GP 44-70

Document No.
GP 44-70
Applicability IMSL
Date 28 September 2007
Guidance on Practice for

Overpressure Protection Systems
GP 44-70
INEOS Manufacturing Scotland Limited

ENGINEERING TECHNICAL PRACTICES
28 September 2007 GP 44-70
Guidance on Practice for Overpressure Protection Systems
Foreword
This is the first issue of Engineering Technical Practice (ETP) IMSL GP 44-70. This Guidance on
Practice (GP) is based on parts of heritage documents as follows:
IMSL RPSE
RP 44-1 Overpressure Protection Systems.
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Table of Contents
Page
Foreword............................................................................................................................................2
Introduction.........................................................................................................................................5
1. Scope........................................................................................................................................6
2. Normative references................................................................................................................6
3. Terms and definitions................................................................................................................8
3.1. General..........................................................................................................................8
3.2. Terms.............................................................................................................................9
3.3. Definitions......................................................................................................................9
4. Symbols and abbreviations.......................................................................................................9
5. Overall philosophy...................................................................................................................10
5.1. General........................................................................................................................10
5.2. Reference to other codes.............................................................................................11
6. Documentation........................................................................................................................12
6.1. General........................................................................................................................12
6.2. Select stage – Early design of relief and overpressure protection systems................12
6.3. Define stage – Comprehensive relief and overpressure design basis.........................13
6.4. Execute Stage – Relief and overpressure system detailed development....................14
7. Design practice.......................................................................................................................20
7.1. General........................................................................................................................20
7.2. Relief limitation by design............................................................................................25
7.3. Pressure-limiting safety instrumented systems...........................................................26
7.4. Safety instrumented systems and reliability analysis...................................................29
7.5. Implication of changes in design conditions................................................................30
7.6. Emergency depressuring.............................................................................................30
7.7. Vacuum relief...............................................................................................................31
7.8. Cold service.................................................................................................................31
7.9. External fire condition..................................................................................................31
7.10. Thermal relief...............................................................................................................32
8. Relief design guidelines for let-down stations.........................................................................34
8.1. Definitions....................................................................................................................34
8.2. Let-down station relief design considerations..............................................................34
9. Design procedure for protection of equipment, tankage, and piping......................................38
9.1. General........................................................................................................................38
9.2. Shell-and-tube heat exchangers..................................................................................40
9.3. Air-cooled heat exchangers.........................................................................................43
9.4. Double pipe heat exchangers......................................................................................43
9.5. Plate-and-frame heat exchangers................................................................................44
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9.6. Centrifugal pumps........................................................................................................44

9.7. Positive displacement pumps......................................................................................45
9.8. Steam turbine drivers...................................................................................................46
9.9. Furnaces......................................................................................................................47
9.10. Boilers..........................................................................................................................47
9.11. Compressors................................................................................................................47
9.12. Main transmission pipelines and associated equipment..............................................48
9.13. Process and utility piping.............................................................................................50
9.14. Atmospheric/low pressure storage tanks.....................................................................50
9.15. LPG/LNG storage........................................................................................................51
9.16. Cascade effects...........................................................................................................52
10. Pressure relief devices............................................................................................................52
10.1. General........................................................................................................................52
10.2. Pressure relief valves...................................................................................................53
10.3. Rupture disks (bursting discs)......................................................................................59
10.4. Rupture pin relief valves..............................................................................................62
10.5. Sizing of pressure relief devices..................................................................................63
10.6. Installation of pressure relief devices...........................................................................64
11. Responsibilities of owner/operator..........................................................................................69
Annex A (Informative) Regional annex on local regulation..............................................................71
Annex B-1 (Normative) Operator intervention decision tree for liquid relief to closed system with
adequate liquid retention or for non-hazardous liquids...........................................................72
Annex B-2 (Normative) Operator intervention decision tree for liquid relief without adequate
retention or for hazardous liquids............................................................................................73
Bibliography......................................................................................................................................74
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Introduction
This Guidance on Practice (GP) provides guidance on overpressure protection systems that are within
its stated scope and is for use in determining the need for and design of specific overpressure
protection systems.
This GP refers to National and International Standards that are widely accepted. Codes and Standards
of the country in which the equipment is manufactured and/or operated should be considered and may
be accepted if they can be used to achieve equivalent safe and technical results to this GP. In any case,
statutory and local regulations must be complied with.
The value of this GP to its users is significantly enhanced by their regular participation in its
improvement and updating. For this reason, users are urged to inform IMSL of their experiences in all
aspects of its application.
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1. Scope
a. This GP provides guidance for the protection of pressured systems, up to the relief device
discharge flange, against overpressure to insure that plant equipment, facilities, and
pipelines comply with applicable codes, standards, and contract documents. This GP
provides a level of safety acceptable to IMSL in the design and operation of the following:
1. Processing plants, including refineries, gas installations, and chemical plants.
2. Steam generating plant and ancillary equipment.
3. Terminals, including jetty and loading facilities.
4. Petroleum production facilities, including well pads, crude oil & gas gathering
centres.
5. Main transmission pipelines, and associated equipment (as defined in clause 9.12.).
6. Storage installations.
7. Vacuum systems and systems relieving at a pressure less than 1 bar (ga) (14,5 psig).
b. It includes IMSL general requirements on the use of pressure-limiting instrumentation.
These are based broadly on:
1. Continuation of the use of pressure relief devices, wherever practicable, as the main
method of overpressure protection.
2. The use of pressure-limiting instrumentation (also known as safety instrumented
systems) as an initial method of overpressure protection in most cases, and as the sole
method in a limited number of cases.
c. It does not apply to pressure relief for systems in ships or road/rail tanks unless the system
is a special purpose-built facility that would normally be considered a processing plant.
d. This GP is applicable to new installations and to changes in overpressure protection
systems required as a result of changes in design conditions or modifications in existing
installations. The extent to which any part of the GP is applied retrospectively to an
existing system shall be subject to IMSL approval.
2. Normative references
The following normative documents contain requirements that, through reference in this text,
constitute requirements of this technical practice. For dated references, subsequent amendments to, or
revisions of, any of these publications do not apply. However, parties to agreements based on this
technical practice are encouraged to investigate the possibility of applying the most recent editions of
the normative documents indicated below. For undated references, the latest edition of the normative
document referred to applies.
The user should note there is some disagreement between the codes and standards listed in this
section. The user shall comply with the specific codes and standards applicable to the local facility and
specific equipment.
IMSL
GP 24-10 Guidance on Practice for Fire Protection – Onshore.
GP 30-75 Guidance on Practice for SIS - Management of the SIS Lifecycle.
GP 30-76 Guidance on Practice for Safety Instrumented Systems (SIS) –
Development of the Process Requirements Specification.
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GP 30-80 Guidance on Practice for SIS - Implementation of Process Requirements.

