pressure relief systems 2014 rev a

PRESSURE RELIEF SYSTEMS

June 2014

AcknowledgmentAPI STD - RP 520/ 521/ 526/ 537

Various Client/ Project Standards/ Specifications

Pictures from many sources, suppliers, internetDEDICATED TO:

My friend Winston Yeo, KBR, Singapore/ Chevron, Thailand

Topics

� Introduction

� Relief Devices

� Codes & Standards

� Relieving Scenarios (Demands) & Loads

� Sizing

� Installation

� Isolation

� Design Features

Introduction

� Control system maintains stable operation

� Trip / shutdown system provides primary protection, when control system fails

� Relief system provides secondary protection, when control and trip systems fail – ultimate protection or last line of defence

Production

Separator

PAHH

PALL

PIC

SDV

SDV

SDV

SDV

T0 Compressor

T0 Flare

Well Fluids

Oil/ Condensate

Produced WaterRV lifting: a serious incident

NOP

PIC/PAH

PAHH

PSV

Code Vs Recommended Practice

� Relief devices – key part of plant Layer of Protections to protect plant and personnel. Prevent production loss

� Relief devices are required by national codes and standards, mandated under law

ASME is a Code. Compliance is mandatory.

API is a recommended practice.

API is also getting adopted as a National /

International Standard

Community Emergency Response

Emergency, Evacuation

Plant Emergency Response

Containment/ Evacuation Procedure

Mitigation

Mechanical mitigation, Relief System

Operator Action

Prevention

SIS Trips

Operator Response

Controls & Monitoring

Controls, Alarms

Operator Supervision

Process

Where Pressure Relief is not possible

� Fast chemical reactions: � Pressure propagation rate is very high and loss of

containment may occurs before RV pops.

� “hot spots,” decompositions & internal detonation/fires

� Relieving rate requires large relief areas

� Plugging, polymerization or deposition that may partially or completely block RV� Relieved chemicals may polymerize and plug. PSV useless

� Multi-phase relief: where rate is difficult to predict

� Relief may create additional hazards due to stack location or very large vent/ flare system

� Use HIPPS

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Relief Scenarios

Air freshener can in a closed

car - Thermal

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Column internals - Pyrophoric fire

Semi sub – what was leftVacuum column fire

Tank drained. Pulled

vacuum

RELIEF DEVICES

Relief Devices

� Relief Valves

� Rupture Disks

� Rupture Pins

� Buckling Pins

� PVRV

� Blow-off Hatches

� Explosion Doors

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Relief Devices




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Relief Valves

� Conventional

� Balanced

� Pilot

Conventional RV

� Most common

� Simple, cheap and reliable

� Backpressure reduces capacity

� Variable back pressure limited to 10% of set pressure

� Large spring required limits set pressure of bigger PSV

� Constant or superimposed backpressure increases set point on a 1 for 1 basis


D – P Q R T

285 165 100 65

150# RV Set Press, psig at 100°F

Why?

Back Press �

Se

t P

ress

�

100

0 50

Balanced Bellows RV

� Not allowed per ASME section I

� Back pressure max 30% on all except smaller sizes. Up to 50% with capacity correction

� Fragile bellows. Mechanical limit imposed by bellows

� Bellows can plug; movement restricted In plugging and polymerizing service

� Bellows sealed in hydrate, solid, foaming and coking services to keep foreign matter out of bonnet

� Bellows prone to fatigue and pin-hole leaks. [Leaks take away ability to handle backpressure; hence bonnet is vented. As long vent is bigger than “holes” OK.]

� Bonnet vent must be routed to safe location in toxic service


Bellows original purpose was to protect the

spindle & guide from corrosive fluids. Beyond 30%

back pressure, lift and hence capacity affected

Why?

Balanced Disk RV

� Backpressure acting on top and bottom of disk cancels each other

� Backpressure ha no effect on RV opening or closing pressure



Back Press �

Se

t P

ress

�

100

0 50

RV Opening Pressure

RV Reseating Pressure


Pilot RV

� Process pressure on a differential area piston keeps the seat closed

� Pilot: A small PSV that pops and removes piston top pressure, allowing the main valve to open


Pilot

Pilot Dome

Dome

Piston

Pilot Tube

Pilot Tube

Note: Piston top area > bottom area. For the same pressure, force on top > force on bottom, keeping the seat closed

More on Pilot RV

� Process pressure on the larger piston (top) area opposes pressure on the smaller seat, keeping the valve shut

� Higher the process pressure, greater the downward force, keeping the seat tightly closed. c.f spring loaded RV

� A small auxiliary relief valve (pilot) controls the main RV. It pops open relieving top pressure, opening main RV

� Larger RVs can have higher set pressures; no longer limited by spring force. c.f spring loaded RV

� Full lift and capacity achieved near set pressure as there is no heavy spring load to overcome

� With pop action, full lift at set pressure; with modulating pilot, full lift at relieving pressure; modulating pilot relieves only what is required

More on Pilot Pilot is a small RV!

1. As process pressure reaches set pressure, the

spring is compressed; lower feeding seat closes,

isolating process gas

2. Upper seat opens, venting gas and pressure in

dome; and opening RV

� Process gas isolated during a relief – no flow pilot

� Flowing pilot, discharges process gas before,

during and after a relief. Not recommended

� Flowing design may lead to freezing or

particulates into the pilot

� Based on one-shot venting or gradual venting

“pop” or “modulating” action

� “Pop” or fast action is for rapid relief of gas.

Recommended. Spring loaded RV

� “Modulating” allows RV opening with a small

pressure rise; fast response. Relieves what is

reqd. Diaphragm RVSpindle travel - decides

blowdown. 3% blowdown possible


1

2

More on Pilot RV

� Most have soft seats; remote sensing capability – pilot tube intake need not be at RV inlet

� Polymerizing, plugging service, sensing line can plug. Use non-flow type or filtered sensing line in dirty service

� Backpressure: Set pressure not affected unless pilot is vented to headerCaution: Higher backpressure can lead to reverse flow and product contamination, during start-up and shutdown. Use check valve

� Usual to have no-flow, pop action elastomer seat/ seal type.

� Less commonly used. May require prior approvalLiquid filled systems: Blowdown may change c.f gas service. Operating time too rapid -

producing water hammer or too slow. Pilot affected by particulate contamination or corrosion


Capacity - Back Pressure Impact

� RV: ‘Nozzle’ or ‘orifice’ -

flow decided by:

� upstream pressure, as long

as it is ‘critical’ or ‘sonic’

� ∆P, Pressure drop (P1-P2), if

sub-sonic

� Back-pressure adds to

spring force, reduces lift

and flow (‘capacity’ of RV)

Transition Point

Sonic to Sun-sonic

Back Pressure - Conventional RV

� Backpressure affects lift;

impacts capacity severely



At 15% valve fully closed

Back Pressure - Balanced Bellows

� Bellows nullify backpressure effect to an extentThe linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location.


Difficult to have small bellows. Size D & E, may be a ‘modified’ F !!

