OIL & GAS
WorleyParsons
OIL&GAS
PSV Sizing CalculationPSV Sizing Calculation23-June-0523-June-05
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CONTENTCONTENT
• INTRODUCTION• PSV TYPES• CHATTERING PROBLEM• SIZING CALCULATION• EXAMPLE
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INTRODUCTIONINTRODUCTION
• Relief systems are provided on a platform in order to ensure the safe operation of the facilities.
• In accordance with API RP 14C, all hydrocarbons handling equipment and pressure vessels will be provided with two levels of over protection, high pressure trip (PSHH) with shutdown action, and protection by mechanical devices, Pressure Safety Valve (PSV) or Rupture Disc.
• PSVs are installed at every point identified as potentially hazardous, that is, at points where upset conditions create pressure which may exceed the maximum allowable working pressure.
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INTRODUCTIONINTRODUCTION
How High Pressure Develop• Over heating • High head ( from pumping or compression) • Over Filling • Failure of Regulator / Control valve. • External Fire • Runaway Reaction • Combustion of gas/dust • Freezing • Thermal Expansion• Loss of Mixing • Others
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INTRODUCTIONINTRODUCTION
Definitions
• Operating pressureOperating pressure : The gauge pressure during normal service.
• Set PressureSet Pressure : The pressure at which the relief device begins to activate or open.
• Maximum Allowable Working Pressure (MAWP)Maximum Allowable Working Pressure (MAWP) : The maximum guage pressure permissible at the top of a vessel for a designated temperature.Vessel fails at 4 to 5 times of MAWP!!!! . But only hydrostatically tested to 1.5 times.
• AccumulationAccumulation : The pressure increase over the maximum allowable working pressure of a vessel during the relief process. Expressed as % of MAWP.
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INTRODUCTIONINTRODUCTION
Set Pressure
Relief begin to open
Accumulation
Pressure
Time
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Definitions
• Over PressureOver Pressure : The pressure increase in vessel over the set pressure during the relieving process. Overpressure is equivalent to the accumulation when the set pressure is at the MAWP. Expressed as % of set pressure. Must be specified prior relief design. Typically 10 % ( or for fire 21%) will be used.
Pressure
Time
Relief begin to open
Set PressureOver Pressure
INTRODUCTIONINTRODUCTION
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Definitions
• Blow-downBlow-down : The pressure difference between the relief set pressure and the relief reseating pressure.
• Maximum Allowable Accumulated PressureMaximum Allowable Accumulated Pressure : The sum of the maximum allowable working pressure plus the allowable accumulation.
INTRODUCTIONINTRODUCTION
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INTRODUCTIONINTRODUCTION
Guideline for relief pressures (Adapted from API RP 520 : “ Sizing, Selection, and Installation of Pressure-Relieving Devices in “ Sizing, Selection, and Installation of Pressure-Relieving Devices in Refineries.”Refineries.” , page 3)
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Definitions
• Back PressureBack Pressure : The pressure at the outlet of the relief device during the relief process due to pressure in the discharge system.
1. Superimposed Back Pressure. 2. Built-up Back Pressure.
Total Back Pressure = Superimposed Back Pressure + Built-up Back Pressure
INTRODUCTIONINTRODUCTION
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INTRODUCTIONINTRODUCTION
Definitions
1. Superimposed Back Pressure is the back pressure which may exist at the outlet of a particular relief valve when connectedto a closed system. The pressure can be constant or variable. The Superimposed back pressure always exists even when the reliefvalve is closed.
2. Built-up Back Pressure is the pressure at the discharge of a relief device which develops due to the relief flow through the device when the relief valve opens. The built-up back pressuredepends on the valve itself but also on the design of the relief piping. It can reach excessive values in the case of vary high set pressures and/or poorly designed piping with too much pressureLoss. The built-up back pressure is variable.
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PSV TYPESPSV TYPES
General Design of PSV
1. Direct acting type
• Oldest and most common.• Kept closed by a spring or weight to oppose lifting force of process pressure.
2. Balanced Bellows.
3. Pilot operated type
• Kept closed by process pressure
4. Modulating Pilot.
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PSV TYPESPSV TYPES
The following types of PSV are generally used.