GP 30-81 Guidance on Practice for SIS - Operations and Maintenance.
GP 32-47 Guidance on Practice for In Service Inspection and Testing of
Mechanical Protective Devices.
GIS 34-301 General Purpose Steam Turbines (API 611).
GIS 34-302 Special Purpose Steam Turbines (ISO 10437).
GP 42-10 Guidance on Practice for Metallic Piping Systems ASME B31.3.
GP 43-01 Guidance on Practice for Principles of Onshore Pipeline Design.
GP 44-10 Guidance on Practice for Plant Layout.
GP 44-25 Guidance on Practice for Depressurization.
GP 44-80 Guidance on Practice for Relief Disposal Systems.
GP 46-01 Guidance on Practice for New Pressure Vessels.
GP 58-10 Guidance on Practice for Design of Welded Steel Tanks for Oil Storage
to API 650.
GP 76-01 Guidance on Practice for HSSE in Design and Loss Prevention.
GP 81-41 Guidance on Practice for Overpressure Protection, Flare and Vent
Systems for LNG Facilities.
American National Standards Institute/American Society of Mechanical Engineers

(ANSI/ASME)
ANSI/ASME B16.5 Pipe Flanges and Flanged Fittings NPS ½ through NPS 24 Metric/Inch
Standard.
ANSI/ASME B31.1 Power Piping.
ANSI/ASME B31.3 Process Piping.
ANSI/ASME B31.4 Pipeline Transportation Systems for Liquid Hydrocarbons and Other
Liquids.
ANSI/ASME B31.8 Gas Transportation and Distribution Piping Systems.
ASME Section I Power Boilers.
ASME Section VIII Pressure Vessels – Division 1 including Appendix M.
ASME Section VIII Alternative Rules – Division 2.
American Petroleum Institute (API)

API RP 520 Recommended Practice for Sizing, Selection, and Installation of
Pressure-Relieving Devices in Refineries.
API RP 521 Recommended Practice for Pressure-Relieving and Depressuring
Systems.
API STD 526 Flanged Steel Pressure Relief Valves.
API STD 2000 Venting Atmospheric and Low-Pressure Storage Tanks.
API STD 2510 Design and Construction of LPG Installations.
British Standards Institute (BSI)

BS 2915 Bursting discs and bursting disc devices.
BS 6759: 1-3 Safety valves
Part 1: Specification for safety valves for steam and hot water.
Part 2: Specification for safety valves for compressed air or inert gasses.
Part 3: Specification for safety valves for process fluids.
BS EN 14161 Petroleum and natural gas industries – Pipeline transportation systems.
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CP 2010-2 Code of practice for pipelines – Design and construction of steel

pipelines in land.
International Electrotechnical Commission (IEC)

IEC 61508 Functional safety of electrical/electronic/programmable electronic safety-
related systems.
Institute of Petroleum (IP)

