gp 44-25 guidance on practice for depressurisation

8/19/2019 GP 44-25 Guidance on Practice for Depressurisation

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Guidance on Practice forDepressurisation

GP 44-25

BP GROUPENGINEERING TECHNICAL PRACTICES

Document No. GP 44-25

Applicability Group

Date DRAFT 3 January 2007


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DRAFT 3 January 200 GP 44-25Guidance on Practice for Depressurisation

Downloaded Date: 6/17/2008 11:12:31 PMThe latest update of this document is located in the BP ETP and Projects Library

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Foreword

This is the first issue of Engineering Technical Practice (ETP) BP GP 44-25. This Guidance onPractice (GP) is based on parts of heritage documents from the merged BP companies as follows:

BP

RP 44-4 Guide to Depressurisation.CP 37 BP Engineering Code of Practice CP 37 – Guide to Depressurisation.

Copyright © 2007, BP Group. All rights reserved. The information contained in thisdocument is subject to the terms and conditions of the agreement or contract under whichthe document was supplied to the recipient’s organization. None of the informationcontained in this document shall be disclosed outside the recipient’s own organizationwithout the prior written permission of BP Group, unless the terms of such agreement orcontract expressly allow.


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Table of Contents

Page

Foreword ........................................................................................................................................ 2 Introduction..................................................................................................................................... 6

1. Scope .................................................................................................................................... 7 1.1. General....................................................................................................................... 7 1.2. Objective..................................................................................................................... 7 1.3. General requirements ................................................................................................. 7 1.4. Calculation methods ................................................................................................... 8

2. Normative references............................................................................................................. 8

3. Terms and definitions............................................................................................................. 9 3.1. Terms ......................................................................................................................... 9 3.2. Definitions................................................................................................................... 9

4. Symbols and abbreviations.................................................................................................. 10

5. General................................................................................................................................ 10

6. Operational vapour depressurisation ................................................................................... 11 6.1. General..................................................................................................................... 11 6.2. Plant and equipment ................................................................................................. 11 6.3. Pipelines ................................................................................................................... 11

7. Emergency vapour depressurisation.................................................................................... 12 7.1. General..................................................................................................................... 12

7.2. Vessels, aboveground pipework, and valves........... .......... .......... ......... .......... .......... . 12 7.3. Compressors ............................................................................................................ 12

8. Depressurisation requirements ............................................................................................ 13 8.1. General..................................................................................................................... 13 8.2. Emergency shutdown system ................................................................................... 13 8.3. Emergency shutdown valves .................................................................................... 14 8.4. Emergency depressuring (EDP) system ................................................................... 15 8.5. Emergency depressuring valves ............................................................................... 16

9. Application of depressurisation systems .............................................................................. 16 9.1. General..................................................................................................................... 16

9.2. Manned production platforms and floating production facilities.................. .......... ...... 17 9.3. Unmanned production platforms............................................................................... 17 9.4. Onshore gas/condensate plants........... ........... .......... ......... .......... .......... ......... .......... 17 9.5. Hydrotreating/hydrocracking reactors............ ......... ........... .......... ......... .......... ........... 18

10. Time for depressurisation..................................................................................................... 18 10.1. Fire case................................................................................................................... 18 10.2. Non-fire case ............................................................................................................ 19 10.3. Stopping depressurisation......................................................................................... 19


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11. Methods of depressurisation ................................................................................................ 19 11.1. Uncontrolled depressurisation................................................................................... 19 11.2. Depressurisation by zone.......................................................................................... 19 11.3. Controlled depressurisation ...................................................................................... 20 11.4. Depressurisation flow rates....................................................................................... 20 11.5. Draindown................................................................................................................. 20

12. Effects of depressurisation................................................................................................... 21 12.1. Auto-refrigeration...................................................................................................... 21 12.2. Hydrates and ice....................................................................................................... 22

13. Repressurisation.................................................................................................................. 22

Annex A (Normative) Background to the selected depressurisation time ......... .......... ......... .......... 23

A.1. Depressurisation purpose .................................................................................................... 23

A.2. Depressurisation systems designed for pool fire exposure.............. ......... ........... .......... ....... 23

A.3. Depressurisation systems designed to minimize leak size ........... .......... ......... .......... .......... . 26

A.4. Calculation of depressurisation mass flow rates......... .......... ......... .......... .......... ......... .......... 26

A.5. API 521 guidelines............................................................................................................... 27

Annex B (Normative) Methods for estimating the minimum wall temperature of depressurisedvessels and pipework........................................................................................................... 33

B.1 Proposed methods............................................................................................................... 33

B.2 General assumptions........................................................................................................... 33

B.3 Vessel contents ................................................................................................................... 33

B.4 Method 1.............................................................................................................................. 33

B.5 Method 2.............................................................................................................................. 33

B.6 Method 3.............................................................................................................................. 33

B.7 Method 4.............................................................................................................................. 33

Bibliography.................................................................................................................................. 33

List of Tables

Table A1 - High temperature tensile properties for typical carbon steel (1) .......... ......... .......... ...... 30

Table A2 - High temperature tensile properties for 18-8 stainless steel (1) .......... ......... .......... ...... 32

List of Figures

Figure A1 - API RP 521 figure on average rate of heating steel plates exposed to open gasolinefire on one side .................................................................................................................... 28

Figure A2 - API RP 521 figure on effect of overheating steel (ASTM A515 grade 70) ......... .......... 29

Figure A3 - Typical carbon steel (SA-515, grade 70) rupture stress versus time to rupture(bibliographical reference [1], Page 20)............. .......... ........... ........... ......... .......... .......... ...... 29

Figure A4 - Typical carbon steel (SA-515, grade 70) tensile strength and yield stress versustemperature (bibliographical reference [1], Page 16).............. ........... ......... .......... .......... ...... 30


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Introduction

This Guidance on Practice (GP) provides guidance on depressurising systems that are within its statedscope and is for use in determining the need for, and design of, specific depressuring systems.

This GP refers to National and International Standards that are widely accepted. Codes and Standardsof the country where the equipment is manufactured and/or operated should be considered and may beaccepted if they can be used to achieve an equivalent, safe, technical result. In any case, statutory andlocal regulations must be complied with.

The value of this GP to its users is significantly enhanced by their regular participation in itsimprovement and updating. For this reason, users are urged to inform BP of their experiences in allaspects of its application using the “shared learning” folder on the ETP website.


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1. Scope

1.1. General

a. This GP provides guidance on depressurisation as it relates to system design and selectionof process equipment and piping. This GP is applicable to new, above ground plant andfacilities and may also be used to assess possible hazards in existing systems.

b. This GP generally covers the depressurisation of connected systems, typically consisting ofone or more pressure vessels, heat exchangers, rotating equipment and other equipmentitems interconnected by pipework as described herein. During depressurisation of thesesystems:

1. Fluid flow may pass through any or all equipment and pipework in the system beingconsidered.

2. Fluid may reverse flow direction to its expected flow path during either normal orabnormal operation.

3. Depressurising flow through centrifugal compressors and other rotating equipmentmay result in “windmilling” of the equipment, which in turn could impact thetemperature reached by the fluid (and could cause damage to the rotating equipment).

c. This document describes and provides guidelines for the Emergency Depressuring (EDP)system and the Emergency Shutdown (ESD) system as it relates to the EDP along withbriefly discussing depressurisation as it relates to maintenance. The EDP and ESD systemsare integral parts of the overall operations and safety systems provided for a facility.

1.2. Objective

a. Early detection and isolation of hazardous releases and reduction of certain hazardousinventories can substantially limit the consequences from an emergency situation such as amajor release of flammable materials, hydrocarbons or a fire. An emergency Shutdown(ESD) and emergency vapour space depressurisation system shall be provided in situationswhere rapid isolation of uncontrolled releases is desirable; to shut off secondary fuelsources that could feed a fire or vapour cloud, and to minimize releases through the use ofrapid depressurisation. Coupled with a fire and gas detection system, strategically locatedand properly designed ESD and EDP valves can significantly reduce exposure from fireand vapour clouds.

b. These systems do not replace any requirement for providing pressure safety valves (PSV)as required by regulation, and are supplemental to plant pressure relief protection systems.