1. Conventional PSV2. Balanced Type PSV (Balanced Bellow)3. Pilot Operated PSV4. Modulating Pilot Operated PSV5. Thermal PSV
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PSV TYPESPSV TYPES
Conventional PSV Advantages• Most reliable type if properly sized and operated• Versatile -- can be used in many services• Compatible with fouling or dirty service.
Disadvantages• Relieving pressure affected by back pressure• Susceptible to chatter if built-up back pressure is too high
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Balanced Bellow PSV
PSV TYPESPSV TYPES
Advantages• Relieving pressure not affected by back pressure.• Can handle higher built-up back pressure.• Protects spring from corrosion.• Wide range of materials available & chemical compatibility.
Disadvantages• Bellows susceptible to fatigue/rupture.• May release flammables/toxics to atmosphere.• High maintenance costs.
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Pilot Operated PSV Advantages• Relieving pressure not affected by backpressure• Can operate at up to 98% of set pressure• Less susceptible to chatter (some models)
Disadvantages• Pilot is susceptible to plugging (therefore not recommended for fouling service, eg. Wax).• Limited chemical and high temperature use by “O-ring” seals• Vapor condensation and liquid accumulation above the piston may cause problems• Potential for back flow
PSV TYPESPSV TYPES
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CHATTERING PROBLEMCHATTERING PROBLEM
Modulating Pilot Operated
There are two main types of pilot control operation
• Pop action : Main valve fully open at set pressure
• Modulating : Main valve opens according to relief demand.
Modulating pilots have additional advantages:
• They only open the main valve enough to keep the system at set pressure which leads to less wasted product being relieved
through the valve.
• Less noise generated by the valve when it is required to relieve.
• Recommended for Wellhead platform PSV.
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CHATTERING PROBLEMCHATTERING PROBLEM
Main valvepiston lift
Pressure
OpeningClosing
100 % Lift POP Action
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CHATTERING PROBLEMCHATTERING PROBLEM
Main valvepiston lift
Pressure
OpeningClosing
100 % Lift Modulating
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Chattering Problem
• Chattering is the rapid, alternating opening and closing of a PSV.
• Resulting vibration may cause misalignment, valve seat damage and, if prolonged, can cause mechanical failure of valve internals and associated piping.
• Chatter may occur in either liquid or vapor services
CHATTERING PROBLEMCHATTERING PROBLEM
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Cause of Chattering• Excessive inlet pressure drop
• Excessive built-up back pressure
• Oversized valve
• Valve handling widely differing rates
CHATTERING PROBLEMCHATTERING PROBLEM
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Excessive inlet pressure drop
• Normal PSV has definite pop and reseat pressures.
CHATTERING PROBLEMCHATTERING PROBLEM
Reseat or close pressure Pop or opening pressure
Blow-down = Different between pop and reseat pressure
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CHATTERING PROBLEMCHATTERING PROBLEM
Excessive inlet pressure drop : Solution
If you can’t change the piping
• Install smaller PSV
• Install different type of PSV
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CHATTERING PROBLEMCHATTERING PROBLEM
Excessive Built-up Back Pressure
Excessive outlet pressure will also cause chatter.
Avoid• Long outlet piping runs.• Elbows and turns.• Sharp edge reductions.
But if you must• Make outlet piping large!
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CHATTERING PROBLEMCHATTERING PROBLEM
Improper Valve SizeOversized valve
• Must flow at least 25% of capacity to keep valve open.• Especially bad in larger sizes.
Valve handling widely differing rates
• Leads to oversized valve case.
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SIZING CALCULATIONSIZING CALCULATION
Step Of Sizing CalculationDevelop Process Safety Diagram (PSD)
Develop relief scenarios by using general possible cause and PSD
Determine required relief area for each cases (Gas, Liquid, 2-Phases)
Choose the worst case scenario to be a governing case
Select proper orifice and valve body size based on STD
Calculate inlet line size (Line ∆P < 3%of RP)
Perform preliminary estimate of tail pipe
Perform Flare system modeling to indicate total back pressure and most suitable tail pipe size.
Select PSV type (Conventional, Balanced Bellow, Pilot Operated
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SIZING CALCULATIONSIZING CALCULATION
Develop Process Safety Diagram (PSD)
Process safety diagram is the diagram which showall installation of all process safety equipments (PSHH,TSHH, PSV, BDV, Rupture disc, etc.) intend to be used inevaluation of all possible relieving scenarios in processfacilities. Process safety diagram must be developed beforeperforming any PSV calculation.