Model Code of Safe Practice
IP Part 6 Petroleum Pipelines Safety Code.
IP Part 9 Vol 1 – LPG.
International Organisation for Standardisation (ISO)

ISO 4126 Safety devices for protection against excessive pressure –
Part 1: Safety valves.
Part 2: Bursting disc safety devices.
Part 4: Pilot operated safety devices.
Part 5: Controlled safety pressure relief systems.
Part 6: Application, selection and installation of bursting disc safety
devices.
Part 7: Common data.
ISO 23251 Petroleum, petrochemical and natural gas industries – Pressure-relieving
and depressuring systems.
National Fire Protection Association (NFPA)

NFPA 59A Production, Storage, and Handling of Liquefied Natural Gas (LNG).
3. Terms and definitions
3.1. General
a. In this GP the term ‘approve’ or ‘approved’, as applied to IMSL , is used if IMSL does not
wish a design to proceed unless certain features have been agreed in writing with a
contractor or supplier. This does not imply that all details of a document have been
considered by IMSL and does not affect design responsibilities of the contractor or
supplier
b. Throughout this document, the words ‘will’, ‘may’, ‘should’, ‘shall’ and ‘must’, when used
in the context of actions by IMSL or others, have specific meanings. For purposes of this
GP, the following terms and definitions apply:
3.2. Terms
Will
used normally in connection with an action by IMSL , rather than by a contractor or supplier.
May
used if alternatives are equally acceptable.
Should
used if a provision is preferred.
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Shall
used if a provision is mandatory by IMSL .
Must
used only if a provision is a statutory requirement.
3.3. Definitions
The technical terms used in this GP have the meanings defined in API RP 521 or ISO 23251. The
following additional technical definitions also apply:
Disposal system
The purpose of a disposal system is to conduct the relieved fluid to a location where it can be safely
discharged. It may terminate in an atmospheric vent, combustion device such as a flare, or other
specialized treating equipment.
Heat-off
Stopping the heat input to a plant or section of a plant with either manual or automatic initiation.
Let-down station
A flow restriction where the upstream operating pressure is greater than the downstream design
pressure. It normally consists of an arrangement of valves and/or orifice plates.
Pressure-limiting instrumentation
Instrument systems that act to minimise the size or frequency of relief loads by automatically adjusting
process conditions when they tend towards a relief situation. One example of this is a safety
instrumented system (SIS) as described in clauses 7.3 and 7.4.
Reliability analysis
A mathematical technique for assessing in probabilistic terms the performance of a component, system
or plant.
Relief device
Any device (mechanical or instrumentation) that acts automatically and reliably to relieve material on
pressure rise. It normally refers to pressure relief valves and bursting discs; but explosion hatches,
water seals, buckling pin devices, and pressure/vacuum breather valves are among the devices that
meet this requirement.
4. Symbols and abbreviations
For the purpose of this GP, the following symbols and abbreviations apply:
DN Nominal Diameter
HAZOP Hazard and Operability Study
HIPPS High Integrity Pressure Protection Systems
HIPS High Integrity Protection Systems
LNG Liquefied natural gas
LOPA Layer of Protection Analysis
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LPG Liquefied petroleum gas
NGL Natural gas liquids
NPS Nominal pipe size
MOC Management of Change
P&ID Process & Instrument Diagram
PFD Probability of Failure on Demand
PHA Process Hazard Analysis
SIL Safety integrity level
SIS Safety instrumented system
TÜV Technischen Uberwachungsvereine (Technical Inspection Organizations)
UK United Kingdom
US United States of America
5. Overall philosophy
5.1. General
a. This document defines IMSL ’s guideline for overpressure protection systems and
identifies related resources. This document’s objective is to assist in development of an
overpressure protection design that is safe, reliable, and cost effective. It is the obligation
of all parties to ensure the overpressure/relief system design accomplishes these goals.
b. As noted in API RP 521 and ISO 23251, this GP in particular shall be used in conjunction
with sound engineering judgement.
5.2. Reference to other codes