Bellows Bellows fixed at at upper end. High back pressure lengthens

the bellows at the lower end, restricting seat lift

At 30% capacity reduced

Back Pressure - Balanced Disk RV

� Disk nullify backpressure effect to an extent



At 20% capacity reducedAt 30% capacity reduced

Balanced Spindle type can withstand higher backpressure; Sizes to 2J3 only

Back Pressure - Pilot RV

Flow

� Flow follows closely nozzle flow

� For k = 1.3 & BP = 70%. Flow:

Nozzle = 92% Pilot = 78%

� Back flow Preventer:

Backpressure may open the

main valve when process

pressure is low as at start-up.

May contaminate products. C3

Refrigeration

Back Pressure Impact - Comparison

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Set Pressure Vs Lift

Conventional

Pilot



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� University of Milan Test on 5 Balanced RV, 2 J 3

� Supposed to be good to 50% BP viz k = 1

� Capacity Lost, % at BP, % Remarks

A 10 50

B 30 50

C 40 30

D 20 30 0% at 32%

E 60 18 bellow ruptured

Backpressure Impact - Tests

Terminology - Refresher

� Relief Valve: Valve opens in proportion to

overpressure. Liquid (incompressible fluids)

service

� Safety Valve: Valve opens rapidly with pop action.

Vapour (compressible fluids) service

� Safety Relief Valve: Either a safety or relief valve

� Pressure Relief Valve: Generic term for all of

above


� MAWP: Max Allowable Working Pressure on top of vessel based on wall thickness provided at coincident temperature. ≈> Design Pressure

� Design Pressure: Equipment/ system design pressure at design temperature

� Set Pressure: Pressure at which RV is set to open. May be same or less than Design Pressure

� Overpressure: Pressure increase over set pressure

� Relieving Pressure: Set pressure + Overpressure

� Accumulation: Pressure increase over MAWP

� Back pressure: Pressure at the outlet flange/ pressure in discharge system

Where RV is set below MAWP, overpressure can be higher to match MAWP + Accumulation


� Superimposed back pressure - Affects set pressure.Pressure at outlet flange before RV opens� Constant superimposed BP: Always the same pressure. When RV

discharges to a closed system. Can be high ~ 50% of set pressure.

� Variable superimposed BP: Varies based on flow from other sources. When multiple sources discharge to a common header

� Built-up back pressure - Does not affect set pressure but affects capacityPressure that develops in the discharge header as a result of flow thru RV

� Total back-pressure = Superimposed + Built-up BP

� Spring differential: Difference between set pressure and superimposed constant BP. It is not wise to give a superimposed constant BP in a data sheet unless one exists.

E-001

V-002

Why?

Back Pressure - ExampleFlare Stack

Flare Header

Flare Knockout DrumRelief valve

Normal Operating Press = 0.3 U

∆P = 5 U

∆P = 10 U due to flow from this +other PSVs

SP = 100 Units

� Superimposed Constant Back Press = 0.3 U

� Built-up Back Pressure = 15 U

� Total Back Pressure = 15.3 U

� Spring Differential (Set Pressure – Constant BP)

� Spring set at: = 99.7 U

Care needed while

specifying constant BP

Back Pressure - More Info

� Backpressure adds to spring load, prevents full lift� Flow and backpressure reduced; Valve opens again

� Close �Open. Rapid cycling or chattering

� P1, backpressure at valve outlet flange is known and NOT PB inside the valve at nozzle outlet

� Bigger the RV, smaller is Outlet: PSV area (Ao/A) ratio; Higher is PB

� PB, controls flow in sub-sonic cases

� Vendors have come up with a correction factor to Nozzle Coefft, to account for this – based on valve body / nozzle geometry


P2

PB

Outlet: PSV Area Ratio

Size

Area, in2

(Ao/A)

1½ D 2 0.110 (31)

1½ E 2 0.196 (17)

1½ F 2 0.307 (11)

2 G 3 0.503 (15)

2 H 3 0.785 (9)

3 J 4 1.287 (10)

3 K 4 1.838 (7)

3 L 4 2.853 (5)

4 M 6 3.600 (8)

4 N 6 4.340 (7)

4 P 6 6.380 (5)

6 Q 8 11.050 (5)

6 R 8 16.000 (3)

8 T 10 26.000 (3)

Design Tip: Backpressure mechanical limit on RV is

decided by bellows. Bigger the RV lower is

allowable backpressure. Affects non-flowing RVs

too; forgotten by Process Engineers. See RP 526


� Blowdown: Difference between set pressure and reseating pressure, % of set pressure. Usually 3%

� Cold differential test pressure: Set pressure with correction for backpressure and/or temperature service condition

� Simmer: Audible or visual release of fluid across the RV just prior to opening at set pressure. Excessive simmering is detrimental to valve seating surfaces

� Chattering: Rapid opening and closing of RV in quick succession. Wear and tear on seating surfaces leading to leak in normal operation. Caused by:� Oversized RV

� Inlet loss > 3%

� Excessive back-pressure

� Broken or leaking balanced bellows

� Lift: Rise of the disc to open the RV

RV Operation - Refresher

� As the seat lifts, flow is thru (i) nozzle at full lift or (ii) curtain for partial lift

� Nozzle Area = πD²/4Curtain Area = πDL; L = D/4

Usual lift is about 35 to 40%

� At PSV opening point,press * area = spring load

� To reach full lift, additional overpressure required, say 10% to compress the spring. Not enough.

� Solution? Add a skirt to seat, to add ‘area’ and redirect flow to add to lift

� Blowdown Ring, controls blowdownTop: Short Simmer; long blowdown

P

S

Seat Disk

Skirt

Blowdown Ring

IncreasesDecreaseBlowdown

Nozzle Diameter, D

Cu

rta

inL

ift,

L

Boiler Board

Formula with Lift

RV Operation - RefresherThis image cannot currently be displayed.

Rupture Disks

� Non-reclosing� Good for large relief; instantaneous and unrestricted relief

� For valuable/ toxic fluids (no leak) and viscous, high melting point fluids

� For corrosive and slurry (no exposed seat/ spring)

� Used upstream and downstream of RV in corrosive services

� Upstream of RV� Protects RV internals from corrosion – save $$ using standard

MOC; Prevents leakage thru RV; Prevents plugging and gumming of RV; Allows in-situ calibration testing of RV

� Downstream of RV� Protects RV internals from corrosion – save $$ using standard

MOC; Check leakage thru RV; Prevents fouling and gumming of RV; Cushions impact of variable backpressure

� In parallel to or in series with RV

Non-reclosing: Unlike a PSV that closes once the pressure < set pressure, RDs remain open and discharge the contents. It has to be replaced after an event

Note: Max distance between RD and PSV = 5D

Design Tip: RD + RV requires Combined Capacity Factor ≈ 0.9 factor on RV area; combined inlet ∆P <3%. RD burst pressure ≈ 90-100% RV set pressure (ASMEVIII Div 1 UG-127 foot note 52 + UG132 (a)(4)(a))


Rupture Disks

� Conventional tension loaded type� Op pressure <70% of burst pressure

� Fragments and not used under RV

� Reverse buckling disk� Op pressure <90% of burst pressure

� Can withstand pressures in excess of burst pressure on the outlet.

� Non-fragmenting. Can be used under RV

� PAH set at >10% set point required between RD & RV.

� Liquid service disk� Disk full open without the stored

compressed energy of vapour



Reverse: Snap back action reqd to move the disc thru knife blade. May not be reliable in liquid service. Scored design instead of knife-cut!

Rupture Disks

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2 RDs in series may be required, if

variable backpressure is significant.What is the gauge pressure?.