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SIZING CALCULATIONSIZING CALCULATION
Develop Process Safety Diagram (PSD)
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SIZING CALCULATIONSIZING CALCULATION
Develop relief scenarios by using general possible cause and PSD
EquipmentPossible Scenarios
PumpHEX LineVessel / Column Compressor
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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SIZING CALCULATIONSIZING CALCULATION
Blocked Outlet/ Blocked Discharge
CLOSED
CLOSED
CLOSED
CLOSEDCLOSED
Process Vessel
Compressor Pump
This situation arises from the inadvertent closure of a block valve or failure of a control valve in the closed position on an outlet line. Typical overpressure application where this form of protection is required includes production separators, compressor discharge piping or pump discharge piping. The safety relief valves are sized to handle 100% of the anticipated upstream flow. If the feed stream(s) is multi-phase, the relief rate is the total inlet flow (gas plus liquids).
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SIZING CALCULATIONSIZING CALCULATION
Thermal Expansion/ Thermal Relief
Heat Exchanger
Line
Hot Side
Cold Side
CLOSED CLOSED CLOSED
Thermal expansion relief valves (TERV’s) are required in liquid-full systems if the system can be blocked in and/or subjected to heat input from the atmosphere or process that results in overpressure.
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SIZING CALCULATIONSIZING CALCULATION
Tube Rupture
Heat Exchanger
Hot Side
Cold Side OR
Heat Exchanger
Hot Side
Cold Side
Tube rupture causing vapour to enter either the tubeside or shellside of a heat exchanger will cause a pressure spike to travel through the fluid at sonic velocity. Generally, a PSV will not lift fast enough to protect the system. Protection against tube rupture is typically by the use of bursting discs.
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SIZING CALCULATIONSIZING CALCULATION
Suddenly OpeningPressure at PSHHLiquid at LSLL
Gas blow-by occurs when liquid level in a partially filled vessel drops so low that gas exits via the liquid outlet nozzle due to level control failure. Loss of liquid level will result in gas from the high pressure vessel passing into the low pressure system downstream of the liquid level control valve.
Gas Blow-by
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SIZING CALCULATIONSIZING CALCULATION
Fail to openPressure at normalLiquid at normal
Inlet Control Valve Failure
The relief rate is equal to the difference between the maximum inlet flow and the flow, at relief conditions, from the outlet valves that remain open. No credit for outlet valves response will be taken i.e. they will be assumed to remain at their normal operating point (% open).
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SIZING CALCULATIONSIZING CALCULATION
Exterior FireGenerally, the production & processing facilities will be segregated into fire areas, by means of plated decks, fire walls, or edge of the platform. During a fire in one of the fire areas, all equipment within that area is assumed to be fully exposed to the fire.
It is assumed that during a fire there is no feed to or product from an affected system, and all normal heat inputs have ceased.
• No credit will be taken for the presence of any water spray systems. • No credit will be taken for thermal insulation on vessels.
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SIZING CALCULATIONSIZING CALCULATION
Pool Fire Jet Fire
Fire Type
Systems with significant liquidhydrocarbon inventory will be considered for pool fire case. Heat flux will be calculated as per API RP521. Credit for a 40% reduction in heat flux may be taken for good drainage and the presence of prompt fire fighting efforts as specified in API RP 521.
Where potential for jet fire exists, relief load will be calculated for higher heat flux from heat fire. The heat flux generated by jet fire ranges from 50 kW/m2 to 300 kW /m2. However, the net heat flux into the fluid will depend on many factors such as fuel type, vessel temperature, the surface emissivity, the fire environment, the radiative and convective components of the fire.
