PSV Calculation

23-June-05

OIL&GAS OIL & GAS

• INTRODUCTION • PSV TYPES • CHA CHATTERING TTERING PROBLEM • SIZING CALCULA CALCULATION TION • EXAMPLE

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• INTRODUCTION • PSV TYPES • CHA CHATTERING TTERING PROBLEM • SIZING CALCULA CALCULATION TION • EXAMPLE

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or der to • Relief systems are provided on a platform in order 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 lev els of ov over er 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 w hich may exceed exceed the maximum allowable working working pressure.

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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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Definitions • Operating pressure : The gauge pressure during normal service. • Set Pressure : The pressure at which the relief device begins to activate or open. • 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. • Accumulation : The pressure increase over the maximum allowable working pressure of a vessel during the relief  process. Expressed as % of MAWP. OIL & GAS

Accumulation

Pressure Set Pressure

Relief begin to open

Time OIL & GAS

Definitions • Over 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. Over Pressure Set Pressure

Pressure

Relief begin to open

Time

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Definitions • Blow-down : The pressure difference between the relief  set pressure and the relief reseating pressure.

• Maximum Allowable Accumulated Pressure  : The sum of  the maximum allowable working pressure plus the allowable accumulation.

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Guideline for relief pressures (Adapted from API RP 520 : “ Sizing, Selection, and Installation of Pressure -Relieving  Devices in Refineries.” , page 3) OIL & GAS

Definitions • Back Pressure  : The pressure at the outlet of the relief  device during the relief process due to pressure in the discharge system. 1. 2.

Superimposed Back Pressure. Built-up Back Pressure.

Total Back Pressure = Superimposed Back Pressure + Built-up Back Pressure

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Definitions 1. Superimposed Back Pressure is the back pressure which may exist at the outlet of a particular relief valve when connected to a closed system. The pressure can be constant or variable. The Superimposed back pressure always exists even when the relief  valve 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 pressure depends 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 pressure Loss. The built-up back pressure is variable.

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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 •

4.

Kept closed by process pressure

Modulating Pilot.

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The following types of PSV are generally used. 1. 2. 3. 4. 5.

Conventional PSV Balanced Type PSV (Balanced Bellow) Pilot Operated PSV Modulating Pilot Operated PSV Thermal PSV

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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

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

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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. OIL & GAS

100 % Lift

Main valve piston lift

POP Action Opening

Closing

Pressure

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Modulating

100 % Lift

Main valve piston lift Closing

Opening

Pressure

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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

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Cause of Chattering • Excessive inlet pressure drop • Excessive built-up back pressure • Oversized valve • Valve handling widely differing rates

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Excessive inlet pressure drop • Normal PSV has definite pop and reseat pressures. Blow-down = Different between pop and reseat pressure

Reseat or close pressure

Pop or opening pressure

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Excessive inlet pressure drop : Solution

If you can’t change the piping • Install smaller PSV • Install different type of  PSV

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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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Improper Valve Size Oversized 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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Step Of Sizing Calculation Develop 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 OIL & GAS

Develop Process Safety Diagram (PSD) Process safety diagram is the diagram which show all installation of all process safety equipments (PSHH, TSHH, PSV, BDV, Rupture disc, etc.) intend to be used in evaluation of all possible relieving scenarios in process facilities. Process safety diagram must be developed before performing any PSV calculation.

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Develop Process Safety Diagram (PSD)

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Develop relief scenarios by using general possible cause and PSD

Possible Scenarios

Equipment 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!! OIL & GAS

Blocked Outlet/ Blocked Discharge

CLOSED

CLOSED CLOSED

CLOSED

Compressor

Pump

CLOSED

Process Vessel 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). OIL & GAS

Thermal Expansion/ Thermal Relief  Hot Side

Cold Side CLOSED

CLOSED

CLOSED

Line Heat Exchanger  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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Tube Rupture Hot Side

Cold Side

Heat Exchanger 

Hot Side

OR Cold Side

Heat Exchanger 

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. OIL & GAS

Gas Blow-by

Pressure at PSHH Liquid at LSLL

Suddenly Opening

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.

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Inlet Control Valve Failure

Pressure at normal Liquid at normal

Fail to open

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). OIL & GAS

Exterior Fire Generally, 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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Fire Type

Pool Fire

Systems with significant liquid hydrocarbon 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.