What it tells you?

Why?

Leakage thru RD can increase the

pressure in the cavity between RD

and RV, reduce dP across RD and

hinder RD opening. Provide a

PG/PAH/vent line d/s of RD Burst pressure dependency on design Vs Operating temperature

Rupture Disk Vs Relief Valve


‘Combining RDs with RVs’, Roger

Bours, Chemical Engg, June 2014


Rupture Pins

� As a replacement for relief valves. Non reclosing type.

� Good for large loads

� Usually in alternative paths to staged flares


Buckling Pinshttp://www.bsb.ie/Buckling_Pin_Relief_Valves/BPRV_buckling_pin_relief_vent.html






� As a replacement for relief valves. Non reclosing type.

� Instead of relieving, isolates the high pressure source; eliminates flaring

� Clapper, disk, piston or plunger valve held in place by a pin

� When the pin buckles, the valve is instantly closed.

� Not Approved by ASME. OK for Pipelines under Dept of Transportation Code

Open

Closed

Pin

Pressure Vacuum Relief

PVRV/Blow-off Hatches/ Explosion Doors

� PVRV

� Low set pressure - from few mm of H2O to 1 bar( 15 psig)

� Generally for Storage Tank protection

� Blow-off Hatches/ Explosion Doors

� For infrequent large releases

� Used generally for Storage Tank protection

� In furnace fire boxes (“Explosion Doors”)





RELIEF DEVICES SELECTION

Relief Devices - Selection

� Type of relief valve� Based on backpressure and service

� Steam service: direct spring loaded “pop action” type.

� As back pressure on the valve rises� from conventional to balanced bellows to pilot

� Rupture disks: Rapid rise in pressure, corrosive services or for very large relieving areas� E.g. Heat Exchanger Tube Rupture, Reactor

� RD + RV to avoid emissions or in corrosive service

� RD + RV: Non fragmenting RD and consider combination capacity reduction factor

Relief Devices - Comparison

Weighted Pallet

� Low Cost

� Very Low Set Pressure

� Set Press, not adjustable

� High over pressure 100%++

� Seat can be frozen

Conventional PSV – Metal Seat

� Lowest Cost

� Good Chemical & Temp compatibility

� Seat Leakage = Product Loss

� Long simmer or blowdown

� Affected by inlet press loss

� Affected by back pressure

� Difficult to check Set Press in-place

Balanced Bellows – Metal Seat

� Set Press constant with back press

� Good Chemical & Temp compatibility

� Seat Leakage

� Long simmer or blowdown

� Limited bellows life

� Affected by inlet press loss

� Affected by higher back pressure

� Difficult to check Set Press in-place

Soft Seat: Good tightness; but elastomer will

limit chemical & temp capability


Pilot - Soft Seat - Piston Type

� Smaller & Lighter

� Excellent Seat Tightness

� Pop or Modulating Action

� In-line maintenance of main valve

� Set Pressure can be tested in-situ. Only pilots are tested

� Adaptable for remote press sensing

� Remote unloading possible

� Not OK in polymerizing or dirty service

� Limited Chemical & Temp Compatibility

� Limited Low Press Setting >15 psig

� Not Allowed under ASME Sec I

Pilot - Soft Seat - Diaphragm or Bellows

� Good for Low Press operation 3” WC


� Pop or Modulating Action

� In-line maintenance of main valve

� Set Pressure can be tested in-situ. Only pilots are tested


� Remote unloading possible

� Fully opens at Set Pressure

� Not OK in polymerizing or dirty service

� Limited Chemical & Temp Compatibility

� Limited High Press Setting <50 psig

� Liquid service limitations


Rupture Disks

� Good tightness, if disk is intact

� Wide choice in material

� Minimum space

� For high capacity relief as in FCCU

� For secondary relief in parallel to a RV

� Wide tolerance in burst pressure

� Non-reclosing

� Premature rupture, with pressure pulsations

Pilot – Metal Seat


� Set Pressure can be tested in-situ


� Excellent Chemical & Temp Compatibility

� Only pop action available

� Pressure limited to 1200 psig

� Temperature limited 1000°F

Relief Devices - Selection

Type Conventional Bellows Pilot

Default Selection �

Back Press ≤ 10% ≤ 30% (Note 1) No limit

Max Op Press 90% SP 90% SP 90% SP (Note 2)

ASME Sec I � � �

Remote Pressure Sensing/ Unloading �

Plugging, Polymer, Dirty Service � �

Rupture Disk RD/RV Combination

Rapid pressure rise Prevent atmospheric emissions

Corrosive, fouling polymerization services Reduce RV cost in corrosive service

Very large relieving area Not allowed for ASME Sec I

Always use non-fragmenting RD

Derate RV capacity by 10%

1. Up to 50% with capacity correction 2. Up to 95% of set in revamp or high pressure situation

CODES & STANDARDS

Codes & Standards

� Codes - ASME� Section I for Steam Boilers

� Section VIII for Unfired Pressure Vessels

� Recommended Practices/ Standards - API� RP 520 Sizing, Selection, and Installation of Pressure-Relieving

Devices in Refineries� Part I Sizing and Selection and

� Part II Installation

� STD 521 Pressure-relieving and Depressuring Systems

� STD 526 Flanged Steel Pressure Relief Valves

� RP 2000 Relief load calculations for Storage Tanks

Vessels under 15 Vessels under 15

psig excluded

ASME is a Code. Compliance is mandatory.

API is a recommended practice.

API is also getting adopted as a National /

International Standard

Operating/ Design/ Set Pressure

� Operating Pressure� + margin = PAH or PCV Dump Pressure

� + margin = PAHH Pressure

� + margin = Design Pressure

� RV is usually set at Design Pressure

� Code allows a margin over set pressure – “overpressure” for full capacity to be reached� 10% overpressure for all contingencies, except fire

� 16% with multiple valve

� 21% overpressure for fire, an infrequent or rare case

� Higher overpressure � smaller RV, that is all!!

� Note: � 1. MAWP, based on installed wall thickness is not considered in RV set point.

Vessels are hydrotested to 130% of MAWP

� 2. RVs can be set below Design Pressure

� 3. Considering blowdown, RVs should above set 3-7% above PAHH

Why?

ASME/ API GuidelinesThis image cannot currently be displayed.

Process Engineers go by Design Pressure, rather

than MAWP, as MAWP is usually known much later.

For revamp: MAWP may be OK. Caution: Corroded

walls!

Where RV is set below MAWP, overpressure can be higher to match MAWP + Accumulation

Single Vs Multiple Devices

� Design Note: In high pressure service, large

valves may not be available. Instead of waiting

to find out at AFC stage, it helps if Process

Engineers can do a quick sizing and show

multiple valves, if required

� For heat exchangers, one may need a small RV

for thermal and a bigger RD for tube rupture.

Set RV low so that on thermal demand, RD is

not ruptured

RELIEF SCENARIO ANALYSIS

Relief Scenario Analysis

� Utility Failures� Power Failure - Total or Partial

� Instrument Air Failure

� Cooling Medium Failure

� Heating Medium or Steam Failure

� Controllers Failure� Instrument Air failure to individual control valve

� Control Valve Failure - Gas blowby

� Blocked Outlet� Inadvertent opening / closing of manual valves

� Check Valve Failure Utility failure may not result in major loads for individual PSV. But being cumulative load, they may govern the header and flare sizing

Power Failed

Fatal Error

Restart Giveup

X

Common Mode / Cascading Failure

� One failure results in another� Steam loss to Steam Turbines results in Power failure

� Power loss to Air Compressor, leads to Inst Air failure

� Power loss to pumps, leads to Cooling Medium failure

� Analyzing cascading failures - difficult but important

READ API RP 521. IT IS PAINFUL. BUT NO OTHER WAY!!