1.3. General requirements

a. This GP specifies BP general requirements for vapour depressurising systems as applied toall sectors: Exploration and Production; Refining and Marketing; Gas, Renewables, Supplyand Trading. However, additional sector factors may have to be taken into account andreference should be made to any sector specific GP(s) in the ETP library.

b. Plants, systems, and facilities covered by this GP require some form of operationaldepressurisation. Depressurisation can also be required for emergency situations. Clause 9provides the information necessary to select a depressuring system and means of disposalapplicable to a particular facility.

c. Contractors are to develop designs and apply their services in accordance with theprinciples of this GP as amplified or modified by any accompanying supplementaryspecification(s). Proposed depressurisation designs, services, calculation methodologies,and the final depressurisation system design shall be subject to general discussion with andwritten approval by BP.


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1.4. Calculation methods

This GP provides guidance on calculation methods to be used for determining:

a. Depressurisation loads.

b. The effects of depressurisation on the temperature of plant piping.

c. The effects of depressurisation on the minimum design temperature of vessels.

2. Normative references

The following normative documents contain requirements that, through reference in this text,constitute requirements of this technical practice. The latest edition of the following normativedocuments apply.

BP

GP 24-03 Guidance on Practice for Concept Selection for Inherently Safer Design.GP 24-10 Guidance on Practice for Fire Protection – Onshore.GP 24-20 Guidance on Practice for Fire and Explosion Hazard Management of

Offshore Facilities.GP 24-24 Offshore Passive Fire Protection.GP 30-35 Guidance on Practice for Control Valves and Pressure Regulators.GP 30-45 Guidance on Practice for Human Machine Interface for Process Control.GP 30-76 Guidance on Practice for SIS – Development of the Process Requirement

Specification.GP 30-80 Guidance on Practice for SIS – Implementation of the Process

Requirements Specification.GP 30-85 Guidance on Practice for Fire and Gas Detection.GP 43-54 Guidance on Practice for Depressurisation of Pipelines.GP 44-70 Guidance on Practice for Overpressure Protection Systems.

GP 44-80 Guidance on Practice for Relief Disposal Systems.GP 62-01 Guidance on Practice for Valves.PSS 10 BP Refining Process Safety Standard No. 10.0 -

Hydrotreating/Hydrocracking.gHSEr BP’s Getting HSE Right.

American Petroleum Institute (API)

API RP 521 Guide for Pressure-Relieving and Depressuring Systems.

American Society of Mechanical Engineers (ASME)

ASME VIII Boiler and Pressure Vessel Code, Section VIII, Pressure Vessels.

American Society for Testing and Materials (ASTM)

ASTM A515 Specification for Pressure Vessel Plates, Carbon Steel, for Intermediateand Higher-Temperature Service.

British Standards Institute (BSI)

BSI PD 5500 Unfired Fusion Welded Pressure Vessels.


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Energy Institute (Previously known at the Institute of Petroleum)

IP 9 Model Code of Safe Practice in the Petroleum Industry, Part 9 - LiquefiedPetroleum Gas.

National Fire Protection Association (NFPA)

NFPA 59A Standard for the Production, Storage, and Handling of Liquid NaturalGas.

Other

BLOWDOWN™ Software developed by Imperial College in London.

Note The contact for information on this program is Dr. StephenRichardson, Department of Chemical Engineering, ImperialCollege, London United Kingdom SW7 2BY.

3. Terms and definitions

3.1. Terms

a. In this GP the term ‘approve’, as applied to BP, is used if BP does not wish a design toproceed unless certain features have been agreed in writing with a contractor or supplier.This does not imply that all details in a written document have been considered by BP anddoes not affect the design responsibilities of the contractor or supplier.

b. Throughout this document, the words ‘should’, ‘shall’ and ‘must’, when used in thecontext of actions by BP or others, have specific meanings. For the purposes of this GP,the following terms and definitions apply:

1. “Should” - is used if a provision is preferred.

2. “Shall” - used if a provision is mandatory.

3. “Must” - is used only if a provision is a statutory requirement.

3.2. Definitions

BlowdownCan be used interchangeably with ‘depressurisation’ but more commonly taken to mean a rapidrelieving of all system pressure down to atmospheric or low pressure levels.

BPBP p.l.c. and their associates.

Controlled DepressurisationAn instrument controlled depressurisation generally giving a lower maximum flow rate over a longer

period of time than uncontrolled depressurisation.Depressurise or DepressurisationTo reduce the internal pressure of process equipment.

DraindownDraining of liquid from vessels or storage to remove the source of flashing liquid that may feed a fire.

Emergency DepressurisationThe ability to rapidly depressurise, by release of gas, a plant or part of a plant in an emergency.


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Operational DepressurisationThe ability to depressurise equipment, by release of gas, to permit decommissioning and maintenanceoperations.

Yellow ShutdownOn an offshore production facility, the production process from wellhead valves to export lines is

shutdown and isolated. Other systems remain in operation. This type of shutdown normally includescontrolled depressurisation of the production facilities.

4. Symbols and abbreviations

For the purpose of this GP, the following symbols and abbreviations apply:

EDP Emergency Depressuring

EDPV Emergency Depressuring Valve

ESD Emergency shut-down

ESDV Emergency shut-down valve

LPG Liquefied petroleum gas

MCR Main Control Room

PAS Process Automation System

PSD Process shut-down (i.e. not ESD)

SI Systeme International d'Unites

SIL Safety Integrity Level

SIS Safety Instrumented System

5. General

A depressurisation system is a means of reducing the pressure in a process plant or pipeline below the normal operating pressure. The main reasons for this are:

• For maintenance and inspection.• To reduce the failure potential of pressure containment equipment for scenarios

involving over-temperature from a fire or exothermic/runaway processreactions.

• To minimise release of fuel that may be feeding a fire or could be ignited.

• To minimise the uncontrolled release of hazardous gases.• To mitigate the effect (i.e. size and/or duration) of a jet fire.

Like pressure relief, depressurisation is generally to a flare or remote vent. It isnormal to be able to utilise part or all of the relief system for depressurisation.

a. Disposal is normally to a flare, but an atmospheric vent may be pursued for emergencydischarge in rare instances when the project can demonstrate flaring is not an option andGP 44-80 conditions for venting with the required management approvals are obtained.


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Vents must also follow applicable local regulations, discharge to a safe location (refer toAPI 521, Section 5), and have appropriate dispersion analysis conducted.

b. Depressurisation systems may be installed to cover operational and/or emergencysituations and may be automatically or manually initiated.

c. Depressurisation systems shall be developed in accordance with the strategy and associatedperformance standards for managing major hazard events in GP 24-03 and either GP 24-10(for onshore facilities) or GP 24-20 (for offshore facilities) as appropriate.

d. GP 44-70 and GP 44-80 contain further guidance on both system design and requiredprocess components for depressurisation systems.

Dependent upon the nature of the contained fluid, depressurisation can cause lowtemperatures (auto-refrigeration) which can form large volumes of liquidcondensate, plugging of the depressurisation system due to solids being formed(freezing) or the need for more expensive materials to avoid brittle fracture issues.

6. Operational vapour depressurisation

6.1. General

Operational depressurisation is often required for the shutdown of machinery andas preparation for plant inspection and maintenance.

The maximum rate of depressurisation is influenced by:

• The reduction in temperature due to auto-refrigeration (see clause 12.1),• The disposal system (e.g., flare) capacity, and• The pressure rating of the depressuring system and connected equipment.