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SIZING CALCULATIONSIZING CALCULATION
Vessel Type & Fluid relief type
Vessel type could be :
• Dry or empty vessel• Vessels containing liquid -> Need to consider effect of wetted area of vessel
Fluid relief type could be :
• Fluid is sub-critical: P<0.9*Pc• Fluid is near its critical pressure: 0.9Pc < P < 1.1*Pc• Fluid is super critical (dense phase): P > 1.1*PcPc = Critical PressureP = Relieving Pressure
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SIZING CALCULATIONSIZING CALCULATION
Fire case
Jet Fire
Dry Vessel Wetted vessel
Sub Critical FlowNear Critical FlowSuper Critical Flow
Pool Fire 2 CASES
2 CASES
3 CASES
Totally = 2x2x3 = 12 cases possibleHence 12 methods of calculation for Fire case
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SIZING CALCULATIONSIZING CALCULATION
Determine required relief area for each case (Gas, Liquid, 2-Phases)
Target of sizing relief valve
1. Determine the relief rate.2. Determine the required relief area.3. Select the standard relief area.
Code and standard required
API RP 520 : “ Sizing, Selection, and Installation of Pressure-Relieving “ Sizing, Selection, and Installation of Pressure-Relieving Devices in Refineries.”Devices in Refineries.”
API RP 521 : “ Guide for Pressure Relieving and Depressuring Systems.”“ Guide for Pressure Relieving and Depressuring Systems.”
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SIZING CALCULATIONSIZING CALCULATION
Relief Phase
Single Phase Relief
Two Phase Relief
Vapor Phase Relief
Liquid Phase Relief
Relief Type
Continuous Relief
Transient Relief Thermal Relief
Generally
Gas/Vapor
Steam
Relief fluid categoryDetermine required relief area for each case (Gas, Liquid, 2-Phases)
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SIZING CALCULATIONSIZING CALCULATION
• Determine relief rate, some cases (eg. Gas blow-by, tube rupture, fire case etc.) are very complicated and contain many steps of calculation especially fire case.
• API RP520/ 521 shows the simple method of calculation in order to determine the relief rate. This does not govern all relief scenarios. Hence some companies have developed their own procedure to determine the relief rate.
Determine required relief area for each case (Gas, Liquid, 2-Phases)
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SIZING CALCULATIONSIZING CALCULATION
Vapor Phase Relief• Relief valves for single phase vapour flow will be sized according to the methodology presented in API RP 520, Section 3 (reference 4).
• The sizing equations fall into 2 categories, depending on whether flow is critical or subcritical.
• The critical pressure must be checked using the equation below:
)1(
1 12.
kk
cf kPP
where Pcf = critical flow throat pressure (psia)P1 = upstream relieving pressure (psia)k = ratio of specific heats
Ref. API 520 section 3.6.1.4
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SIZING CALCULATIONSIZING CALCULATION
Vapor Phase Relief• If flow is critical (Pcf > downstream pressure P2), the critical sizing equation is used:
A WCK PK
TZMd b
1
Ref. API 520 section 3.6.2.1
WhereA = required effective discharge area of the valve ( in2).W = required flow through the valve (lb/hr).C = coefficient determined from an expression of the ratio of the specific heats of the gas
or vapour at standard conditions. This can be obtained from Figure 26 or Table 9 in API 520.Kd = effective coefficient of discharge = 0.975 P1 = upstream relieving pressure, in psia.Kb = capacity correction factor due to back-pressure. This can be obtained from the manufacturer’s literature or estimated from Figure 27 in API 520. The back-pressure correction factor applies to balanced-bellows valves only.T = relieving temperature of the inlet gas or vapour, in R.Z = compressibility factor for the deviation of the actual gas from a perfect gas, a ratio evaluated at inlet conditions.M = molecular weight of the gas or vapour.
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SIZING CALCULATIONSIZING CALCULATION
Vapor Phase Relief• If flow is subcritical, the following equation will be used:
)(..735 2112 PPPMZT
KFWA
d Ref. API 520 section 4.3.3.1
Where A = required effective discharge area of the valve, in square inches.W = required flow through the valve, in pounds per hour.F2 = coefficient of subcritical flow
=
rrr
kk k
k
k
11)(
)1(
12
Ref. API 520 section 4.3.3.1
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SIZING CALCULATIONSIZING CALCULATION
k = ratio of the specific heats.r = ratio of back pressure to upstream relieving pressure, P2 /P1.Kd = effective coefficient of discharge = 0.975Z = compressibility at relieving inlet conditions.T = relieving temperature of the inlet gas or vapour (R) M = molecular weight of the gas or vapour.P1 & P2 = upstream relieving pressure and back-pressure pressure respectively (psia)
Vapor Phase Relief
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SIZING CALCULATIONSIZING CALCULATION
Vapor Phase Relief• Relief valves in steam service will be sized as follows:
A WPK K Kd N SH
515 1.