Individual Failure

� Exchanger Tube Rupture

� Thermal Expansion of blocked in liquid

� External Fire

� Pressure (Surges) Transients – Liquid lines

� Ingress of volatile (e.g. water) into hot oil

� Fractionators/ Columns:� Reflux Failure

� Loss of Cold Feed

� Excess Heat to Reboiler

� Reboiler Tube Rupture

� Absorbent failure

Individual Failure

� Abnormal Heat or Vapour Input

� Accidental Mixing of Fluids. Remember Bhopal?

� Storage: Liquid Overfill Remember Buncefield

� Human Error

� Chemical Reactions Column Blows-off Top

� Vacuum Relief

� Atmospheric Tank Thermal Breathing

Owner may, at his risk, elect to exclude some scenarios,

considering administrative or instrument controls.

How are you going to control Hot Oil Coking?

Power Failure

� All Electric Power driven equipment stop

� Evaluate� Electrical one-line diagrams

� Back-up power sources: in-plant generation / grid power

� Single Equipment failure

� Localized Power failure

� Unit Power failure

� Plant-wide or plant section-wide power failure

� Consequence:� Vapour release from columns/ vessels

� Air Cooler Fans: Natural draft credit: 25% of duty


Instrument Air Failure

� All control valves revert to safe position - FC or

FO

� Individual control valves: Analyse individually

� Consequence:

� Blocked outlet etc release

� Impact on Flare: Analyse system by system

� Simultaneous failure of Inst Air & Inst Electric Power

- unlikely This image cannot currently be displayed.

Steam/ Heating Oil Failure

� All Steam Turbine driven equipment stop

� Loss of Motive Power to eductors and ejectors

Loss of Heat to reboilers, exchangers

� Loss of Stripping Steam to columns

� Evaluate single failure, steam line blockage to a

single equipment + to individual unit

Cooling Medium Failure

� Evaluate - impact on� Single equipment

� Plant wide - Cooling Medium Pumps down

� Partial credit, for multiple pumps driven by independent sources� Example - 2 electric motor + 2 steam turbine

� No credit, if ‘independent’ pumps can be on stand-by or taken off service for maintenance

� Cooling Medium Loss to� Exchangers and condensers; Column Condenser - Reflux failure

� Refrigeration Condenser - Blocked outlet on Refrigeration Compressor

� Loss of chilled water, refrigerant, etc

� Compressor Lube Oil Coolers - Compressor trip

� Consequence� Vapour release from columns/ vessels


Blocked Outlet

� Causes� Inadvertent valve opening or closing by operator

� Instrument / Mechanical / Utility failure

� Panic response - Wrong action

� Wrong interpretation when multiple alarms are activated simultaneously. Multiple alarms may result in alarm fatigue, leading to accidents. “Alarm Management Study” a MUST.

� Source pressure > downstream design pressure.� Sources: Pumps, Compressor, Utility, HP upstream etc

� ‘LO’ or ‘CSO’ - not a good design; OK if Owner wants� ‘LC’ valves on a high pressure source may leak

Design Tip: No double jeopardy! Only one valve closed or opened. Safety Engineer can say: Outlet SDVs got closed but inlet SDV failed to close, asking PSV sized for both gas and liquid. No hard and fast rule.


Blocked Outlet

� SDV – 2 or PCV-1 fails closed� PSV - 001 Size: Full inflow to V-001

� Credit: LCV-1/LCV-2 normal liquid flow - as only ONE valve is taken blocked at a time. Caution: instant flow via LCV < design. Credit?

� Safety engineers: Both liquid and vapor flow – as on a trip, SDVs in liquid and vapor outlets might have closed with inlet SDV failing to close

� Compromise: Check well flow at relieving pressure; usually less on high backpressure. (Not true, if choke takes a high ∆P


V-001

PSV - 001

SDV-2

SDV-1

LCV-1

SDV-3

PCV-1

LCV-2

SDV-4

Arguments: On LCV-1 closing, liquid can go via PCV-1. On LCV-2 closing, liquid can go via LCV-1 etc.

Blocked Outlet

� LCV - 1 fails closed

� Pump P-001 shut-off

pressure > E-001 tube

side design pressure.

� Relief rate: Based on

pump head at PSV-001

relieving pressure and

max suction pressure of

pump P- 001

� Good design to have

pump outlet designed

for shut-off headRelief flow is less than Operating flow

He

ad

Capacity

Relieving

Operating

P-001

E-001

V-001

LCV-1

PSV - 001

Blocked Outlet

� To satisfy ASME, a PSV is required on equipment at pump outlet, even if its design pressure > pump shut-off pressure

� Relief rate may be nominal or Nil.

� If a PSV is provided for some other reason, say fire, then it will do

He

ad

Capacity

Relieving

Operating

Pump suction valve & piping downstream of it to suit discharge conditions

Control Valve Failure

� Causes� Instrument air failure; Signal (wiring) failure; DCS hardware/software failure

� Improper manual operation by operator

� Mechanical malfunction of control valve

� Hand wheel left engaged on control valve

� Plugging

� Evaluate both Open and Closed position of control valve

� No credit: for interlocks / Emergency Shutdown System in RV size; Credit may be taken for total load to flare header

� Credit may be taken for normally open flow paths and not affected

� Simultaneous failure control valve and bypass: Owner preference� Options: No bypass; RO in bypass; bypass valve Cv same as control valve;

parallel but not-connected control valve; parallel control valve on its own

Control Valve Failure

� LCV - 1 fails open� PSV - 002 Size:

Max flow thru LCV-1 minus V-2 normal flow

� Max flow thru LCV-1: Max Cv + downstream PSV - 002 relieving pressure + ∆P between LCV and PSV

� LCV – 1 fails closed� PSV - 001 Size: Blocked

outlet

V-002

PSV - 002

V-2

L-2

V-001

PSV - 001

LCV-1

SDV-2

SDV-1

SDV-3

Note: Several approaches to gas blowby load estimation: All gas; gas volume

equivalent volume of liquid; both gas and liquid limited to max inflow etc.