The addition of supplemental fuel gas to the flared gas may be required to maintainthe minimum heating value required for proper flare operation when depressuringvessels containing inert gas or other gas with a low heating value.

6.2. Plant and equipment

a. Sections of plant or individual plant items containing hydrocarbon gas and/or liquid shouldnormally be isolated, depressurised, drained, and purged to allow access for inspection andmaintenance.

b. Offshore, operational depressurisation should use the same valve as emergencydepressurisation, if installed, to minimise weight, minimise leakage to flare, and provide ameans of testing the valve. For manual depressurising the valve auto position should beoverridden by local key lock to prevent the depressurisation logic becoming over complex.

c. In onshore applications, the system may be the same as offshore; although a dedicatedoperational depressurisation valve is often used.

6.3. Pipelines

Pipeline depressurisation is not covered within this GP; refer to GP 43-54 for pipelinedepressurisation guidelines.

Occasionally depressurisation of pipelines may be required to allow for inspectionor repair. Generally, pipeline depressurising times are extensive, measured in daysrather than minutes, making the pipeline unavailable for transportation; which maybe particularly important when more than a single operator is reliant on the

pipeline availability.


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7. Emergency vapour depressurisation

7.1. General

Emergency vapour depressurisation is generally used to avoid incident escalation, therebyreducing risk to personnel and limiting property or environmental damage. Examples are:

a. Reducing the failure potential of pressure containment equipment for scenarios involvingover temperature from a fire, exothermic or runaway process reaction.

b. Minimising the release of fuel that may be feeding a fire or could be ignited.

c. Minimising the potential uncontrolled release of hydrocarbons or hazardous gas.

d. Mitigating the effect (i.e., size, impact, and/or duration) of a jet fire.

7.2. Vessels, aboveground pipework, and valves

Vessels and aboveground pipework are normally protected from overpressure in the fire case by relief valves. However during a fire, high pressure vessels or systemscan heat-up rapidly and rupture at pressures below vessel design pressure or reliefvalve set pressure.

The rate of temperature increase and hence the decrease of vessel strength is morerapid for gas filled systems since the rate of heat transfer and thermal capacity for agas are less than a liquid. The same applies to the gas space of vessels that could besubject to flame impingement.

a. Provision may be made to insulate the vessel vapour space, or apply external water forcooling, or to depressurise the vessel by means of a vapour depressurising system. Whendealing with vapour, the objective of a depressurising system should be to keep the internalpressure of the exposed vessels and piping below the rupture pressure as the yield stress ofthe wall reduces due to overheating.

b. Depressurisation may also be used to minimise uncontrolled release from a vessel orpipework resulting from a leak such as a blown gasket or leaking valve.

Detection of the gas followed by depressurisation minimises the possibility ofignition. If ignition has already occurred, depressurisation on fire detection limits

fuel supply to the fire.

c. The platform topsides section of a subsea pipeline, including the pig launcher/receiver anddownstream pipework to the pipeline ESDV at the riser/topsides interface, should bedepressurised through the normal platform system. The platform design shall ensure thatthe ESDV and downstream pipeline are fire protected, so the pipeline inventory can bemaintained.

d. Deluge systems are designed to minimise the temperature rise of equipment in andsurrounding a fire. Passive fire protection may be considered for vessels particularly at riskin a fire, in addition to or instead of deluge systems. Refer to fire protectionGP category 24 for more specific information and GP 30-85 on fire and gas detection.

7.3. Compressors

a. Blocking in and depressurisation of centrifugal compressors is required on seal oil failure.Depressurisation is required within the hold-up time of the seal oil overhead tank toprevent gas escape via the seals.

b. For compressors with seals not relying on a seal oil system to contain the gas, thecompressor may be considered as part of the depressurisation system.


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8. Depressurisation requirements

8.1. General

a. ESD and EDP systems shall be reliable, failsafe, and based on proven design conceptsutilizing a SIS designed in accordance with GP 30-76 and GP 30-80. The SIS shall beindependent of the PAS though operators may view the ESD/EDP status through a

common human machine interface. See GP 30-45. The SIS for an ESD/EDP system shallcomply with the SIL determined during Front-End Engineering Design and detaileddesign. The ESD and EDP systems shall have a simple interface with plant operators toallow a safe shutdown and, if required, depressuring without plant operators having toconsider many alternatives.

b. The following factors shall be considered in determining the maximum rate ofdepressurisation:

1. Reduction in temperature due to auto-refrigeration (see 12.1) from depressurisation.

2. Process flare capacity requirements.

3. Pressure rating of the relief/ vent system and connected systems.

4. Impact on pipe supports.

5. Impact on flare pilots (e.g. potential for extinguished pilots due to highdepressurisation rate).

6. Noise induced by depressurisation.

c. In case of an emergency, the ESD and EDP systems should perform, as a minimum, butnot be limited to, the following functions:

1. Stop selected inlet and outlet hydrocarbon streams by closing dedicated ESDVs.

2. Stop flow of incoming thermal energy or heat sources within ESD zone (Such as fuelsources, furnaces, and steam to reboiler, if any).

3. Stop selected drivers on pumps and compressors. Some facilities such as lube oil andseal oil system for compressors, turbines, and lighting system are not stopped ortripped.

4. Stop outlet liquid hydrocarbon streams by closing ESDVs on vessels requiringinventory containment, and trip associated pumps.

5. Enable opening of dedicated EDPVs.

8.2. Emergency shutdown system

The PSD/ESD system normally comprises a hierarchy of shutdown levels (i.e.,individual plant equipment, a process skid or module, a localized geographic plantarea [often referred to as a zone], and the entire facility). The extent of a process or

plant shutdown and the respective initiating conditions are generally defined as partof the initial design. Some factors influencing the extent of an emergency shutdown

include, but are not limited to, equipment operating pressure rating, operating philosophy, flare restrictions, and available fire fighting facilities.

Manual ESD activation is at the discretion of an operator and is typicallyaccomplished via hard-wired manual switches located in the MCR and at strategic

positions throughout the facility. Note that ESD valves may be shared by othershutdown systems.

Automatic activation of a shared ESD valve by other systems is allowed; however, manual ESDvalve activation shall override any automatic process shutdown.


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8.3. Emergency shutdown valves

a. In determining ESDV locations, consideration should be given to equipment prone tofailure or containing inventories of materials that present significant fire, vapour cloud, ortoxic exposures as well as operational requirements associated with the process. Failures ofrotating equipment, fired heaters, expansion joints, and loading operations are recognizedas high frequency and in some cases having high consequence loss exposures. The GP 24

series referenced in clause 2 provides further guidance.b. Final ESDV locations should be reviewed by process hazard analyses and design hazard

reviews that address the impact of isolation on operations.

Some typical ESDV locations are potentially located at:

• Pressurised and refrigerated storage tanks.• Feed gas lines.• Storage tanks containing highly corrosive or toxic materials.• Vessels containing large hydrocarbon inventories.• Pumps and manifolds for ship, rail, or truck loading and unloading.• Discharge lines on charge pumps.• Turbine fuel systems.• Process pumps.• Fired heater process lines and fuel pumping systems.• Refrigeration systems using a flammable medium.• Hydrocarbon loading lines.

c. ESDV location(s) and use shall be optimised based on the individual system configuration.The minimum hydrocarbon liquid level contained in vessels and tanks shall: be specific tothe type of fluid, be determined by regulations and consequence analysis, and require thatan ESDV be installed.

d. ESDVs on accumulator and process vessels should be placed as close as possible to thevessel outlet flange.

e. ESDVs for process area isolation shall be located at the edge or boundary of the processarea being isolated. Upon activation, the ESDV shall stop the flow of inlet and outletprocess streams, hazardous utility streams, and fuel supply to the affected area.

f. It is important that the location and number of not only ESDVs but also depressuringvalves consider:

1. Check valves or other flow restrictions that can impede depressurisation.

2. Packed vessels where packing can be entrained by depressuring.

3. Other equipment such as compressors that can impede or affect depressurisation.Note in some cases the depressurisation path may be opposite to the normal flow pathand/or at a significantly higher flow rate than normal.

g. Generally, an ESDV shall be a tight shut-off, “fail close” (on loss of signal or powersource), air/pneumatic operated block valve. An ESDV and its accessories shall be of firesafe design if located inside a fire zone.

h. LNG service ESDVs should be located in accordance with NFPA 59A. For applicationsnot subject to NFPA 59A, ESDVs should not be located at long distances from the processunit just to avoid installation in the fire zone without considering the consequences ofhaving a potentially larger hazardous material release.