Jet Fire

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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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 1.1*Pc Pc = Critical Pressure P = Relieving Pressure OIL & GAS

Fire case

Jet Fire

Dry Vessel

Super Critical Flow

2 CASES

Pool Fire

Wetted vessel

Near Critical Flow

2 CASES

Sub Critical Flow

3 CASES

Totally = 2x2x3 = 12 cases possible Hence 12 methods of calculation for Fire case OIL & GAS

Determine required relief area for each case (Gas, Liquid, 2-Phases)

Target of sizing relief valve 1. 2. 3.

Determine the relief rate. Determine the required relief area. Select the standard relief area.

Code and standard required API RP 520 :

“ Sizing, Selection, and Installation of Pressure -Relieving  Devices in Refineries.” 

API RP 521 :

“ Guide for Pressure Relieving and Depressuring Systems.” 

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Determine required relief area for each case (Gas, Liquid, 2-Phases)

Relief fluid category Vapor Phase Relief  Single Phase Relief 

Gas/Vapor  Steam

Liquid Phase Relief  Relief Phase Two Phase Relief 

Continuous Relief 

Generally

Transient Relief 

Thermal Relief 

Relief Type

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Determine required relief area for each case (Gas, Liquid, 2-Phases)

• 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 deter mine the relief rate.

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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:

 2  Pcf   P1 .  k   1

k 

( k 1)

Ref. API 520 section 3.6.1.4

where Pcf  = critical flow throat pressure (psia) P1 = upstream relieving pressure (psia) k = ratio of specific heats OIL & GAS

Vapor Phase Relief  • If flow is critical (P cf  > downstream pressure P2), the critical sizing equation is used:

 A  Where  A W C

Kd P1 Kb

T Z M

W 

TZ 

C Kd  P1 K b 

 M 

Ref. API 520 section 3.6.2.1

= required effective discharge area of the valve ( in2). = required flow through the valve (lb/hr). = 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. = effective coefficient of discharge = 0.975 = upstream relieving pressure, in psia. = 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. = relieving temperature of the inlet gas or vapour, in R. = compressibility factor for the deviation of the actual gas from a perfect gas, a ratio evaluated at inlet conditions. = molecular weight of the gas or vapour.

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Vapor Phase Relief  • If flow is subcritical, the following equation will be used:

 A 

Where A W F2

W 

 ZT 

735.F 2 K d 

 M .P1 ( P1  P2 )

Ref. API 520 section 4.3.3.1

= required effective discharge area of the valve, in square inches. = required flow through the valve, in pounds per hour. = coefficient of subcritical flow k 1   k  1  r  k  k    (r ) (k   1)  1  r     2

=

Ref. API 520 section 4.3.3.1

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Vapor Phase Relief  k r Kd Z T M P1 & P2

= = = = = = =

ratio of the specific heats. ratio of back pressure to upstream relieving pressure, P2 /P1. effective coefficient of discharge = 0.975 compressibility at relieving inlet conditions. relieving temperature of the inlet gas or vapour (R) molecular weight of the gas or vapour. upstream relieving pressure and back-pressure pressure respectively (psia)

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Vapor Phase Relief  • Relief valves in steam service will be sized as follows:

 A 

Where  A W P1 Kd KN

KSH

= = = = = = = =

W  51.5 P1 K d K N K SH  

Ref API 520 Section 3.7.1  

required effective discharge area of the valve ( in2). required flow through the valve (lb/hr). upstream relieving pressure (psia) effective coefficient of discharge = 0.975 correction factor for Napier equation. 1 where P1  1515 psia. (0.1906P1 – 1000)/(0.2292P1 – 1061) where P1  1515 psia and  3215 psia 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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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 .

 A  Where  A Q Kd Kw

K-V G P1 P2

Q

G

38 K d K w K v

P1  P2

Ref. API 520 section 4.5.1

= required effective discharge area of the valve ( in2). = flow rate, in U.S. gallons per minute. = 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. = 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. = correction factor due to viscosity as determined from Figure 32 in API RP520. = specific gravity of the liquid at the flowing temperature referred to water = 1.0 at 70 F. = upstream relieving pressure, set pressure plus allowable overpressure (psia). = back-pressure (psia). °

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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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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.