Dynamic Simulation helps get realistic results

If it overloads or is the largest LP Flare load, consider same design pressure for

the d/s vessel to eliminate gas blowby case

Heat Exchanger Tube Failure

� Shell & Tube heat exchangers tubes may fail due to thermal shock, vibration, corrosion etc

� No PSV, if high pressure side design/ operating pressure is ≤130% of design (= hydrotest) pressure of low pressure side * temperature correction

� 130% or ‘0.77 rule’ does not mean tubes don’t rupture –a common mistake� Evaluate potential overpressure of connected equipment

� Evaluate potential chemical reactions when two sides mix

� 2 Options - tube failure at mid tube viz 2 orifices andfailure at tube sheet viz 1 nozzle + 1 orifice

� For PCHEs, one full channel failure

� No PSV for tube failure in double pipe exchangers


Heat Exchanger Tube Failure

� Credit: Flow thru normally open pathif LP fluid is gas or vapour� If LP side is liquid, pressure build-up to push and

accelerate large liquid mass. It is as good as blocked

� Some consider tube rupture only when HP to LP differential pressure > 65 bar (1,000 psi)

� On tube rupture, pressure spike is rather quick. Usually rupture disks are provided as spring loaded RVs take time to react� Opening time: Rupture pin: 2ms; Rupture disk: 5ms; RV

25ms

� Recommended to have 2 RDs at either end of LP side

� Dynamic Simulation studies help, select location


Check Valve Failure

� All valves leak or pass. In early designs check valve leak was NOT considered� Check valves stop “bulk” flow but can’t avoid leak past them

� Some considered check valve leak only in high pressure or dirty or surging service. Some considered specially designed, power assisted check valve can stop reverse flow. No longer valid

� No credit to single check valve. Reduced flow area for 2 dissimilar check valves� Standard calculation methods available to estimate leak past a

check valve

� Note: Along with leak, pressure is transmitted. That is HP side can pressurize LP side shut-in

When a compressor trips, discharge from

other running compressors can back flow

into the tripped one, pressurizing its

Suction Drum

This point out is missed out by Process Engineers in a

Hazop review

Check Valve Failure

� At a common manifold, when one of the stream stops

flowing or a pump/ compressor feeding it stops, fluids from

other streams may back flow thru the non-flow pipe

Wellhead inlet manifolds: A common check valve

or one per header Well

Header A

Header BXmas Tree

Test Header

3 Workers Killed

Thermal Expansion

� Liquid filled equipment / piping that is blocked-in and heated � Solar radiation; Hot side of exchanger; Heat tracing

� Heat Exchangers: Cold side vapor pressure > design pressure� At ambient temperature; At hot side fluid inlet temperature; Heat

tracing

� OSBL: Yard piping

� 10% overpressure for vessels and 33% for piping

� CSO or LO valves can eliminate thermal PSV, provided Owner agrees to administrative control

Air freshener can in a closed

car - Thermal



Thermal Expansion

� Thermal Expansion � Massive Force

� Liquid Ammonia Tank in a closed garage, exploded and propelled the truck 40m



External Fire

� Pool fire under equipment, even if contents are not flammable

� Radiant + direct heat boils liquid / expands vapour � increasing pressure

� Equipment assumed blocked in and isolated when fire occurs and inflow stopped� There can be exemptions for this rule, example, heat exchangers

� ASME stamped equipment must be protected unless fire can be ruled out or equipment/ system cannot be blocked-in

� Piping and piping components do not require protection. � Interconnecting piping included in adjacent equipment

� Equipment grouping: 8.6m (28.2’) radius (2,500 sq.ft area) and 7.6m (25’) high from grade are grouped in a single fire zone� Liquid at NLL or HLL

� Evaluate: Effects of chemical reaction, fluid decomposition and fluid behaviour (foaming, frothing, etc.)

Design Tip: API indicates max fire zone size. Use it wisely to reduce Blowdown load + Flare size


Vacuum column fire

Do NOT design for Jet Fire load as some do. As API RP 521 says, jet fires are handled by blowdown viz. removing fuel

External Fire

� Fire NOT considered if:� Sloping or proper drainage eliminates pool fire possibility

� No flammable hydrocarbon exists in the area

� Air Coolers/ equipment located 7.6m (25’) above grade OR over open grating

� If fire load is relieved thru any passage that can’t be shut

� If Owner instructs: “Equipment will be vented and drained when taken out of service”. e.g. Pig launcher/ receiver

� Credit for fireproof insulation as allowed by API; it should withstand firewater jet impact

� Gas vessel: Fire PSV not effective as vessel metal temperature > Creep temperature

Design Tip: If fire relief temperature > equipment design temperature, use design temp

for RV material and flange selection. Say so in data sheet. Vessel metal temperature will be

200-300°C > RV relief temperature. Vessel will fail/ rupture/ deform first before RV lifts

PETRONAS: No fire PSV for gas vessels


Caution: Corrosion

under insulation can

bring a vessel down

before fire does!. Need

Inspection windows

External Fire

� Vessel under fire will deform/ rupture before PSV lifts, as metal wall rapidly loses strength as its temperature rises.

� Blowdown Valves are provided to depressurize the vessel within 15 minutes

� Against fire:� Blowdown

� FW spray

� Fireproofing

Temp °F %

400 100

800 80

1,100 36


Max Temp

°C

°F

1/3 Tensile

2/3 Yield

RVs do NOT protect against structural failure when the vessel is exposed to extremely high temperatures during a fire

RP 521 Figures

• Heat up rate

• Time to Rupture

Pressure Surges

� Transient Analysis required for� water, liquid filled or rundown OSBL lines

� oil/condensate export pipelines

� Transient Analysis is NOT required for� ISBL piping. Short runs and generally do NOT have quick

closing valves

� Code allowed - short term - margins may be used to avoid a PSV

Design Tip: It is common for GRE Fire Water/ Sea Water

piping to burst during start-up, fill the Flare KOD and

bring the plant down. Have a good surge study; leave

design and construction/start-up to a single source. Take

exception from Owner, giving him the risk.


Seawater flooding a column sank semi-sub


Water hammer. 24 t piping flew off 800m. Sheared off telephone poles

Column Cases

� Reflux failure is usually the controlling case:� Reflux Pump / Power Failure

� Reflux Control Valve Fails Closed

� Overhead Condenser Failure or Flooded on Draw-off Control Valve Fails Closed

� Non-condensable Accumulates in the Condenser

� Operator Error: Block Valves Closed

� Loss of Cold Feed� Feed Control Valve Fails Closed or Feed Pump Fails - Transient Surge

in Vapour Rate

� Excess Heat to Reboilers� Steam or Heating Control Valve Fails Open

� Excessive Fuel to Fired Reboiler

� Additional Vapours generated

� Reboiler Tube Rupture

Credit: Reduced vaporization in reboiler at relieving pressure.

Reduced ∆T relieving pressure reduces relief rate

Excess heat may not pressurize the

exchanger but will over pressure the column

Safety Alerts

Column blows off top – leakage reacts

Column overflows – 15 killed; 150 injured

Column Cases

� Column load calculations is complicated� 3 approaches – flash, gross overhead vapour, unbalanced heat; last

one gives the best estimate

� Dynamic simulation can reduce column and reactor loads

From: “Optimize relief loads with dynamic simulation”, CL Xie, ZG Wang and YF Qin, HP, Dec 2013

Column Overhead Vapor, kg/h Unbalanced Heat, kg/h

DC Steam Stripper 60,000 168,000

DC Fractionator 296,000 448,000

HC Debutanizer 69,000 171,000


DC Fractionator Conventional, kg/h Dyn Simulation, kg/h

.. Total power fail 448,000 259,000

.. Single power fail 85,000 0

.. Blocked outlet 258,000 172,000

Dyn Sim load 60%. Case 2 PSV does not pop

Accidental Mixing of Fluids

� Runaway reaction - Polymerization:� Some chemicals, when mixed in wrong

ratio or sequence may lead to run-away reaction

� Inadvertent mixing of reactive streams

� Decomposition or polymerization due to abnormal heat input or loss of cooling

� See Safety Alert

� Runaway Reaction Relief Rate � Determination is complex. Inputs from

Owner, Catalyst Manufacturer, Process Licensor.