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i. In general, ESDVs should be located outside of buildings housing hazardous processes orhazardous utility equipment.

j. If necessary, a hydraulic actuating system in lieu of air may be used. If hydraulic valvesare selected, these shall be equipped with a secured supply of actuating fluid and back-upsystem and be protected as necessary against potential hazards.

k. In general, the use of spring return air operated valves shall be selected for the ESDVs atfirst from reliability and maintainability points of view. However, for large size valves,etc., which require large torque, the application of double acting air cylinder type orhydraulic type, etc. shall be investigated with consideration of constructability andmaintainability. If double acting air cylinder or hydraulic valves are used as ESDVs, an airbottle or hydraulic accumulators sized to provide an independent air or hydraulic supplyfor at least three (3) cycles, i.e. Close-open-close-open, to provide motive energy to movethe valve to its fail safe position shall be provided. Additionally, valve and actuatorcomponents, including wiring, air supply, etc, should be protected against potentialhazardous exposures. Inherently failsafe actuation is preferred.

l. ESD valves shall not be provided with handwheels. ESD valve shall be equipped withopen/close position limit switch and the open/close indication shall be displayed on thePAS.

m. The scope and requirements to provide online testing of the ESDVs shall be developedduring the design to meet the required integrity levels. Control valves shall not be used asESDVs, unless specifically justified and failure of the control loop cannot cause a demandon the ESD function.

n. The type of ESDV shall be defined dependent on the service requirements and size of thevalve. Further guidance on ESD valve selection is provided in GP 62-01.

8.4. Emergency depressuring (EDP) system

a. The scope of details of EDP shall be developed during design. EDP for each skid, processarea, or the total plant, if applicable, shall be enabled only after activation of the ESDsystem.

Activation of EDP is typically accomplished via hard-wired manual switches thatare located in the MCR and, for some offshore installations, automatically onconfirmed detection of fire or gas release.

b. The EDP system shall have adequate venting capacity to achieve reduction of stress inselected equipment affected by fire to a level at which stress rupture is not an immediateconcern. In addition, it should be designed to enable minimization of fuel inventory thatmight otherwise aggravate a fire and to minimize the uncontrolled release of flammable ortoxic gases.

c. EDP system (once activated) shall be able to reduce the pressure of the system to thepressure and maximum duration provided in Annex A.

d. The design of piping and equipment shall consider the temperature reached during auto-refrigeration. Vapours released during depressuring shall be vented to the flare system orother BP approved location.

e. The depressuring system shall consider, on a case-by-case basis, automated “liquidblowdown” capabilities. The advantages and disadvantages of liquid blowdown shallconsider that the depressurisation rate depends on the boiling rate of the liquid.Significantly longer depressurisation times are likely required compared to cases where thevessels are only filled with gas.

Removing liquid from a vessel exposed to a fire eliminates the cooling effect of thewetted surface area and the equipment heats up quicker, increasing the failure

potential due to overheating.


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In a non-fire case, liquid blowdown frequently reduces auto-refrigerationtemperature effects.

8.5. Emergency depressuring valves

a. Depressuring valves shall, in general, be tight shut-off (to avoid loss of hydrocarbonsduring normal operation) air operated block valves. See GP 62-01.

b. The EDPV is typically designed to “fail close” or fail in the last position. However, thefailure position of each valve shall be reviewed during the design hazard review. Shouldthe EDPVs fail open, operational upsets due to malfunctioning valves or inadvertentopening of the valves should be considered as-well-as any single mode failure resulting inthe EDPVs simultaneously opening and potentially exceeding flare capacity.

c. Use of a single control valve to serve as both an EDP and a letdown-to-flare should followGP 30-35. This common usage also needs review during the design hazard review toensure this design does not result in a common mode failure that could contribute to thecause and thus defeat a protective system.

d. The scope and requirement to provide online testing of the depressuring valves shall bedeveloped during design to meet required integrity levels.

9. Application of depressurisation systems

9.1. General

Plants and process systems covered by this GP require some form of operationaldepressurisation. This section summarizes where emergency depressurisation systems arerequired.

The use of a depressurising system maintains the integrity of equipment by reducingthe possibility of vessel rupture.

a. If a depressurising system is not required by regulation, the risk and effectiveness of thesystem should be considered. This entails developing a fire damage assessment, assessingthe viability of depressurising to mitigate undesirable leaks and spills, then fully evaluatingpersonnel risks and plant replacement costs with and without a depressurising systeminstalled. During this assessment the following points should be considered:

1. The probability of a fire and/or significant leakage of flammable material.

2. Stress rupture may not occur as the fire may die out or be extinguished. Note theinventory of a gas plant is generally significantly less than an oil installation andtherefore oil fires could last appreciably longer.

3. Water deluge, or insulation, or both, may provide sufficient protection to minimisewall temperatures over the duration of the fire.

4. Vessel design pressure may be substantially higher than the maximum operatingpressure; reducing the possibility of rupture.

5. Upgrading material selections for equipment subjected to low temperatures as a resultof depressurisation and auto-refrigeration can substantially increase investment costs.

6. Inadvertent activation of depressuring system can cause significant production lossand possible downtime.

7. Heavy flaring caused by activation of depressuring system (refer to BP gHSEr).

8. The potential risk of personnel injury shall be adequately assessed.


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9.2. Manned production platforms and floating production facilities

a. Manned platforms shall have emergency depressurisation systems to safeguard personneland protect the investment. On platforms where process plant is totally enclosed orenclosed by louvers, gas detection should initiate yellow shutdown followed by automaticdepressurisation.

b. To minimise spurious trips, the shutdown and depressurisation should be the result of gasdetection by two detectors in a voting system. These detectors should produce a pre-alarmsignal to allow possible operator intervention before the plant trips and depressurises.

c. On open deck platforms, gas detectors are unlikely to detect anything but very large leaks.However if they are used they should initiate yellow shutdown and depressurisation. Onopen deck platforms a vapour cloud is much less likely to form than in an enclosedplatform and if the leak is large, depressurisation is unlikely to be necessary after an ESDhas taken place.

d. Floating production facilities are invariably manned and are therefore covered by the same,above criteria.

9.3. Unmanned production platforms

a. Unmanned platforms should be fitted with emergency depressurisation systems if theproduction facilities contain more than 30 tonnes (30 tons) of hydrocarbons either stored ator capable of exceeding API 521 criteria (50% of vessel design pressure) during normaloperations, a fire case, or a process excursion.

b. Gas or fire detection on unmanned platforms shall result in a process shutdown. Thedepressurisation should be manual; either initiated by operators visiting the platform or ifthere are no personnel on the platform, by operators at the controlling platform or terminal.Initiation of depressurisation should consider helicopter operation in the platform vicinity.

c. Use should be made of fire protection for systems most at risk from a delayeddepressurisation.

9.4. Onshore gas/condensate plants

9.4.1. Gas terminals

If a terminal contains pipework and tankage but no process plant, depressurisation is unlikely tobe appropriate in emergency situations. Fire protection with water deluge and/or passiveprotection should be used with drain down if appropriate.