a. Nothing in this document is meant to replace or preclude application of relevant local
codes or national standards. Design of overpressure protection, flare, and vent systems
shall comply with the requirements of the applicable country and the requirements of this
GP, including supporting referenced codes, standards, and documents.
b. This GP shall be used in conjunction with ISO 23251, ISO 4126, API RP 520 Part I, API
RP 520 Part II and API RP 521, interpreting and supplementing them as necessary to
provide IMSL requirements.
6. Documentation
6.1. General
a. For new and modified plant, the following documentation requirements shall apply.
Existing plant shall have their documentation upgraded to the level described in the
following clauses of this GP as soon as practicable.
b. Documentation for overpressure and relief systems shall be created in three sections or
phases. Each phase is further clarified in the following clauses.
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1. Early design concept (select project stage) with information submitted for IMSL
approval.
2. Complete relief and overpressure design basis (design and execute project stages)
with supporting calculations and system details.
3. A comprehensive relief and overpressure system summary for incorporation into the
plant operating procedures (during the project execute stage for use in the operate
stage) and to develop a permanent Relief and Overpressure database summary.
6.2. Select stage – Early design of relief and overpressure protection systems
a. At an early project stage, relief requirements shall be studied in sufficient depth to
establish the basic design philosophy. This shall then be considered in relation to proposed
siting constraints and relevant statutory requirements.
1. For new or significantly modified plant and process, an outline design philosophy and
pertinent data on which the design has been based shall be provided.
2. The preliminary design of an overpressure protection system shall be completed as
early as possible and should be reviewed independently in detail by IMSL .
3. The subsequent preliminary design for overpressure protection shall then be
developed, agreed, and finalised following discussion with IMSL .
b. The basic overpressure and relief protection philosophy should be fully developed before
the design specification stage of the Project Health, Safety, and Environmental Review
(PHSER). The preliminary design basis for any overpressure protection system shall be
submitted to IMSL with the following minimum information:
1. Conceptual design philosophy. (clause 6.4.2).
2. Codes and standards (both internal IMSL and external) being used for design.
3. A philosophy on safety instrumented systems and an outline of the SIS system
proposed with a supporting provisional integrity assessment (SIL). (clause 6.4.11).
4. Process flow diagrams or flowsheets showing relief devices and anticipated system
operating pressures (clause 6.4.3).
5. Rough sizing and type of disposal system.
c. IMSL may, at its discretion, call for additional back-up information such as calculations
and other details. Final versions of the above information shall be included in the relief and
overpressure protection design basis and shall be subject to IMSL approval.
6.3. Define stage – Comprehensive relief and overpressure design basis

a. After review and approval of the relief and overpressure conceptual design, a
comprehensive relief and overpressure design record shall be prepared which shall fully
document, but not be limited to, the information detailed in clauses 6.4.2 through 6.4.12.
This full description of the relief design philosophy shall be written as part of the project
technical documentation and should substantially be made available before HAZOP
reviews and before P&IDs are classified as “Approved for Design”.
b. ISO 23251, API RP 521, ISO 4126, and this GP shall be referenced before starting an
overall consideration of any relief system. The causes of overpressure to be considered
shall include, but not necessarily be limited to those listed in API RP 521/ISO 23251.
c. An examination of all modes of operations and engineering intentions shall be applied to:
1. Maintain mechanical integrity of the equipment and piping systems based on credible
incidents.
2. Protect personnel.
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3. Minimize losses during pressure upset.

d. Provisions shall be made to contain or safely relieve excess pressure in the system.
1. Anticipated emergency conditions leading to possible overpressure shall be taken into
account during design. The potential for overpressure may result from failure(s) of
equipment, instrumentation, fire, thermal expansion, operator error, and/or procedural
violations.
2. The full range of operating scenarios, from purging, through pre-start-up and start-up
procedures, to shutdown, gas freeing and restart conditions shall be considered.
e. The operating cases that have been considered shall be listed in detail and submitted to
IMSL for approval before proceeding with detailed design of the relief system. The outline
operating procedures should be considered in preparing the basis for this list of anticipated
emergency conditions.
f. If an item is not applicable, a clear statement as to why it is not applicable shall be
included in the information under clause 6.4.2. Process systems having an impact on the
relief and overpressure system design shall be included in the relief and overpressure
system design basis.
g. Documentation shall demonstrate that equipment (vessels, piping, pumps, compressors,
dryers, tanks, silos, etc.) has adequate overpressure protection or cannot be overpressured
beyond its allowable pressure.
h. The relief and overpressure design basis shall be formatted in such a way that necessary
operating details can subsequently be incorporated and kept up to date in both the plant
operating manuals and in the following relief and overpressure summary. Relief and
overpressure design documentation shall be provided in an electronic format unless
otherwise specified by IMSL .
i. Upon project completion, the relief and overpressure design basis shall be updated as
necessary to make this comprehensive relief design basis current with final project design
details. Any future plant modification (MOC) procedure shall include either updating or
supplementing this documentation to maintain a comprehensive, up-to-date record of the
relief system design basis.
6.4. Execute Stage – Relief and overpressure system detailed development
6.4.1. Relief and overpressure summary document