� Owner/ Licensor to provide the relief load. Pass them the responsibility


Bhopal. 4,000 to 10,000 dead; 500,000 injured

Liquid Overfill of Storage Tanks





Design Tip:

1. Let level transmitters for Control and Trip track each other.

2. While filling large tanks, let DCS put a time lock based on pumping rate and ullage

� Inflow exceeds outflow

� Overfilling from an offsite

pump during start-up or

LAH/LAHH failure

Vacuum Relief

� Equipment may come under vacuum:

� Fluid withdrawn without matching inflow

� Excessive condensation in Column

Overhead Condenser

� Condensation or cooling of vapours upon

atmospheric temperature drop

� Compressor suction side blocked

� Condensing side of exchanger blocked in

while cooling continues

� Draining with vent closed

� Cool down and condensing after

steaming a vessel




Vacuum Relief


� Equipment that could come under vacuum is

designed to withstand full vacuum

� Note: For large diameter columns and storage tanks,

cost of designing to full vacuum is prohibitive

� Check the consequences of air mixing with vessel

inventory before providing vacuum relief. Usual to

provide Nitrogen padding/ blanketing

� No RV required if Owner instructs that his

administrative procedures can prevent vacuum

� Draining test water; Steam condensing after a steam-out

Atmospheric Tank Protection

� Inbreathing (vacuum relief) is required for� Maximum outflow without matching inflow

� Vapour shrinkage due to atmosphere cooling –showers etc

� Blanket gas supply valve fails/ closed

� Out breathing (pressure relief) required for� Maximum inflow without matching outflow

� Vapour expansion due to atmosphere warming

� Blanket gas supply valve fails open

� Vapour outlet valve fails/ closed

� Fire relief required unless tank has frangible roof� Fire generally does not engulf the entire tank


Atmospheric Tank Protection

� Refer API 2000, for calculation of relief load

� N2/ gas padding for thermal inbreathing/ outbreathing

� PVRV for thermal inbreathing/ outbreathing

� Gauge hatch / manway vents for fire relief

� Tanks have a low design pressure, mmWC. PVRV/

manway are weight loaded; sizing by vendor

� PVRVs installed directly on roof nozzleThe linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location.


Blanket Gas Regulators Emergency Vent

Gauge Hatch and Manhole Cover

PVRV

Fired Heater

� Blocked outlet and thermal

� No PSV required for process coils, unless mandated

or underrated

� PSV required for BFW and Steam coils – Code/ IBR

� Thermal PSV in Hot Oil WHRU

� Residual heat in refractory/ insulation. Not effective

against oil coking inside the tube

Pumps & Compressors

� Centrifugal Pump� Usually designed for shut-off or highest head at zero flow

� Reciprocating/ Positive Displacement Pump/ Compressor� RV for blocked outlet. Due to pulsation in discharge pressure keep good

margin between operating and set pressure

� Centrifugal Compressor� Suction side for settle-out pressure. 2-3 stages in a common casing may

settle-out together + Check valve leak

� Refrigeration or low temp service ~ vapour pressure at ambient temperature

� Discharge/ Casing: Design for surge pressure at 105% speed with maximum [suction pressure; molecular weight] and minimum suction temperature [Oil & Gas Industry practice] or RV provided at 120% of Normal Operating Press

� Inter-stage: Usually fire case

When a compressor trips, discharge from

other running compressors can back flow

into the tripped one, pressurizing its

Suction Drum

Typical Relief Cases – Oil & Gas

� Flowline - Blocked Outlet/ Thermal

� Inlet Sep - Blocked Outlet

� LP Sep - Blocked Outlet/ Gas Blowby

� Compressor - Fire/ Check Valve Leakage

� Compressor Last Stage - Blocked Outlet ?

� Glycol Contactor – Fire

� Fuel Gas KOD - PCV Failure

� Glycol Pump - Blocked Outlet

� Filters - Fire

� Air Vessels - Fire

RVs may not be the right solution…

� For a few cases, RV is impractical. Instrumented safeguards is needed

� Hot Oil WHRU.

� Hot Oil Boiling Pt at Relief Press >≈ Incoming Flue Gas Temp

� Heat to boiling fluid ≈ zero

� Hot oil will decompose and coke before it boils

� Instrumented protection to remove source of heat + minimum flow at all

times + thermal PSV against residual heat in WHRU

� Export pipeline of 1,000 MMSCFD

� A huge flare. HIPPS contains the HP fluid avoiding a release

� Instrumented Protection to isolate the HP source such as compressor

and/or HIPPS (2 independent SDV) from 2 “independent” trip systems.

� READ ASME CODE CASE 2211-1, now part of RP 521, Annex E

Design Tip: HIPPS/ IPF requires Documented User Approval.

Only User may specify pressure protection by system design.Design Tip: SDVs leak, Ha Ha

SIZING

Design Tip: Analyzing Relief Scenarios and Estimating Relief

Loads is the important part. Sizing is a matter of routine.

RV Sizing

� 3 Equations

� Vapour - Critical

� Steam - Critical (ASME Div VIII)

� Liquid

K = Sizing constant

W = Relief flow rate

C = Coefficient

P1 = Upstream relieving pressure

Kd = Coefficient of discharge

Kb /Kw = Back pressure correction factor

Z = Compressibility

M = Molecular weight

T = Upstream relieving temperature

A = Required orifice area

Kn = Correction factor for Napier Equation

Ksh = Correction factor for steam superheat

Kv = Correction factor for viscosity

P2 = Total back pressure

SG = Specific gravity of liquid

A =KW TZ

CP1KdKb M

A =KQ G

38KdKwKv P1-P2

A =KW

P1KdKbKnKsh

Liquid sizing: trial & error step required. Start with an assumed size to determine Re and hence Kv. Repeat to match

See API for sizing 2 Phase Flow.

Older method of vapor + liquid

area is no longer valid

RV Sizing

� Subcritical Flow – Vapour, pilot and conventional

� Valid for RVs that have their cold spring setting

adjusted to compensate for the constant superimposed

BP

� Built-up back pressure <10% or allowable accumulation

A =KW ZT

F2Kd MP1(P1-P2)

K = Sizing constant

W = Relief flow rate

P1 = Upstream relieving pressure

P2 = Downstream or backpressure

Kd = Coefficient of discharge

F2 = Coefficient of sub-critical flow

Z = Compressibility

M = Molecular weight

T = Upstream relieving temperature

A = Required orifice area

Do NOT interpret this equation

allows >10% back pressure

RV Sizing

� Coefficient of Discharge Kd

� Depends on relief valve design

� National Boiler Board certifies capacities of all RVs

� Manufacturer back calculates Kd from certified capacity

and test conditions

� If unknown, assume 0.975 for vapour and 0.65 for liquid

� RV capacity must be checked based on vendor Kd

� For all vapour and liquid RVs, manufacturer should

supply sizing calculation based on his Kd

Design Tip: Kd varies from manufacturer to manufacturer. Our calculations should

not be passed to clients. Final calcs from supplier should be the deliverable.