9.4.2. Stabilisation or fractionation plants and gas terminals with processing plant

Emergency depressurisation should be considered for high pressure plants (significanthydrocarbon stream(s) above 70 barg or 1 000 psig) and those with a large inventory (greaterthan 10 tonnes [10 tons]) of pressured hydrocarbon. Fire protection in association with pavingand drainage systems design to limit the spread of fire should be considered. Refer to APIRP 521.

9.4.3. Pressured LPG storage

The protection and safety of pressurised LPG storage systems is covered by IP 9. Fireprotection, both passive and with water deluge, shall be used for fire protection, as appropriate,and no vapour depressurisation is required.


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9.5. Hydrotreating/hydrocracking reactors

9.5.1. General

a. Hydroprocessing reactors above 34 barg (500 psig) separator operating pressure shall beprovided with a fail safe depressuring system that can be activated from the control room.The main purpose of this depressuring system is for high pressure inventory disposal under

unit emergency conditions such as fire. Fail safe means that the valve(s) used fordepressuring the unit fails open on loss of signal or de-energisation. The depressuringvalve can also serve as the normal pressure control valve.

b. The protection and safety of the pressurized reactor section of a Hydroprocessing unit shallcomply with BP Refining PSS 10.

9.5.2. New build hydroprocessing reactors with cracking catalyst

a. New build hydroprocessing reactors (post January 2000) containing catalyst with crackingfunction and above 70 barg (1 000 psig) separator operating pressure shall be providedwith a fail safe depressuring system that can be activated from the control room and in thefield local to the plant. Fail safe means that the valve(s) used for depressuring the unit failopen on loss of signal or de-energisation. The depressuring valve/s shall be dedicated

shutdown valve/s separate from normal unit controls.b. The depressuring system shall have automatic initiation by high reactor temperature. High

reactor temperature is defined as 30°C (54°F) above normal operating temperature orreactor mechanical design temperature, whichever occurs first. Depressuring shall not beable to be interrupted until all temperatures are 25°C (45°F) below trip setting. Initialdepressuring rate shall be maximized up to the industry practice of 21 bar/min(300 psi/min) subject to reactor bed support and flare system constraints, but in no casesshall be less than 14 bar/min (200 psi/min).

9.5.3. Existing hydroprocessing reactors with cracking catalyst

a. Existing hydroprocessing reactors containing catalyst with cracking function and above70 barg (1000 psig) separator operating pressure shall be provided with a fail safedepressuring system that can be activated from the control room and in the field local tothe plant. Fail safe means that the valve/s used for depressuring the unit fail open on loss ofsignal or de-energisation. The depressuring valve/s shall be dedicated shutdown valve/sseparate from normal unit controls.

b. The depressuring system shall have manual or automatic initiation by high reactortemperature. High reactor temperature is defined as 30°C (54°F) above normal operatingtemperature or reactor mechanical design temperature, whichever occurs first.Depressuring shall not be able to be interrupted until temperatures are 25°C (45°F) belowtrip setting. Initial depressuring rate shall be at least 14 bar/min (200 psi/min).

10. Time for depressurisation

10.1. Fire casea. If depressurisation is not the controlling rate for design of the flare, vessels designed to

BSI PD 5500 should be depressurised to 6,9 barg (100 psig) or 50% of the design pressure,whichever is the lower pressure, in 15 minutes. Vessels designed to ASME VIII, BSI PD5500 or equivalent which are 25 mm (1 in) wall thickness or greater, should bedepressurised to 50% of their design pressure in 15 minutes if the vessel is uninsulatedcarbon steel construction (see Annex A).

b. Vessels designed to ASME VIII and pipework of wall thickness less than 25 mm (1 in)should be depressurised proportionately faster (see Annex A).


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c. If depressurisation governs flare design capacity, the rate of vessel(s) and pipeworkdepressurisation should be related to the reducing strength of the steel exposed to fire. Thedepressurisation rate selected and method of calculation shall be subject to BP approval.

d. If necessary to reduce the flow rate of gas to flare or vent, longer depressurisation timesmay be proposed for BP approval for vessels containing liquid, having external insulation,or having wall thickness greater than 25 mm (1 in).

Vessels containing liquid or having external insulation take longer to heat up thannon-wetted or bare vessels. Also vessels of wall thickness greater than 25 mm (1 in)take longer to heat up than the 25 mm (1 in) thick vessels used as a basis in API

RP 521.

For equivalent wall thicknesses, stainless steel vessels generally allow lowerdepressurisation rates than carbon steel (see Annex A) because stainless steelbegins to lose strength at a higher temperatures than carbon steel.

10.2. Non-fire case

The 15 minute depressurisation guideline does not apply to non-fire case. Refer to formal riskanalysis, Annex A, and API RP 521 guidelines.

10.3. Stopping depressurisationDepressurisation should not be stopped on reaching the target pressure (See Annex A). Pressurenormally continues to reduce until atmospheric pressure or the flare or vent backpressure isreached. Stopping the depressurising process should be evaluated on a case-by-case basis if it isdeemed discontinuing depressurisation can be conducted safely. See clause 13.

11. Methods of depressurisation

Initial depressurisation flow rates may be substantial and create difficulty in the design of theflare or vent systems. There are ways to reduce this high initial flow as discussed below.

11.1. Uncontrolled depressurisation

In a normal uncontrolled depressurisation the total system is shutdown and isolatedand the pressure in the process equipment is discharged to flare or vent through theemergency blowdown valves, restriction orifices, and headers. This creates aninitial peak flow rate that decays over the major portion of the depressurising

period.

The depressuring time and the end pressure (clause 10.3) are of great importancewhen determining the load to flare or vent. In addition to the load from the systembeing depressurised there is a possibility of continued in-flow into the system beingdepressured, e.g. from wells that have not shut-in, and consequently more gas isrouted to flare increasing the total gas depressuring rate.

11.2. Depressurisation by zone

Offshore, process plant often occupies a number of fire zones, i.e. areas separatedby firewalls within which a fire can be contained. Onshore, fire in one area can be

prevented from reaching other areas by distance and bunding or kerbing.

This division into fire zones is an important means to reduce the maximum flare loadin cases of emergency depressurisation. It is more applicable to onshore plants, butcan be applied offshore if good fire zone segregation is achieved.

a. Consideration should be given to depressurising only those vessels and equipment withinthe fire zone in which fire or gas is detected. Depressurisation of vessels and equipment in


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adjacent fire zones should be timed to follow, or be at the discretion of the operator, but inany case should be delayed to minimise the size of the flare or vent system. A reduction inflare size by zoned depressurisation shall only be accepted if total depressurisation cannotoccur from a common cause (e.g. simultaneous loss of instrument air to alldepressurisation valves).

b. In exceptional circumstances, BP may approve a reduction in the peak discharge rate due

to the distributive nature of the relieving flow and the requirement for pressure build-up todischarge the system inventory. The use of any such reduction shall require specific,written approval of the BP responsible Engineering Authority (EA).

c. The designer should be aware of and prevent common cause failures, e.g. breakdown of adistributed control system in one area shall not affect any other process areas.

11.3. Controlled depressurisation

In a controlled depressurisation, the peak flow rate can be maintained for asubstantially longer period before the decaying phenomenon sets in. Since peak flowis maintained over a longer time, the depressurisation flow rate is reduced inmagnitude compared to the peak flow rate of an uncontrolled depressurisation.

Flow from each section being depressurised is normally initiated by the opening of avalve with the flow controlled by a restriction orifice. It is possible to limit the total

flow rate, but still depressurise in the designated time, by either controlling the flowrate bypassing the orifice with a control valve or snap open valve(s) initiated by atiming sequence. This increases the flow to flare after the peak flow has passed andthe system pressure has reduced.

The use of controlled depressurisation is subject to BP approval, since controlleddepressurisation instrumentation can be less reliable than that used for uncontrolleddepressurisation. Systems containing fail open or fail shut valves rather than control valves aregenerally favoured, but in all cases reliability analysis shall be required for a controlleddepressurisation system.