a. In addition to the detailed design basis noted above and subsequently described in the
following sections, a concise spreadsheet, database, or other electronic form shall be
provided which summarizes critical relief system components and details. This Relief and
Overpressure summary has several distinct purposes:
1. To assist Operations in the preparation of plant operating procedures, including
potential incorporation of the Relief and Overpressure summary directly into these
procedures.
2. To assist in development of the Register of Safety Critical Equipment required for all
operating facilities. See clauses 11.1.g and 11.1.h for further information on the
Register of SCE.
3. To support establishment of a risk based maintenance and inspection program as
described in GP 32-47.
4. As a valuable summary by itself for critical process or plant parameters, equipment,
instrumentation, and other process elements that impact relief and overpressure
conditions in the plant.
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b. A summary of relevant plant and process variables affecting overpressure and relief design
shall be distilled from clauses 6.4.2 through 6.4.11 and incorporated into an electronic
summary including, but not limited to:
1. Control valve trim size.
2. Valve Cv characteristics.
3. Pump impeller size.
4. Fluid suction pressure.
5. Fluid specific gravity.
6. Operating fluid levels.
7. Applicable scenarios including the relief load for each credible scenario.
8. Relief valve sizes.
9. Equipment or systems protected.
10. Summary of other relevant data impacting relief system design or capacity.
This Relief and Overpressure summary shall be produced and kept current by each facility
as part of their MOC process.
6.4.2. Design philosophy

This section contains an outline summary of the philosophy adopted in the process design that
shall address in particular (but not be limited to) the following:
a. Types of utility failures considered, i.e. total, unit, partial, etc.
b. Whether multiple failure cases have been considered and if so, where and why.
c. Accommodation of fire relief from vessels, shell and tube exchangers, and condensers,
especially if individual relief valves have not been provided.
d. Instances in which credit has been taken for operator intervention.
e. Maximum fire areas considered and how they relate to the design of the surface and fire
water drainage systems.
f. Philosophy for sparing relief valves. (clause 10.6.3.5)
g. Basis for sizing discharge lines, i.e. the maximum back pressure and velocity that have
been considered.
h. Values of pipe roughness used to size lines.
i. The assumed position of bypass valves when control valves fail open.
j. Unit capacities, feedstock, and severity on which the design is based.
k. In developing the relief and overpressure philosophy, due consideration shall also be given
to potential vacuum conditions that can be created in process equipment.
6.4.3. List of relieving devices, data sheets, and associated block valves
a. A complete set of final process specifications (data sheets only) listing relief valves and
rupture disks (i.e., bursting disks) shall be provided. In addition, the list shall include
thermal relief valves, rupture/buckling pins, conservation vents, vacuum relief valves, and
other mechanical devices used for both overpressure and underpressure protection. The
relief device list shall include the following information:
1. Tag No.
2. Manufacturer.
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3. Type of relief device and model number.

4. Location.
5. Set Pressure.
6. Size.
7. Manufacturer’s Capacity Factor.
8. List of Equipment, vessel(s), or system(s) being protected.
b. This section shall also contain a set of IFD (issued for design) unit flowsheets or P&IDs
marked up to designate and show all Chain locked, Car-sealed or Locked open (LO) and
Locked closed (LC) manual block valves that must be locked open or locked closed during
normal unit operation to safeguard the integrity of the relief system as designed.
c. A tabulation, spreadsheet, or list of locked open (LO) or locked closed (LC) block valves
in a relief or overpressure system path or process shall also be provided to ensure these are
implemented during construction and to assist in development of field operating
procedures.
d. Administrative controls are required to ensure an open relief path and/or to prevent the
occurrence of an overpressure situation within the unit.
6.4.4. Relief loads

a. This section shall contain a tabulation of the relief loads generated for identified causes of
overpressure, clearly indicating the case that governs sizing of the relief device. For each
device, relief load calculations shall be made for credible overpressure scenarios with the
following data provided in the calculation file:
1. Tag No.
2. Discharge location.
3. Relief loads for every credible overpressure case shall be included in the relief device
sizing basis.
a) Each relief case shall note the maximum allowable vapour and liquid flow rates,
multiple fluid phase sizing cases, and may also include data for additional cases
if deemed appropriate (e.g. a high temperature relief case).
b) Fluid characteristics such as molecular weight, specific gravity, fluid
temperatures and any other fluid properties relevant to the relief case being
reviewed and the relief device capacity shall also be included as part of the data
in this section.
b. The conditions under which each relief load occurs shall be clearly defined. Thus, when
recording power failure it should be stated whether this is facility wide, local (i.e. one unit
or group of units), partial (affecting part of the supply distribution within a unit or group of
units, e.g. motor control centre (MCC)) or individual (single item of equipment).
c. When evaluating gas breakthrough conditions, the relief load summary should state:
1. The source of overpressure, including the control valve tag number.
2. Whether the control valve bypass has been assumed open or closed.
3. The assumed liquid level in the low pressure vessel if this has impact on the relief
case.
d. If a relief valve is provided to protect more than one item of equipment, the equipment
protected shall be clearly indicated.
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6.4.5. Fire areas, fire loads and fire-resistant insulation