Standard RV Sizes

� RVs made in standard sizes

� Each standard orifice given a letter designation

� Select a standard size larger than the calculated one

� If calculated size, marginally exceeds a standard size, it may be OK, as the actual orifice area for most RVs are higher than the standard API area. Actual areas are listed in National Boiler Board Book

RV Standard Sizes

API 526 Orifice Designation

Size Area, in2

D 0.110

E 0.196

F 0.307

G 0.503

H 0.785

J 1.287

K 1.838

L 2.853

M 3.600

N 4.340

P 6.380

Q 11.050

R 16.000

T 26.000

Standard RV Sizes

API 526 Orifice Designation

Size Area, in2

D 0.110

E 0.196

F 0.307

G 0.503

H 0.785

J 1.287

K 1.838

L 2.853

M 3.600

N 4.340

P 6.380

Q 11.050

R 16.000

T 26.000

RV Standard Sizes

Size D E F G H J K L M N P Q R T

1 x 2

1½ x 2

1½ x 3

2 x 3

3 x 4

3 x 6

4 x 6

6 x 8

6 x 10

8 x 10

RV Inlet x Outlet Sizes

Standard RV Sizes

� API area is not actual RV area� Actual area and nozzle coefft vary from

manufacturer to manufacturer

� 2J3 API Area = 1.287 in2

� Actual area = 1.427 to 1.635 in2

� Coeffts = 0.788 to 0.975

� National Board certified capacity - based on nozzle coefft and orifice area - varies

� Why the difference?� In 1962 ASME Sec VIII derated certified

capacities by 10%. Manufacturers did not derate their advertised capacity or nozzle coefft, but increased nozzle area by 10%. But API orifice areas as advertised remain same.

KA is more comparable.Explanation AG/Crosby

Advertised KA = 0.975*1.287 = 1.255National Board = 0.788*1.635 = 1.288

API (K= 0.9) = 0.9*1.287 = 1.158

Actual capacity may be 10-16% more So don’t jump from P to R (73%) when

calculated size marginally exceedsstandard size

Air/Gas/Steam ServiceThis image cannot currently be displayed.

Board RV Area is based on

• Nozzle bore for full lift valves

• Lift for restricted lift valve

Thermal Expansion

� Relief Rate, q = αv.φ

K.d.c

αv = cubic expansion coefft of liquid at expected temp

φ = Heat Transfer Rate

Exchangers: use max Heat DutySolar Radiation: use as per Project Design Basis

K = Sizing constant

d = Relative Density

c = Specific heat of trapped liquid

� For thermal protection of piping, generally ¾” D 1” threaded or 1” D 2” flanged RVs are provided; No calculations done

Fire Relief

� Liquid: � Latent heat for multi-component is tricky, but rules of thumb help. λ = 50 to 100 units

� Assumed that entire heat goes to boil-off.

� With large liquid inventory, only a small part goes to vaporization; rest heats the liquid

� Gas: � Temperature, T2, calculated under fire may exceed base equipment design temperature.

RV with required inlet flange rating is usually not available. In RV data sheet, specify design temperature and indicate that T2 is for area calculation only.


Fire Relief - Blowdown

� Without BDV, internal pressure (Hoop’s stress) rises over time; metal’s ability to hold pressure (yield strength) falls with increasing temperature. The vessel will fail when internal stress exceeds ability

� Blowdown brings down internal pressure and stress. As long as internal stress is below allowable stress, vessel will not rupture

� Judiciously use to extend blowdown time when blowdown rate is higher than design inflow capacity to reduce flare size

Time, minutes �

Str

ess

� Ka Boom

Fire Relief - Blowdown

� API RP 521: Thinner plates (LP service) heat up faster; higher the temperature, faster it ruptures

� If BDV initial pressure (PAHH/PSV) >> operating pressure, zoning can cut peak rate � Take one source at a time. Loads from this

and adjacent equipment within a fire zone (8.6m radius x 7.6m high) are taken at BDV initial pressure; rest at operating pressure

� Staggered blowdown can reduce flare capacity

RP 521 Figures

• Heat up rate

• Time to Rupture

Time �

Flo

w +

Pre

ssu

re

Flow = Foe-θt

Pressure = Poe-θt

Time �

Flo

w

Group 1, then Group 2 and last Group 350% reduction

Groups 1 +2 + 3

Staggered Blowdown• Each BDV with secured air vessel,

sized for 3 valve strokes; PAL; 2 check valves at inlet; no bleeding devices like regulators

From: “Design staggered depressurization sequence for flare systems”, R Dole, S Bhatt and S Sridhar, HP, Dec 2013

INSTALLATION & ISOLATION

Design Tip: Improper installation restricts capacity. Next

time you visit a plant, walk around and cringe in horror!!.

Inlet Line

� Size on RV rated flow - not on relief load

� Inlet loss <3% to avoid chatter, except with remote sensing pilots� If inlet ∆P >3% with pilots, use actual inlet

pressure to size RV

� Upstream of demister. from vapour space; below Normal Liquid Level for PRV

� 10d min from Control Valve

� Free draining to source; Bleed/drain @inlet

� Nozzle Entrance Loss� 1 VH if RV is off vessel

� ½ VH if RV is off outlet pipe

� RV mounted upright

� Inlet line/ Vessel Nozzle ≥ RV inlet

Design Tip: Common Error: Ignoring ∆P in common piping,

specially in a group of vessels protected by a single RV.

Resonant Chatter in a pilot can self-destruct it

Friction Loss

Entrance Loss1 Velocity Head

Bleed

Entrance Loss½ Velocity Head

Friction Loss

Hard TBleed

Inlet 3%

� It is difficult to meet <3% criteria when

� Inlet pipe area/ RV area < 3. Results in body bowl

choking. Usually in bigger RV

� Suggestions:

� Have a higher inlet example 4P6; have 6P8

� Insert a size 9.5 between P and Q 6.38^11.05

� Reduce RV lift to reduce area viz Q � 9.5

� Latter 2 reduce RV area to desired to cut rated flow and ∆P

� Study of 14,863 RVs indicate 20% fails to meet 3% limit

� 90 off 4P6 RVs with inlet L= 4 to 116’. ∆P = 1.2 to 19.4%.

63% > 3%

0.7854*4^2/P(6.38) = 1.970.7854*6^2/P(6.38) = 4.43

0.7854*6^2/9.5 = 2.973

From: “Address inlet pressure loss concerns with restricted lift relief devices”, Smith D, Yoram S, HP, Mar 2014

Outlet

� Atmospheric Discharge� To Safe Location - for steam, air and N2; not HC

� Weep or drain hole in outlet low point

� To Closed Drain� Thermal etc RV

� Avoid, if cross contamination is possible

� Avoid if water in drain will freeze

� To Flare� Line should free drain to flare header; Top entry

� No liquid accumulation

� Backpressure limitation

� Outlet line size ≥ RV outlet

� < 70% sonic and ρV² criteria

¼“ drain hole

Safe Location

Free Drain

Like high inlet loss, high back-pressure can make

a RV chatter. As soon as RV closes, flow stops,

back-pressure falls, making the RV to open

Inlet/ Outlet Isolation

� Inlet & outlet Isolation valves� Not permitted by ASME Section I; not recommended by ASME

Section VIII

� If required by Owner, then both should be FB locked open (“LO” or “CSO”)

� If a spare RV is required by Owner, � install with FB inlet & outlet valves

� Inlet valve of one RV is LO and the other LC

� Some Owners require interlocked valve to ensure that one RV is always in service

� Both outlet valves should be LO.