Ref API 520 Section 3.7.1
WhereA = required effective discharge area of the valve ( in2).W = required flow through the valve (lb/hr).P1 = upstream relieving pressure (psia)Kd = effective coefficient of discharge = 0.975KN = correction factor for Napier equation.
= 1 where P1 1515 psia.= (0.1906P1 – 1000)/(0.2292P1 – 1061) where P1 1515 psia and 3215 psia
KSH = superheat steam correction factor. This can be obtained from Table 9 in API RP520. For saturated steam at any pressure, KSH- = 1.0.
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SIZING CALCULATIONSIZING CALCULATION
Liquid Phase Relief• For single phase liquid flow, the sizing method specified for certified relief valves will be used.
• The following equation only applies to non-flashing liquids.
AQ
K K KG
P Pd w v
38 1 2
Ref. API 520 section 4.5.1
Where A = required effective discharge area of the valve ( in2).Q = flow rate, in U.S. gallons per minute.Kd = effective coefficient of discharge that should be obtained from the valve manufacturer. For a preliminary sizing estimation, a discharge coefficient of 0.65 can be used.Kw = correction factor due to back-pressure. If the back-pressure is atmospheric, KW = 1. Balanced-bellows valves in back-pressure service will require the correction factor determined in Figure 31 in API RP520. Conventional valves require no special correction.K-V = correction factor due to viscosity as determined from Figure 32 in API RP520.G = specific gravity of the liquid at the flowing temperature referred to water = 1.0 at 70°F.P1 = upstream relieving pressure, set pressure plus allowable overpressure (psia).P2 = back-pressure (psia).
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SIZING CALCULATIONSIZING CALCULATION
Two Phase Relief
• For 2-phase relief, the methodology in the newly released API 520 Part 1 Appendix D “Sizing for Two-Phase Liquid/Vapour Relief ” shall be used (see Appendix 1).
• This method has superseded the previous API methods because, in certain circumstances, it has been found that the previous API methods for 2-phase flow can undersize PSVs significantly.
• This sizing method is based on the Leung Omega method, which assumes thermal and mechanical equilibrium; these assumptions correspond to the Homogeneous Equilibrium Model (HEM).
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SIZING CALCULATIONSIZING CALCULATION
• Required relief area is calculated from relief rate. Hence relief rate calculation is very important step
• The case which giving the maximum relief area will be a governing case.
Choose the worst case scenario to be a governing case
Determine required relief area for each case (Gas, Liquid, 2-Phases)
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SIZING CALCULATIONSIZING CALCULATION
• Selected standard relief area follows API RP526 or GPSA chapter 5 Figure 5-7
• Valve body size ( Inlet diameter x Outlet diameter) follows API STD 526 “Flanged Steel Pressure Relief Valve 4th Ed June 1995”
• Rated flow = (STD relief area) x Relief rate (Required relief area)
Select proper orifice and valve body size based on STD
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SIZING CALCULATIONSIZING CALCULATION
Calculate inlet line size (Line ∆P < 3%of RP)
• Inlet line sizing is based on pressure drop less than 3 % of relieving pressure
Inlet Line design Consideration• Inlet line size must be at least equal to PSV inlet flange size.
• Inlet piping should slope continuously upward from vessel to avoid traps.
• Inlet piping should be heat traced if freezing or congealing of viscous liquids could occur.
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SIZING CALCULATIONSIZING CALCULATION
Inlet Line design Consideration• A continual clean purge should be provided if coke/polymer formation or solids deposition could occur
• CSO valves should have the stem horizontal or vertically downward
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SIZING CALCULATIONSIZING CALCULATION
Perform preliminary estimate of tail pipe
• Discharge line sizing is based on Mach No. less than 0.75
Tail Pipe Design Consideration
• Discharge line diameter must be at least equal to PSV outlet flange size.
• Atmospheric risers should discharge at least 10 ft above platforms within 50 ft horizontally
• Radiant heat due to ignition of release should be considered.
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SIZING CALCULATIONSIZING CALCULATION
Tail Pipe Design Consideration • No check valves, orifice plates or other restrictions permitted.
• Atmospheric discharge risers should have drain hole.