a. This section shall contain a list of the fire areas that have been considered in arriving at
relief fire loads, indicating which relief valves are considered as relieving simultaneously.
If there is a fire relief case to be considered, a separate breakdown shall be included
showing the loads generated within each of the equipment items being protected. The
tabulation shall include:
1. Fire area considered.
2. Equipment item.
3. Vessel liquid level.
4. Tag No. of relief valve through which load is discharged (May not be located on
equipment).
5. Fire load (flow, molecular weight, temperature).
6. Total load for area (flow, molecular weight, temperature).
7. Environmental factors, thermal conductivity, thickness of insulation where
fireproofing credit is taken.
b. The section shall include a plot plan of the unit marked up to show the fire areas
considered.
c. This section shall also contain a vessel and equipment list that utilizes fire-resistant
insulation to reduce the relief design capacity and limit the fire relief load.
1. Credit may only be taken for insulation designed to meet the requirements of
API 521/ISO 23251 (See clause 7.9.d).
2. The description should include the insulation type, thickness, and thermal
conductivity, together with details of the cladding and fixing methods.
6.4.6. Principal (or maximum) flare loads

a. This section shall contain a breakdown of the flare load for each of the major utility failure
cases and the worst fire case. This shall include relief loads from other units not under
consideration that may be relieving at the same time due to a common event.
b. If relief valve discharges from the unit or units can be directed to more than one flare
according to the flare sparing philosophy, then loads for each flare shall be included.
6.4.7. Pipeline equivalent lengths and header pressure profiles

a. This section shall contain a tabulation of the piping equivalent lengths used for the purpose
of estimating relief device inlet line pressure losses and back pressures.
1. Also included for each line and header is a breakdown of the number and type of
fittings providing the basis for the equivalent length.
2. This data shall be the final as-built design and shall reference the number of the
piping isometric or general arrangement drawing for the line.
b. If credit is taken for the pressure drop in interconnecting pipework to reduce the flow in a
gas breakthrough situation or another pressure relief scenario, then the pipe lengths,
diameters, and fittings shall be fully described and documented in the relief and
overpressure design basis. These sections of pipe shall also be flagged in the Register of
Safety Critical Equipment to ensure future piping modifications affecting this pipe are
carefully reviewed.
c. This section shall also contain a series of layout drawings showing the flare and back
pressure at junctions and key points in the relief system pipe network for each of the major
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utility failure and fire cases. Electronic files should be provided to IMSL in either Visual
Flare or FlareNet.
6.4.8. Control valve and restriction orifice data

a. This section shall contain process data sheets for control valves and restriction orifices that
limit relief loads.
1. The sheet shall specify manufacturer, type, size, and rated conditions (including CV)
at normal and fully open positions.
2. A brief process sketch shall also be included, showing the location of the valve or
orifice plate.
b. This section of the design basis shall also document HP/LP (high pressure to low pressure)
specification breaks in the process; including pertinent data such as the size, type, and fully
open flow coefficient of the limiting valves or orifices in every route between the high and
low pressure systems.
6.4.9. Pump impeller data

This section shall contain a list of pumps with their shut-in heads and the corresponding
impeller sizes as used in the relief design. It shall include:
a. Manufacturer.
b. Type designation.
c. Equipment Tag Number.
d. Shut-in head.
e. Fluid density.
f. Impeller diameter.
6.4.10. Other equipment data

The design basis for other equipment such as compressors, heat exchangers, flare and vent
systems, etc. shall be specifically identified and quantified in the detailed relief and
overpressure design basis.
6.4.11. Safety instrumented systems (SIS)

This section shall contain details of safety-instrumented systems with a designated SIL 1 or
higher integrity requirement that has been provided to limit overpressure as an alternative to a
relieving device. Information should be provided for each system including a schematic and a
list of each instrument component showing the instrument type, manufacturer, testing
frequency, and a reference to the analysis or report defining the system’s reliability.
(clause 7.4).
6.4.12. Process control loop segregation

a. If a distributed control system, PLC, or similar electronic process control system is
installed, either a tabulated list or annotated diagrams shall be provided indicating the way
in which the distributed control system components are segregated to avoid common cause
instrument failures and reduce the potential relief loads that could arise from failure of the
distributed control system.
1. For any system with more than one output, an analysis shall be carried out to
determine all reasonably foreseeable failure modes or common cause component
failures that may result in more than one output going to the non-fail safe state and
potentially producing unacceptable process relief loads. See also IEC 61508 for
control system electrical supply reliability.
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2. The relief loads that could arise from these failures shall be determined. If relief loads
exceed design capability, it may be possible to re-assign system outputs to reduce the
relief load.
3. In all cases a table (clause 6.4.4) shall be provided showing relief loads associated
with the system outputs linked to the common cause failure being considered.
b. All items should be included, whether or not their failure can result in overpressure.
6.4.13. Test reports

