure)
Conventional
20–50%
Lift/Capacity
reduced
> 50%
Generally unstable
— Do not use
< 10%
Variable Built-up
Balanced Bellow
No effect
No effect
10–20%
Unstable — Do not use
> 50%
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Pilot
Operated
Lift/Capacity
reduced
No effect
Generally unstable
— Do not use
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Assess Relief Scenarios
Judgement
Scenario to be
considered
separately
An external fire could cause the pressure in V-6010 to
rise to the relief valve setting through vaporization of
liquids. Equipment layout shows no potential that “jet
fire” will happen on located area thus “pool fire” will be
determined as a basis for calculation.
Yes
Source of
Scenario
Overpressure
1
Fire Case
2
Tube Rupture
This case is not applicable.
No
3
Inlet control
valve failure
CVs are fail to close type therefore this case is not
applicable for sizing PSV.
No
4
Gas Blow-by
Gas blow-by can occur by:
• Liquid in a V-1 drop so low that gas exits via the liquid
outlet nozzle due to level control failure. Loss of liquid
level will result in gas from V-1 passing into V-2 via F-1
and/or F-2.
Gas blow-by is based on following assumptions:
• Control valve upstream fails 100% open
• The upstream pressure is at the high pressure alarm
• The downstream pressure is 110% of the set point of
the relief valve on the downstream vessel
• No possibility that the bypass valve around the control
valve is opened.
Yes
5
1. Water Blocked Discharge:
This scenario will relate to two trips; first LIAHH and
secondly LAHH. Credit can be taken that either of these
two will actuate. It is unreasonable to assume both will
fail to respond. Hence, this scenario cuts off the feed to
Blocked Outlet vessel and no relief is needed.
Yes
2. Oil Blocked Discharge:
This scenario relates to only oil trip, while interface level
is already healthy. No credit can be taken that this trip
will work. Hence PSV needs oil relief.
6
Thermal Relief This case is not applicable.
No
Possible Relief Scenarios
There are three different possible relief scenarios:
o
o
o
Fire Case.
Gas Blow-by Case.
Blocked Outlet Case.
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Fire Case
Scenario: An external fire could cause the pressure in V-2 to rise to the relief valve setting through
vaporization of liquids. Equipment layout shown no potential that “jet fire” will happen on
located area thus “pool fire” will be determined as a basis for calculation.
Relief Condition
PSV-2 set pressure = 250 psig
Allowable Accumulation = 21%
Maximum allowable accumulated pressure = 250x1.21 = 302.5 psig.
Relieving temperature =?
Although relief may occur 61 minutes after a fire starts, API RP 520 assumes the fire is managed
within 15 minutes, making this scenario unlikely in actual operation.
By input all required parameters (eg. Vessel dimensions, fluid relieving properties), in to
calculation sheet.
Required relief area = 0.183 in2
Relief Load = 4,066 lb/hr
Therefore
Select 1xEx2 orifice with discharge area of 0.196 in2
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Gas Blow-by
Scenario: Liquid in a V-1 drop so low that gas exits via the liquid outlet nozzle due to level
control failure. Loss of liquid level will result in gas from V-1 passing into V-2 via F-1 and/or F-2.
Gas Blow-by Assumptions and Relief Conditions:
Gas blow-by is evaluated under the following assumptions:

The upstream control valve fails fully open (100%).

Upstream pressure reaches the high-pressure alarm level.

Downstream pressure is assumed to reach 110% of the PSV set point.