• CSO valves should have the stem oriented horizontally or vertically. • Piping design must consider thermal expansion due to hot/cold release.
• Autorefrigeration and need for brittle fracture resistant materials.
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SIZING CALCULATIONSIZING CALCULATION
Tail Pipe Design Consideration• Closed discharge piping should slope continuously downward to header to avoid liquid traps
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SIZING CALCULATIONSIZING CALCULATION
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SIZING CALCULATIONSIZING CALCULATION
Perform Flare system modeling to indicate total back pressure and most suitable tail pipe size.
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SIZING CALCULATIONSIZING CALCULATION
Select PSV type (Conventional, Balanced Bellow, Pilot Operated
Type Value(% if set) Conventional Balanced Bellow Pilot Operated
Effects on Valves : Gas applicationsBack Pressure
Constant
VariableSuperimposed
VariableBuilt-up
< 30%30-50%
>50%
No effectLift/Capacity reduced No effect
Set point increased by back pressure
Set point increased by back pressure Flow become sonic
Generally unstable Do not use
Flow become subsonic
Set point varieswith back pressure
10-30%
< 10% No effect
> 50%
30-50%Unstable
Do not use Lift/Capacity reduced Generally unstable
Do not use
No effect
Flow become subsonic
< 10%
Unstable Do not use
Lift/Capacity reduced
No effect No effectNo effect
Generally unstable Do not use
10-30%
> 50% Flow become subsonic
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SIZING CALCULATIONSIZING CALCULATION
Select PSV type (Conventional, Balanced Bellow, Pilot Operated
Type Value(% if set) Conventional Balanced Bellow Pilot Operated
Effects on Valves : Liquid applicationsBack Pressure
Constant
VariableSuperimposed
VariableBuilt-up
< 20%20-50%
>50%
No effectLift/Capacity reduced
No effect
Set point increased by back pressure
Set point increased by back pressure Flow become sonic
Generally unstable Do not use
Set point varieswith back pressure
10-20%
< 10% No effect
> 50%
20-50%Unstable
Do not use Lift/Capacity reduced Generally unstable
Do not use
No effect
< 10%
Unstable Do not use
Lift/Capacity reduced
No effect No effect
No effectGenerally unstable
Do not use
10-20%
> 50%
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EXAMPLEEXAMPLE
DP = 400 psigPAH = 350 psigOP = 275 psigOT = 80 oF
DP = 250 psigOT = 130 oF
CV = 433
SP = 250 psig
SP = 400 psig
CV = 433FC
FC
V-1
V-2
F-1
F-2
Process Schematic PSV-1
PSV-2
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EXAMPLEEXAMPLE
Assess Relief Scenarios
Scenario Source of Overpressure
Judement Scenario to be considered separately
1 Fire Case An external fire could cause the pressurein V-6010 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.
Yes
2 Tube Rupture This case is not applicable. No
3 Inlet control valve failure
CVs are fail to close type therefore this caseis not applicable for sizing PSV.
No
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EXAMPLEEXAMPLE
Scenario Source of Overpressure
Judement Scenario to be considered separately
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 follow assumption
• 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
Assess Relief Scenarios
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EXAMPLEEXAMPLE
Scenario Source of Overpressure
Judement Scenario to be considered separately
5 Blocked Outlet1. Water Blocked Discharge. This scenario will relates 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 response. Hence, this scenario cuts off the feed to vessel and no relief is needed.2. Oil Blocked Discharge. This scenario relates to only oil trip, whileinterface level is already healthy. No credit can be taken that this trip will work. Hence PSV needs oil relief.
Yes
Assess Relief Scenarios
6 Thermal Relief This case is not applicable. No
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EXAMPLEEXAMPLE
Possible Relief Scenarios
There are three different possible relief scenarios :• Fire Case.• Gas Blow-by Case. • Blocked Outlet Case.
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EXAMPLEEXAMPLE
Fire Case ScenarioAn 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 psigAllowable Accumulation = 21%Maximum allowable accumulated pressure = 250x1.21 = 302.5 psig.Relieving temperature = ????
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EXAMPLEEXAMPLE
Fire Case
250 psig@61 min , relief temperature = 191.5 oF
Since relief can be initiated after 61 min fired but API RP 520 allow 15 min to handle fire hence “this case will rarely happen in real operation.”