Test dates and reports for pressure relief valves, rupture disks, and pressure-containing safety
instrumented systems at SIL 1 and higher integrity shall be recorded, and be readily accessible
for inspection.
7. Design practice
7.1. General
a. A mechanical relieving device(s) or open vent should protect equipment subject to
overpressure. An instrumented HIPS may also be used for overpressure protection, subject
to clause 9.1b.
b. Relief devices or overpressure protection are set at the design pressure of the weakest
component in the system being protected. However, under some conditions the relief
device(s) are set at lower pressures than the process components and local codes may
permit setting multiple relief devices above the design pressure. (See clause 10.1)
c. Adequate consideration of the process relief and overpressure scenarios is a critically
important step and shall be developed during the design of relief and overpressure
protective systems; protection cannot be designed for an overpressure hazard that is not
clearly identified.
d. The following list identifies failures capable of creating potential overpressure. This list is
intended to identify some over-pressure scenarios, but it is not all-inclusive. This list shall
not preclude a detailed review of all other over-pressure possibilities. In all cases, potential
failures shall be carefully examined using a structured, documented process such as a PHA
or equivalent.
1. Power failure.
a) The power distribution system shall be analysed to determine which component
parts of the system could fail without loss of the whole system. These sub-
system failures should then be analysed for their relief implications.
b) Complete power system failure within a unit and the entire facility shall also be
evaluated.
2. Cooling or reflux system failures.
Partial cooling water failure shall not be assumed unless it can be shown that all
cooling water exchangers continue to receive water when part of the cooling water
pumping capacity is lost.
3. Steam failure.
4. Instrument air failure.
5. External fire or pool fire.
6. Individual valve failure, open or closed.
7. Inadvertent valve operation, control valve failure or valve opening from a higher
pressure source.
Page 17 of 54
8. Failure of automatic controls.

a) The possible failure of instrument systems shall be taken into consideration,
including safety-instrumented systems.
b) Modern instrument systems may rely on distributed shared loop systems;
therefore the possibility of simultaneous failure of more than one control loop
shall be considered.
c) This evaluation shall also include the capability of a distributed control system
to introduce ways for otherwise unrelated control systems to be driven
simultaneously to a dangerous position. (clause 6.4.12)
9. Gas breakthrough.
Gas breakthrough shall be specifically addressed as a relief case. (clause 8.2.2)
10. Blocked or closed outlet(s).
11. Equipment failure (including pump, air cooler fan, or compressor trips and
shutdowns).
12. Heat exchanger internal failure (e.g., tube failure or hole in plate of plate exchanger).
13. Reverse flow (such as check valve(s) failure or backflow).
14. Individual item failure in control system.
15. Partial utility failure and/or interaction between utilities.
16. Runaway chemical or thermal reaction.
17. Accidental mixing.
18. Changes in feedstock or other process condition changes.
19. Properties of process fluids under relief conditions. For example, blockages may
occur due to freezing or hydrate formation.
20. Thermal expansion.
21. Hydraulic expansion.
22. The effect of a very large capacity source such as a wellhead or long pipeline.
23. Pressure surge or pressure transients.
24. Internal explosion.
e. The relief rates, together with the relieving temperature and composition, shall be
calculated by performing heat and mass balance calculations for the conditions applying in
the relieving condition. This should include such factors as:
1. Reflux drum emptying or flooding.
2. Dry-out of column sections causing loss of circulating reflux.
3. Change of duty in air coolers or exchangers due to different temperature differentials.
4. Change in latent heat and temperature due to increased pressure.
The methods of calculation shall be submitted to IMSL for approval at an early stage of
design.
f. If catalyst or a chain termination agent is added to either batch or continuous reactor
systems, specific non-normal condition shall be considered in designing the overpressure
protection system. This shall include, but not be limited to:
1. Too much reactant, wrong composition.
2. Too much catalyst and/or promoter.
Page 18 of 54
3. Overfilling, insufficient ullage for expansion.

4. Loss of agitation.
5. Loss of cooling.
6. Failure to terminate the reaction.
7. Loss of control.
g. For internal explosion or runaway chemical reactions, special requirements for emergency
depressuring, for halting reactions, or otherwise preventing/controlling these situations
shall be subject to IMSL approval (see GP 30-76).
h. The probability of two or more entirely unrelated failures occurring at the same time need
not normally be considered in design, unless the consequences are particularly serious.
1. In such cases the hazards shall be quantified.
2. Proposed design measures for limiting the hazard shall be subject to approval by
IMSL .
3. ISO 23251 and API RP 521 provide additional guidance that shall be followed on
coincident failure situations.
i. Although not preferred, under certain conditions, credit can be taken for an operator
responding and taking the necessary action to prevent equipment within battery limits
being overpressured.
1. Operator intervention may be considered if the onset to overpressure is sufficiently
long enough (10-30 minutes) that operators can respond effectively in mitigating the
event and if the scenario does not cause the release of flammable, toxic or otherwise
hazardous liquid directly to atmosphere. See Annex B1 & B2.
2. Further, adequate alarms and other warnings need to be available to alert operators to
take action. If the consequence of this approach is the overpressuring of a vessel with
liquid and it is difficult to provide liquid relief, a hazard quantification procedure may
justify not sizing for a liquid overfill situation. Omission of liquid relief in such cases
shall be subject to IMSL approval.
j. Since vessel design takes into account both temperature and pressure, the possibility that
departures from the normally expected operating temperature range may occur during
emergencies shall be recognised. Overheating due to process control failure, exothermic
reaction or fire, and auto-refrigeration from the presence of light hydrocarbons are typical
examples. These may require provision of heat tracing for freeze protection, temperature-
limiting or emergency depressurising systems, the design of which shall be to GP 44-25
and GP 30-76.
k. Calculation of the quantity and properties of any vapour, liquid, or multiphase fluid to be
discharged under relief conditions shall be determined on the basis of knowledge of the
complete operating system, including process conditions, instrumentation, and utilities
systems. Reference should be made to ISO 23251 and API RP 521 for guidance on general
principles, but calculation shall be specific to the system under consideration.
7.2. Relief limitation by design