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Select proper orifice and valve body size based on STD

• 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)

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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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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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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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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. OIL & GAS

Tail Pipe Design Consideration • Closed discharge piping should slope continuously downward to header to avoid liquid traps

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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

Value (% if set) < 30%

Constant

Variable Superimposed

30-50%

Effects on Valves : Gas a pplications Conventional Set point increased by back pressure

>50%

Set point increased by back pressure Flow become sonic

< 10%

Set point varies with back pressure

Pilot Operated

No effect Lift/Capacity reduced Generally unstable Do not use

No effect Flow become subsonic

No effect No effect

10-30% 30-50%

Unstable Do not use

< 10% 10-30% > 50%

Lift/Capacity reduced Generally unstable Do not use

> 50%

Variable Built-up

Balanced Bellow

No effect

Flow become subsonic

No effect No effect

Unstable Do not use

Lift/Capacity reduced Generally unstable Do not use

Flow become subsonic

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Select PSV type (Conventional, Balanced Bellow, Pilot Operated Back Pressure Type

Value (% if set) < 20%

Constant

Variable Superimposed

20-50%

Effects on Valves : Liquid applications Conventional Set point increased by back pressure

>50%

Set point increased by back pressure Flow become sonic

< 10%

Set point varies with back pressure

Pilot Operated

No effect Lift/Capacity reduced No effect Generally unstable Do not use No effect

10-20% 20-50%

Unstable Do not use

< 10% 10-20% > 50%

Lift/Capacity reduced

No effect

Generally unstable Do not use

> 50%

Variable Built-up

Balanced Bellow

No effect Unstable Do not use

No effect Lift/Capacity reduced Generally unstable Do not use

No effect

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SP = 400 psig

Process Schematic

PSV-1 DP = 400 psig PAH = 350 psig OP = 275 psig OT = 80 oF

V-1

SP = 250 psig F-1

PSV-2

CV = 433 FC

F-2

V-2

DP = 250 psig OT = 130 oF

CV = 433 FC

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Assess Relief Scenarios Source of  Scenario Overpressure 1

Fire Case

2

Tube Rupture

3

Inlet control valve failure

Judement

An external fire could cause the pressure in 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.

This case is not applicable.

CVs are fail to close type therefore this case is not applicable for sizing PSV.

Scenario to be considered separately Yes

No

No

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Assess Relief Scenarios Judement

Source of  Scenario Overpressure 4

Gas Blow-by

Gas blow-by can occur by

Scenario to be considered separately Yes

• 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.

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Assess Relief Scenarios Source of  Scenario Overpressure

Judement

Scenario to be considered separately

5

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.

Yes

6

Thermal Relief  This case is not applicable.

No

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Possible Relief Scenarios

There are three different possible relief scenarios : • 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 Relie ving temperature = ????

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Fire Case 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.”

250 psig@61 min , relief temperature = 191.5 oF

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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 in 2 Relief Load = 4,066 lb/hr  Therefore Select 1xEx2 orifice with discharge area of 0.196 in 2

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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 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 Condition PSV-2 set pressure = 250 psig Allowable Accumulation = 10% Maximum allowable accumulated pressure = 250x1.1 = 275 psig. OIL & GAS

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 = 11,474.5 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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Gas Blow-by Maximum relief rate can be evaluated from control valve sizing Programs (eg. Fisher, Masoneilan etc.) or sizing equations eg.in GPSA.

Maximum relief rate = 245,703.5 lb/hr 

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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 in 2 Relief Load = 245,703.5 lb/hr 

Therefore Select 6xRx8 orifice with discharge area of 16 in 2

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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 condition PSV-2 set pressure = 250 psig Allowable Accumulation = 10% Maximum allowable accumulated pressure = 250x1.1 = 275 psig. Relieving temperature = 130 oF

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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 in 2 Therefore select a 3xLx4 orifice with discharge area of 2.853 in 2

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Selection of Governing Relief Scenarios Relief Case

Design Orifice Size

Relief Phase

Fire Case

1xEx2

Vapor 

Gas Blow-by

6xRx8

Vapor 

Blocked Outlet

3xLx4

Liquid

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Selection of Governing Relief Scenarios Therefore the governing case is Gas Blow-by case Required relief rate = 287,530 lb/hr  Required relief area = 11.57 in 2 Selected relief area = 16 in 2 Rated flow =

16 x 287,530 lb/hr = 397,621 lb/hr  11.57

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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 = 0.03x250 = 7.5 psi Mass 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.

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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 ?????

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Selection of Relief Valve Type Result from FlareNet 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

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