11.4. Depressurisation flow rates

a. Flow restriction orifices are used in conjunction with snap open valves to set the maximumrate of depressurisation to flare or vent. Alternatively, depressurisation valves may be sizedto ensure the disposal system capacity is not exceeded when all valves go to the full openposition. Depressurisation valves may also be designed to fail closed or in the last positionto eliminate common mode failures provided that reliable valve actuation to theappropriate SIL is assured.

b. Depressurisation flow rates and the resulting system temperatures for gas and gas/liquidsystems shall be calculated in accordance with one of the methods given in Annex B.Maximum depressurisation flow rates tied to a flare system shall not exceed the flaresystem capacity.

c. For controlled depressurisation, the flow may not be totally through single fixed orifice(s).Alternative calculation methods that take this into account shall be considered for this case.

11.5. Draindown

a. In some instances it may be inappropriate to depressurise to flare. An example of thiswould be if a vessel has a considerable inventory of highly volatile hydrocarbon liquidsuch as LPG.

b. In a fire, vessels containing volatile hydrocarbon should be protected by passive fireprotection and/or a water deluge system. To limit vapour generation and possible spread offire, facilities may allow for removal of liquid from the system. This may be possible usingthe normal product withdrawal system to remove liquid from the vessel being protected


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during fire exposure, but could require special consideration of the electrical power andutility system status.

c. In many cases the advantages of retaining the liquid in the vessel to minimise the rate atwhich the vessel heats up outweighs the benefits from removing the flammable liquid fromthe fire zone. The reliability of the deluge system, the availability of separate liquid storageand the fire resistance of the system shall be considered for each case, since this will

probably only be used when a fire has reached a high severity.d. Draindown can also be used to avoid low temperatures resulting from boil-off of highly

volatile liquids and hence reduce the requirement for expensive alloy steel.

12. Effects of depressurisation

12.1. Auto-refrigeration

12.1.1. General

If the contents of a vessel, pipework, or a pipeline are depressurised from a high pressure, gas expansion and liquid evaporation normally cause cooling.

12.1.2. Vessels and pipework In general, if the vessel fluid is all vapour, the rate of heat transfer from the vessel tovapour is negligible. The heat capacity of the vessel is also high compared to that ofthe vapour and the reduction in wall temperature is low. An exception to this can beexit nozzles where significant forced convection takes place during depressurisationrequiring the use of stainless steel nozzles, internal sleeves, or other mitigations toaccommodate these low temperature blowdown effects.

Available information should be carefully considered before selecting the thermodynamicprocess for vessel depressurisation.

Downstream of the orifice where fluids are usually at their coolest and the flow veryturbulent, the rate of heat transfer is high, resulting in the pipework generally

approaching isenthalpic flash temperature. Note that flow up to the orifice throat isan isentropic process while flow in the piping downstream of the orifice is generallyconsidered to be an isenthalpic process. Technical studies have yet to firmlyestablish the type of process within the vessel being depressured (isentropic,isothermal or somewhere in between). The isentropic assumption neglects heat gain

from the surrounding environment and can predict low temperatures upondepressurisation, potentially suggesting a need for low temperature materials. Incontrast, an isothermal process may often suggest that plain carbon steelconstruction would be appropriate, even though fluid kinetic energy gainsdownstream of an orifice can limit available fluid thermal energy and push fluidtemperatures below those predicted by an isenthalpic flash calculation.

In a vessel containing liquid and vapour, vapour expansion and evaporation fromthe liquid cools the liquid. The rate of heat transfer from the container to the liquidis significant. Transfer of heat in from the surroundings often is not negligible in thetimescale of the depressurisation except for fire, sweating (re-condense water fromhumidity), and sweating up to ice layer.

Annex B gives four methods of increasing complexity and accuracy whencalculating minimum wall temperatures resulting from depressurisation. The timeand effort expended on this calculation could depend on the likely equipment costsavings. For example, if a simple flash (Method 1) shows stainless steel is required

for a large vessel by a small margin, it would be reasonable to go to a more complex


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analysis to establish if the minimum wall temperature, so calculated, would allowuse of a less expensive material.

12.2. Hydrates and ice

a. Under certain conditions it is possible for hydrates or ice to form in a hydrocarbon systemcontaining free water. In such systems, if the temperatures calculated on emergency

depressurisations using a simple adiabatic flash are low enough to support hydrates or ice;consideration should be given to using Method 2 in Annex B to establish if a supportingtemperature and pressure can exist at the same time.

b. If a severe hydrate or ice formation problem either upstream or downstream of thedepressurisation valve is possible, provision should be made for methanol injection, otherBP approved chemical injection, or other methods used to inhibit hydrate formation.Consideration should be given to providing a nitrogen pressurised methanol injectionsystem upstream of the valve. Less severe problems may occur when depressurisingdownstream of dehydration plants. In this case although hydrate or ice formation may bepredicted, turbulence around the valve coupled with the relatively short time needed forplant depressurisation will probably prevent formation of a mass large enough to cause ablockage or other damage.

13. Repressurisation

a. If depressurisation results in temperatures lower than the design minimum temperature of asystem, the system shall not be repressured until all temperatures throughout thedepressurisation system have risen to a calculated safe value above the design minimumtemperature. This may require a process system to be substantially above the minimumdesign temperature to allow for temperature reduction from gas expansion or high rates ofliquid evaporation during the process restart. Repressuring a process at temperatures belowa known, safe restart temperature may result in brittle fracture.

b. Whether immediate repressurisation after EDP activation is required shall be determinedby the project in conjunction with operating staff. If immediate repressurisation is notpossible due to low metal temperatures, temperature monitoring and warm up facilitiesshall be provided in order to permit restart/repressurisation within the time period definedby the project and by operational requirements.

c. Depressurisation systems immediately downstream of a re-pressurisation valve may bemuch colder than expected during the early re-pressurisation stages due to Joule-Thompson expansion across this valve coupled with the thermal energy transferred to thedownstream fluid from its kinetic energy gain.

d. If below minimum design temperatures can occur, re-pressuring shall be adequatelycontrolled such that an adequate warm-up period exists. If not, a lower design minimumtemperature should be employed.

e. If depressurisation is interrupted, process consideration should be taken for units with acracking catalyst function to minimize the possibility of reaction runaway.


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Annex A(Normative)

Background to the selected depressurisation time

A.1. Depressurisation purpose

The two primary purposes for an emergency depressurisation system are:

a. Remove internal pressure from a gas-filled vessel(s) to reduce the applied stress on thepressure boundary material, assumed to be a metal, exposed to a pool fire in order toextend the time before failure occurs. This is needed because the strength or load carryingability of a metal decreases with temperature.

b. Remove inventory from a vessel(s) to minimize the amount of material that would bereleased through a leak or rupture. This would reduce or mitigate the consequences fromthe leak or rupture.