No possibility that the bypass valve around the control valve is opened as locked close.
Relief Conditions:

PSV-2 Set Pressure: 250 psig

Allowable Accumulation: 10%

Maximum Allowable Accumulated Pressure: 250 × 1.1 = 275 psig
Assume



F-1 and F-2 are same maximum Cv of 433.
C1 assumed 26.5 (C1 is normally obtained from valve vendor)
Assume only one control valve is fail.
Therefore Cg = C1 x Cv = 433 x 26.5 = 11,474.5
V-1 hold pressure at PAH = 350 psig
V-2 operating pressure = 275 psig (250 psig x 1.1 = 275 psig)
Differential pressure = 350-275 = 75 psi
Reliving temperature = 80 deg F
How to find the maximum relief rate via F-1 and/or F-2?
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The maximum relief rate can be determined using control valve sizing software (e.g., Fisher,
Masoneilan, HYSYS) or standard sizing equations such as those found in the GPSA Engineering
Data Book.
By entering all necessary parameters (e.g., fluid relieving properties) into the calculation sheet
for vapor relief scenarios:

Required Relief Area: 11.57 in²

Relief Load: 245,703.5 lb/hr
Based on this, a 6xR x 8 orifice with a discharge area of 16 in² is selected.
Blocked Outlet
1. Water Blocked Discharge
This scenario involves two independent trips: a high-high interface level (LIAHH) and a
high-high liquid level (LAHH). Since it is highly unlikely both would fail, it's assumed that
at least one will stop the feed to the vessel, eliminating the need for pressure relief.
2. Oil Blocked Discharge
In this case, only the oil trip is considered active, with the interface level remaining
normal. No reliability credit is given to the oil trip, so a pressure safety valve (PSV) is
required for protection.
Relief Conditions:




PSV-2 Set pressure: 250 psig
Allowable accumulation: 10%
Maximum relieving pressure: 250 x 1.1 = 275 psig
Relieving temperature: 130 °F
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From simulation data:


Oil flow rate: 508,100 lb/hr (equivalent to 25,000 BPD)
Oil density: 55.21 lb/ft³
Using the provided fluid properties and inputting them into the relief valve calculation sheet for
a typical liquid relief scenario:



Required relief area: 2.76 in²
Selected orifice size: 3" x L x 4"
Actual discharge area: 2.853 in²
This selected orifice provides slightly more area than required, ensuring safe relief capacity.
Selection of Governing Relief Scenarios
Relief Case
Design Orifice Size Relief Phase
Fire Case
1×Ex2
Vapor
Gas Blow-by
6×Rx8
Vapor
Blocked Outlet
3×Lx4
Liquid
Selected Governing Case: Gas Blow-by



Calculated Relief Rate: 287,530 lb/hr
Required Orifice Area: 11.57 in²
Chosen Orifice Area: 16 in²
Resulting Rated Flow Calculation:
Rated flow = (16 / 11.57) × 287,530 lb/hr = 397,621 lb/hr
Inlet line sizing calculation
Inlet line sizing calculation is based on pressure drop less than 3 % of set pressure



PSV Set Pressure: 250 psig
Allowable Pressure Drop (3%): 0.03 × 250 = 7.5 psi
Rated Mass Flow: 397,621 lb/hr
Based on the maximum rated flow and associated relief conditions, the pressure drop for an 8"
inlet line is calculated as 5.3 psi, which is within the allowable limit.
Conclusion: The 8" line meets the inlet pressure drop criteria and is suitable for use.
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Outlet line sizing calculation
Outlet line sizing calculation is based on the maximum Mach No. of 0.75

Preliminary Estimate:
o

12” Line → Mach number = 0.71 → Acceptable
Aspen Flare System Analyzer Modeling Result:
o
10” Line → Mach number = 0.45 → Also acceptable
Conclusion: Both 12” and 10” outlet lines satisfy the Mach number requirement, with 10” being
more conservative and efficient.
Selection of Relief Valve Type
Result from Aspen Flare System Analyzer simulation give total back pressure of 70 psig
PSV set pressure = 250 psig
PSV Type
% of Maximum Back Pressure
Allowable
Maximum Back Pressure Allowable
(psig)
Conventional
10% of SP
25 psig
Balanced
Bellow
30% of SP
75 psig
Pilot Operated
N/A
N/A
Summary:
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