� A (globe) vent valve across RV to depressurize before draining� A 2nd ball isolation valve located 600mm upstream of vent valve in

HP service, if globe valve is stuck on icing ~ JT cooling

� A bleed valve u/s of RV inlet block valve ~ in-situ testing

� If Owner agrees, a single common LO outlet valve for all RVs in a system, say compressor train or Fuel Gas System

LO

LO

600 mm gap

LO

LO

LC

LOWhy?

Inlet & Outlet Piping

Inlet

Lead Size, in 2 3 4 6 8 10 12 14 16 18 20

Eq L, ft open system 25 25 25 25 25 25 25 25 25 25 25

Closed system 75 75 75 75 75 75 75 75 75 75 75

Fittings No off Eq L, ft each

3 Elbows 4 4 5 8 9 12 14 16 18 20 23

1 Hard T 10 14 19 28 37 47 55 62 72 82 90

1 Reducer 1 2 3 4 5 7 8 9 10 11 13

0 Gate Valve 2 2 3 4 6 7 9 10 11 12 14

Eq L, ft - Open system 48 53 62 81 94 115 130 144 161 178 197

Eq L, ft - Closed system 98 103 112 131 144 165 180 194 211 228 247

Outlet

Lead Size, in 2 3 4 6 8 10 12 14 16 18 20

Eq L, ft open system 25 25 25 25 25 25 25 25 25 25 25

Closed system 50 50 50 50 50 50 50 50 50 50 50

Fittings No off Eq L, ft each

3 Elbows 4 4 5 8 9 12 14 16 18 20 23

1 Hard T 10 14 19 28 37 47 55 62 72 82 90

1 Reducer 1 2 3 4 5 7 8 9 10 11 13

0 Gate Valve 2 2 3 4 6 7 9 10 11 12 14

Eq L, ft - Open system 48 53 62 81 94 115 130 144 161 178 197

Eq L, ft - Closed system 73 78 87 106 119 140 155 169 186 203 222

Poor Piping

� Pipers locate RVs at “convenient” locations – viz access, ignoring inlet ∆P. Need to check piping 3D model

� Horizontal dead legs collect trash / liquid in service

� RVs in turbulent zone can chatter and get damaged� Downstream of a Pressure Reduction Station – Fuel Gas?

� Downstream of orifice plates/ flow nozzles

� Downstream of pulsating compressor / pump discharge. Pilot RVs may be better because of high seat loading

Design Tip: It is a pain; but MUST review RV inlet and outlet

piping and pump suction piping in 3D model. Easier to do

than “wish I could bury myself in sand” feeling at site


Ideal Piping

� Difficult to achieve but

recommended by

suppliers



Common Errors

� Ignoring static head� Between upstream & downstream

equipment as in the case of Prod Sep and d/s vessel or Hydrocyclone

� Between PSV and piping at a lower deck

� Ignoring ∆P in common piping, specially in a group of vessels protected by a single RV

� Ignoring mechanical limit on backpressure. Bigger the RV lower is backpressure allowed.

Friction Loss

Design Tip: Important to check mechanical limit on

backpressure on flowing and non-flowing RVs.

Forgotten by Process Engineers. See RP 526

Size D – J M R T

Convn 285 285 60 30

Bellow 230 80 60 30

150# RV Outlet Press Limit, psig at 100°F

Pump atUpper Deck Piping at

Lower Deck

Prod Sep

Hydrocyclone

LC

HIPPS Errors

� HIPPS used� Against PCV / choke failure

� Blocked outlet/ stuck pig/ hydrate blockage

� In � subsea section to derate flowline/riser,

instead of designing for shut-in pressure

� Topside piping

� Check� Pressure build-up in trapped LP section by

the time PAHHs detect and fully closes SDVs

� Provide minimum length of fortified or HP section d/s of HIPPS SDVs - pig/ hydrate blockage, SDV leakage

� Need to provide a PSV in LP SDVs leak!

HP Section LP Section

Riser SDV

HP | LPPSV - 001

SDV-2SDV-1

PAHH

PALL

PAHH

PALL

SDV-3

HP | LP

Subsea Wells

HP | LP

Subsea Flowline

Fortified Section



RV Discharge Velocity & Noise

� Tail pipes may operate at high velocities

� Based on Process input, piping to calculate the reaction forces

� RV may need supports to counter momentum and velocity effects of the flowing fluid� Dual outlet PSV can help mitigate – resultant force

� Noise levels should be calculated per RP 520� Provide noise insulation or relocate RV away

FlowForce

Flow Induced Vibration

� Flow induced vibrations may result in fatigue

failure.

� May require piping supports, increased wall

thickness, etcThe linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location.



Failure to update Relief Studies

� Codes and standards; methods/ assumptions

keep changing … additional insights,, Flarenet

� RVs in old plants should be revisited every 10 years

� If control valves/ equipment have been replaced

� In Oil & Gas plants, GORs, liquid profiles change

RELIEF SYSTEM DESIGN

Relief System Design

� Analyze Relief Scenarios Analysis

� Calculate Relief Loads and RV Size for each

Scenario to get Governing Case Sizing

� Summarize results for each RV for each

contingency to determine Peak Load to Flare

Info Required

1. Heat and Material Balance

2. Process Flow Diagrams (PFDs)

3. Piping and Instrumentation Drawings (P&IDs)

4. Instrument Data (Control Valve, Bypass, RO sizes, etc.)

5. Mechanical and Rotating Equipment Data

Total Load Reduction via Dyn Sim

� On total plant failure cases, viz Power, Cooling Water, Air, it is unlikely all the PSVs will pop at the same instant + maintain initial rate� Columns may take time build to relief pressure

� Dynamic simulation can help find realistic load

� Note: Compressor interstage drum pops in total system study but does not impact total load


Total Power Failure Conventional, kg/h Dyn Sim - Individual, kg/h Dyn Sim – System, kg/h

Fractionator 448,000 259,000 140,000

Comp Interstage Drum 0 0 160,000

Stripper Feed Drum 45,000 45,000 50,000

Debutanizer 72,000 72,000 5,000

Total 565,000 376,000 355,000

Total Load Reduction via Dyn Sim


Dyn Sim total load is 275,000. But design taken as 355,000 kg/h


Total Power Failure Conventional, kg/h Dyn Sim - Individual, kg/h Dyn Sim – System, kg/h

Fractionator 448,000 259,000 140,000

Comp Interstage Drum 0 0 160,000

Stripper Feed Drum 45,000 45,000 50,000

Debutanizer 72,000 72,000 5,000

Total 565,000 376,000 355,000

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Some of these accidents are not preventable by RVs but by

• Common Sense

• Good Operating Practice

• Good Instrumentation & Controls

Boat hits platform PSV not bolted rightBoiler started

without purging

Hydrotest done with

cold water

Still Accidents Happen

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Bend d/s of water

Injection or LCV =

Erosion-corrosionCS bend used instead

of AS in H2 plant Internal in Flare KOD

No gas detectors in

onshore plant

Missing Check at UC

Piping Support Not

Fire Proofed Pig “Launched” Water HammerThe linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location.The linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location. The linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location.The linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location. The linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location.The linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location. The linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location.The linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location.

THANK YOU

pressure relief systems 2014 rev a

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