A.2. Depressurisation systems designed for pool fire exposure

a. API RP 521 suggests depressurisation of equipment to 50% of the design pressure in15 minutes. Although the methodology can be applied to any metal vessel, the API RP 521criteria is specifically based on a relatively large and/or high pressure carbon steel vessel(i.e., wall thickness of 25,4 mm (1 in)) that is gas-filled (i.e., no liquid so all non-wettedsurfaces) and exposed to a pool fire. The desired depressurisation rate can varysignificantly based on vessel wall thickness, material of construction, initial temperature,type of fire (i.e., pool fire or jet fire), type of failure to be mitigated (vessel yield or vesselrupture), and presence of fireproofing or other fire protection means (e.g., water spraysystems).

b. Note that the following approach is applicable to standard hydrocarbon pool fires.Exposure to jet fires can result in intense, localized heating rates that significantly exceedthat of a standard hydrocarbon pool fire. Higher fire heat fluxes require higher

depressurisation rates than predicted below. If available, jet fire heat flux data should beutilized that is representative of jet fires one might expect in a plant as opposed totheoretical analyses or data obtained in strictly controlled tests.

c. The normal starting point in specifying depressurisation criteria for a specific vessel wouldbe determining the vessel wall heat up time from pool fire exposure. Figure A1 of APIRP 521 provides data on average heat-up rates of steel plates exposed on one side to anopen gasoline pool fire. This Figure indicates it takes about 15 minutes for a 25,4 mm(1 in) thick steel plate to heat from ambient temperature to 650°C (1200°F) in the pool fire.The plate would reach an “equilibrium” temperature of about 760°C (1400°F) in20 minutes. The equilibrium temperature is the temperature at which heat gain from atypical pool fire is balanced by heat loss to the environment and assumes a bare, unwettedplate that is exposed to fire on one side. There can be significant variability in the heat uprate and ultimate temperature attained in a pool fire due to the influence of total heatcapacity of the vapour within the vessel, fire intensity, fire duration, presence of externalinsulation, etc.

d. A typical carbon steel pressure vessel is designed on a conservative basis using arecognized “code”, such as ASME Section VIII and Section IID. For example, a vesselfabricated with SA-516 Grade 70, has a maximum allowable design stress of 138 MPa(20 ksi or 20 000 psi) per ASME Section IID at up to 260°C (500 ° F) temperature.

Note While fabrication stress concentration factors consume aportion of this design stress differential, allowable stress


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values from ASME Section VIII provide a significant safetyfactor well below the ultimate tensile strength of the material.

Typically the allowable stress is the lower of 2/3 the yield strength or 1/3.5 of tensilestrength at the design temperature. The allowable stress value is based on time independentproperties. This means that the material properties do not change with time up to a “code”allowable temperature that is related to a specific material. Above this temperature, thematerial undergoes small metallurgical changes with time. The “code” refers to these astime-dependent properties. These are typically reported as creep or stress rupture strengths.

e. For a pressure vessel exposed to a pool fire, an increase in the unwetted wall temperatureabove the “code” allowable temperature causes a decrease in material strength. Immediatefailure may not be predicted because of conservative “code” design. However, as the metalwall temperature gets quite high, short term failures can occur as predicted based on creepor stress rupture data. Figure A2 (taken from API RP 521) shows the effect of temperatureincrease on rupture strength of typical carbon steel pressure vessel plate (i.e., gradeSA-515). This data was obtained from bibliographical reference [1] (see Figure A3 for theoriginal source data) and is characteristic of all grades of carbon steel. These figures plotrupture stress (i.e., load or stress on the pressure boundary material required to rupture avessel) versus the time to rupture for several elevated temperatures. For a carbon steel

vessel with a 138 MPa (20 ksi) design stress, Figure A2 (or Figure A3), predicts the vesselwould rupture in about 1 hour at 593°C (1 100°F) and 0,1 hour (6 minutes) at 650°C(1 200°F). Hence, vessel rupture can occur in a relatively short time period once the metalreaches a high temperature as long as the internal pressure remains high (e.g., near designconditions).

f. Note that the API curve shown in Figure A2 is extrapolated from the source data shown inFigure A3 for exposure times less than 0,1 hours. Figure A3 also plots the Short TimeTensile Strengths at or near the 0,1 hour data. The Short Time Tensile Strengths should beconsidered the limiting stresses for a given temperature (i.e., exceeding these causefailure). Hence, the extrapolations in Figure A1 at exposure times less than 0,1 hoursshould not be used because the vessel integrity cannot be maintained with an internalpressure that results in total stresses, including residual and applied, that exceed thevessel’s tensile strength. It is also important to note that the vessel can be damaged (e.g.,yielded) at stresses significantly lower than the rupture stress. Hence, any equipmentexposed to fire would need a follow-up inspection and assessment to determine fitness-for-service even if out-right failure did not occur.

g. One way to extend the time before failure occurs is to reduce the internal pressure within avessel (i.e., depressure it). As long as the internal pressure results in stresses below therupture stress, the vessel should not rupture (unless there are material defects/ flaws/previous damage or if one of the components such as a nozzle or flange is a weaker link).The data in Figure A2 or A3 can be used to determine the maximum stresses to avoidfailure, but this requires a fairly comprehensive analysis. However, during the initial heat-up phase, it can be easier to use the short-time tensile strength as a limiting stress that, ifexceeded even briefly, would cause vessel failure. Tensile and yield strength data fortypical carbon steel are given in Table A1 and illustrated in Figure A4. This data can beused to determine depressurisation versus time for vessels using carbon steel with about483 MPa (70 ksi) tensile strength when coupled with heat-up rates.

h. For example, the effect of depressurisation on the time to rupture is required for a large(say 25,4 mm (1 in) wall thickness) vessel fabricated from SA-516 Grade 70 carbon steelwith a design allowable stress of 138MPa (20 ksi). The scenario involves pool fireexposure whereby the internal pressure increases to that equivalent to the design allowablestress in the pressure boundary wall and then stays constant as the vessel continues to beheated. Maintaining a constant pressure near the design allowable stress would becomparable to having the vessel protected by a pressure relief valve. If the vessel was


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initially at ambient temperature, Figure A1 indicates it will take slightly over 10 minutesfor the average vessel wall temperature to reach 538°C (1 000°F). Based on the data inTable A1 and Figure A4, the vessel starts to yield at this temperature because the appliedstress (138 MPa (20 ksi)) would become equal to the yield stress. If the applied stress staysconstant at 138 MPa (20 ksi) and further wall heating occurs, then the vessel will rupturewhen the wall temperature reaches about 650°C (1 200°F), about 14 minutes into the fire(see Figure A1). Rupture can occur at lower temperatures if there are material defects or aweaker component of the vessel construction than the base metal.

i. API RP 521 suggests the internal pressure be reduced by 50% within 15 minutes of poolfire exposure. Figure A1 indicates the average wall temperature 15 minutes into the poolfire would be about 670°C (1 240°F). For our vessel with the 138 MPa (20 ksi) allowabledesign stress (thus applied stress of only 69 MPa (10 ksi) once depressured to 50% internalpressure), Figure A4 indicates that at 670°C (1 240°F) the 69 MPa (10 ksi) stress on thecarbon steel pressure boundary would exceed the yield point (about 62 MPa (9 ksi)), butnot the rupture stress (about 90 MPa (13 ksi)). Thus, the vessel will be damaged, typicallyin the form of bulging. Note that this rupture stress is based on the vessel seeing a walltemperature of 670°C (1 240°F) for the full 15 minutes of pool fire exposure (seeFigure A2 or A3). In other words, i t ignores heat-up time and assumes the wall reaches670°C (1 240°F) at the onset of fire exposure. At the other extreme would be the case

where the vessel wall temperature does not appreciably increase until the end of the15 minute exposure in which case the metal wall sees 670°C (1 240°F) but only for a veryshort time. In this case, the tensile strength would be the limiting factor (about 117 MPa(17 ksi) at 670°C (1 240°F) from Figure A4). The actual internal pressure where ruptureoccurs will likely be in between the rupture stress and tensile strength given the pool fireheat-up rate is not instantaneous.

j. It is important to note that the vessel wall temperature can continue to increase perFigure A1. Based on a maximum wall temperature of 760°C (1 400°F), furtherdepressurisation would be required to avoid rupture. The bottom curve in Figure A2 (orFigure A3) indicates the internal stress would need to be reduced to about 34,5 MPa (5 ksi)or 34,5/138 (5/20) = 25% of the MAWP to extend the time to rupture to about one hourand reduced to about 27,6 MPa (4 ksi) or 27,6/138 (4/20) = 20% of the MAWP to extendthe time to rupture to about 4 hours.