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EXAMPLEEXAMPLE
Fire Case
By input all required parameters (eg. Vessel dimensions, fluid relieving properties), in to calculation sheet (WS-CA-PR-025, Rev 0)
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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EXAMPLEEXAMPLE
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 is based on follow assumption
• 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 as locked close. (Note : This may need to be considered in some cases).Relief ConditionPSV-2 set pressure = 250 psigAllowable Accumulation = 10%Maximum allowable accumulated pressure = 250x1.1 = 275 psig.
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EXAMPLEEXAMPLE
Gas Blow-by
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 = 11,474.5V-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 psiReliving temperature = 80 deg F
How to find the maximum relief rate via F-1 and/or F-2 ?????
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EXAMPLEEXAMPLE
Gas Blow-by
Maximum relief rate = 245,703.5 lb/hr
Maximum relief ratecan be evaluated from control valve sizing Programs (eg. Fisher,Masoneilan etc.) or sizing equations eg.in GPSA.
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EXAMPLEEXAMPLE
Gas Blow-by By input all required parameters (eg. fluid relieving properties), in to calculation sheet (WS-CA-PR-025, Rev 0) for generally vapor relief.
Required relief area = 11.57 in2
Relief Load = 245,703.5 lb/hr
Therefore
Select 6xRx8 orifice with discharge area of 16 in2
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EXAMPLEEXAMPLE
Blocked Outlet
1. Water Blocked Discharge. This scenario will relates 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 response. Hence, this scenario cuts off the feed to vessel and no relief is needed.
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.
Relief conditionPSV-2 set pressure = 250 psigAllowable Accumulation = 10%Maximum allowable accumulated pressure = 250x1.1 = 275 psig.Relieving temperature = 130 oF
OIL & GAS
EXAMPLEEXAMPLE
Blocked Outlet
From simulation Oil flow rate = 508,100 lb/hr (25,000 bpd) Oil density = 55.21 lb/ft3
By input all required parameters (eg. fluid relieving properties), in to calculation sheet (WS-CA-PR-025, Rev 0) for generally liquid relief.
Required relief area = 2.76 in2
Therefore select a 3xLx4 orifice with discharge area of 2.853 in2
OIL & GAS
EXAMPLEEXAMPLE
Relief Case Design Orifice Size Relief Phase
Fire Case 1xEx2 Vapor
Gas Blow-by 6xRx8 Vapor
Blocked Outlet 3xLx4 Liquid
Selection of Governing Relief Scenarios
OIL & GAS
EXAMPLEEXAMPLE
Therefore the governing case is Gas Blow-by case
Required relief rate = 287,530 lb/hrRequired relief area = 11.57 in2
Selected relief area = 16 in2
Rated flow = 16 x 287,530 lb/hr = 397,621 lb/hr 11.57
Selection of Governing Relief Scenarios
OIL & GAS
EXAMPLEEXAMPLE
Inlet line sizing calculation
Inlet line sizing calculation is based on pressure drop less than 3 % of set pressure
PSV set pressure = 250 psigAllowable pressure drop = 0.03x250 = 7.5 psiMass rated flow = 397,621 lb/hr
Based on maximum rated flow and its relief properties For 8” inlet line, single phase pressure drop is 5.3 psi therefore suitable for inlet line sizing criteria.
OIL & GAS
EXAMPLEEXAMPLE
Outlet line sizing calculation
Outlet line sizing calculation is based on the maximum Mach No. of 0.75
From preliminary estimation 12” line give Mach No. of 0.71 hence suitable for outlet line sizing criteria.
Result from FlareNet modeling show 10” give Mach No. of 0.45 ?????
OIL & GAS
EXAMPLEEXAMPLE
Selection of Relief Valve Type
Result from FlareNet simulation give total back pressure of 70 psig
PSV set pressure = 250 psig
PSV type
Conventional
Balanced Bellow
Pilot Operated
% of Maximum Back Pressure Allowable
10% of SP
30% of SP
N/A
Maximum Back Pressure Allowable
(psig)
25 psig
75 psig
N/A
OIL & GAS
EXAMPLEEXAMPLE
Summary
6xRx8 Balanced Bellow PSVInlet line size is 8” Outlet line size is 10”
10”8”x10”
8”x6”
8”
Gas Blow-bySet@250 psigBalanced Bellow