k. The depressurisation path as a function of time for carbon steel of several thicknesses isillustrated in Figure A5. This figure illustrates the depressurisation path to minimize failurepotential due to fire exposure as a function of percent of MAWP. Because of the fasterheat-up rate (see Figure A1), thinner walled vessels require faster depressurisation. Thesevarying rates of depressurisation become important when designing a commondepressurisation system for interconnected vessels of different sizes and/or designpressures. In such cases, a fire could simultaneously expose multiple vessels of varyingwall thicknesses. Judgement needs to be taken as to which vessels are included in thedepressurisation system design. Rapid depressurisation required for small vessels must bebalanced not only with the available disposal system capacity but also with the failureconsequences of small versus large vessels.

l. In addition to reducing the likelihood for rupture, depressurisation would reduce theconsequences in the event of rupture due to fire exposure. Upon rupture, the mechanicalenergy (gas stored under pressure) is converted to a blast wave that can damage adjacentequipment due to overpressure. In addition, fragments can be produced upon failure.Possible impacts of the failure should be analysed on a case-by-case basis. The generaleffect of depressurisation on distance to overpressure effects (e.g., side-on overpressures)due to vessel failure is illustrated in Figure A9.

m. The material data presented above applies to typical carbon steel. Alloy materials,including low alloy steels, stainless steels, and nickel base alloys, show similar strengthloss with temperature as carbon steel, but less dramatic: a sample of rupture strength versus


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temperature for type 304 stainless steel (i.e., 18-8 grade) is shown in Table A2 andFigures A6 through A8.

n. It is important to recognize that the tensile and rupture strength data given in this Annexare used as an example of how depressurisation calculations for pool fire exposure can bemade. The sources for this data are typical industry data (1, 2, 3, and 4). However, thedesigner should be aware that the values provided by all such references are not

necessarily consistent with each other. Variability in the pool fire (heat-up rate, maximumequilibrium temperature, view factors, size, duration, extent) can further complicatedepressurisation requirements. Given the variability in assumptions, the designer should becareful not to overanalyse the depressurisation system requirements but to select anappropriate criteria for their specific facility requirements.

A.3. Depressurisation systems designed to minimize leak size

a. The second use of a depressurisation system is to mitigate the effects of a leak. A reductionof vessel pressure through depressurisation to a “safe” location, such as a flare, reduces notonly the leak rate but also the leak duration through reduction in vessel inventory.Depressurisation is one of the few mitigation measures for a jet fire whereby if the sourceof the jet fire were depressurised, the size and effects are attenuated. Once depressurised tonear atmospheric pressure, the jet fire would in essence be “turned off” as the source offuel would be depleted.

b. The design of a depressurisation system to mitigate consequence of leaks is dependentupon the following:

1. Nature and extent of consequence (toxicity hazard, flammability hazard (vapour cloudexplosion and/or flash fire extent and potential), jet fires, environmental release);

2. Location of potentially vulnerable public, plant personnel, environmental aspects,equipment;

3. Location and configuration of adjacent equipment (particularly important regardingmitigation of jet fire impacts);

4. Capacity of the disposal system where the depressurisation system discharges;5. Inventory of fluid requiring depressurisation including liquid that can flash into

vapour upon depressurisation;

6. Evacuation considerations.

c. Generally, a starting point in the depressurisation system design would be using a totalinstantaneous depressurisation rate equal to no more than the capacity of the disposalsystem (e.g., flare). It is critical to stay within the disposal system capacity even duringutility failures such as loss of instrument air that may cause all the depressurisation valvesto open simultaneously (if so designed to fail in the open position upon air failure andwithout a backup air supply).

d. Because of the variability in processes and reasons for depressurisation in non-fire

situations, it is recommended the designs be handled on a case-by-case basis. Consequencemodelling should be performed to determine specific depressurisation goals. In manycircumstances, a depressuring level to no more than 0,7 MPa (100 psig) is commonly usedas the design basis.

A.4. Calculation of depressurisation mass flow rates

a. With depressurisation calculations now embedded in process simulation software, manualcalculation of blowdown times by step calculations at various reducing pressureincrements is no longer adequate. Manual calculations are only approximate, always


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require subsequent verification from a more rigorous analysis, and can provide verymisleading results depending on the assumptions made and coefficients being used.

b. Process simulation users should recognise there often can be limitations to these built-indepressurisation solutions. Some packaged software calculations fail to take properaccount of phase changes and heat transfer (or heat loss). As one example, high purityliquids stored near their bubble point are not handled well.

A.5. API 521 guidelines

Refer also to API 521 Section 3.19 for further guidance on depressurisation flow rates.


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Figure A1 - API RP 521 figure on average rate of heating steel plates exposed to open gasoline fire onone side


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Figure A2 - API RP 521 figure on effect of overheating steel (ASTM A515 grade 70)

Figure A3 - Typical carbon steel (SA-515, grade 70) rupture stress versus time to rupture(bibliographical reference [1], Page 20)


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Table A1 - High temperature tensile properties for typical carbon steel (1)

Temperature,°F

Temperature,°C

TensileStrength, psi

TensileStrength, MPa

Yield Stress0,2% Set, psi

Yield Stress0,2% Set, MPa

750 399 58 000 400 24 600 170900 482 45 500 314 23 500 162

1 000 538 36 500 252 20 100 1391 100 593 27 200 188 14 250 981 200 649 20 000 138 10 200 701 300 704 13 500 93 7 375 51

1 400 760 9 025 62 3 750 26(1) Applies to SA-515 and SA-516 carbon steels, Grade 70.

Reference: bibliographical reference [1], Page 16.

Figure A4 - Typical carbon steel (SA-515, grade 70) tensile strength and yield stress versustemperature (bibliographical reference [1], Page 16)

0

5000

10000

15000

20000

25000

30000

35000

40000

1000 1100 1200 1300 1400

Degrees F

S t r e n g

t h o r

S t r e s s

P S I

Tensile Strength Yield Stress


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Figure A5 - Typical carbon steel (SA-515, grade 70) internal pressure versus pool fire exposure timeto minimize potential for vessel rupture

0%10%

20%30%40%50%60%70%80%90%

100%

0 5 10 15 20 25 30 35 40 45 50 55 60

Time from Fire Start (minutes)

M a x

i m u m

P r e s s u r e

t o A v o

i d F a i

l u r e

( % o

f M A W P )

1/8 Inch Thick 1/4 Inch Thick 1/2 Inch Thick 1 Inch Thick

Figure A6 – 18-8 grade stainless steel (304, 304L) rupture stress versus time to rupture(bibliographical reference [1], Page 20)


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Table A2 - High temperature tensile properties for 18-8 stainless steel (1)

Temperature,°F

Temperature,°C

TensileStrength, psi

TensileStrength, MPa

Yield Stress0,2% Set, psi

Yield Stress0,2% Set, MPa

1 000 538 53 000 365 14 000 971 100 593 48 500 334 12 000 831 200 649 43 000 296 11 000 761 300 704 35 000 241 11 000 761 400 760 27 000 186 10 500 721 500 816 20 500 141 10 000 69

1 600 871 17 650 122 --- ---1 800 982 9 600 66 --- ---

2 000 1 093 4 900 34 --- ---

(1) Applies to 304 and 304L stainless steels.Reference: bibliographical reference [1], Page 140.

Figure A7 – 18-8 stainless steel (304; 304L) tensile strength and yield stress versus temperature(bibliographical reference [1], Page 140)

0

10000

20000

30000

40000

50000

60000

1000 1100 1200 1300 1400

Degrees F

S t r e n g

t h o r

S t r e s s

P S I

Tensile Strength Yield Stress


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Figure A8 – 18-8 stainless steel (304; 304L) internal pressure versus pool fi re exposure time tominimize potential for vessel rupture

0%

10%

20%

30%

40%

gp 44-25 guidance on practice for depressurisation

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