Basic design measures shall be considered to minimise the magnitude and frequency of relief.
7.3. Pressure-limiting safety instrumented systems

a. HIPS or HIPPS may be an approach to over pressure protection utilizing an instrumented
system compared to conventional protection methods utilizing mechanical devices such as
relief valves. See clause 9.1.b.
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b. To meet the reliability necessary for pressure protection, the HIPPS arrangement must
meet the required SIL. GP 30-75, GP 30-76, GP 30-80 and GP 30-81 shall be followed in
the application of HIPS or HIPPS. Also see ISO 23251 and API 521 for further
information on HIPPS.
c. A single process control instrument or single loop design by itself, with no redundancy or
an associated safety integrity level, in general shall not be considered to meet IMSL relief
requirements. In most cases redundant devices are required to achieve the required
performance.
d. A clear distinction shall be made in all documentation between “normal” pressure-limiting
instrumentation and safety instrumented systems providing final protection against loss of
containment. In order to take credit to mitigate an overpressure scenario, the safety
instrumented system shall be in operation during all operating modes (start-up, shutdown,
normal, etc.) when the overpressure scenario can occur.
e. This GP applies to any protective instrumentation (safety instrumented systems) that can
be considered as ‘pressure-limiting instrumentation’, i.e. acting to minimise or eliminate
the operation of pressure relief devices whether or not provided specifically for that
purpose.
f. Pressure-limiting instrumentation should be used, if practicable, subject to the need to
minimise the frequency and magnitude of spurious plant shutdowns. However, complete
relief system capacity shall be provided as the final protection for individual equipment
items if practicable (subject to 9.1.b). If not practicable, a safety-instrumented system with
suitable integrity may be used.
g. The reliability required of any safety instrumented system providing the final protection
against overpressurisation depends on the magnitude of the hazard involved and its
likelihood which is reflected in the integrity level established in accordance with
GP 30-76.
h. The set points of any pressure limiting safety instrumented system, preceded by alarms as
required, shall be below the lowest relief device set pressure in the system under
consideration, in order to be effective.
1. An increase in the vessel design pressure over that allowed by GP 46-01 may be
needed, but should not exceed guidelines in clause 10.1 or in applicable local codes
and national standards.
2. The design margin shall take account of the response of control systems and the
process dynamics.
i. The design margin should be defined to allow for:
1. The tolerance of the set pressure of the relief device under actual working conditions.
2. The setting of the trip switch or amplifier and its switching differential.
3. The setting of the pre-alarm and its switching differential.
4. The maximum working pressure under normal process conditions.
5. The time required for the safety instrumented system to fully complete its protective
function in relation to process dynamics.
j. Pressure-limiting instrumentation systems providing the final protection against
overpressurisation shall be designed to facilitate regular testing and strict control over
bypassing or deactivation, and shall be fully documented in accordance with GP 30-80.
1. Pressure-limiting and temperature-limiting instrumentation may, if appropriate,
include automatic actuation of the following:
a) Feed or pipeline transmission pump or compressor trips.
Page 20 of 54
b) Fuel shut-off valves.

c) Reboiler heating medium bypasses and shut-off devices.
d) Fired reboiler shutdown and heating medium circulating pump trips.
e) Pressure and temperature-limiting systems to protect reactors.
f) Start-up of stand-by pumps and compressors.
2. A philosophy of automatic turndown using partial heat-off may be applied to permit
time for effective operator action in order to avoid both the operation of relief
devices, and widespread shutdown.
3. It is essential that pressure-limiting instrumentation receives regular maintenance and
proof testing at defined intervals in accordance with GP 30-81.
k. The following circumstances should give rise to safety instrument systems providing the
final protection against overpressure.
1. Systems in which overpressure protection is provided solely by instrumentation,
because, for whatever reason, the equipment cannot be protected by conventional
pressure relief devices.
2. Systems having relief valves discharging to a closed system sized by taking credit for
the operation of automatic pressure limiting instrumentation.
7.4. Safety instrumented systems and reliability analysis

a. A SIL determination exercise should be carried out during preliminary design and re-
visited during detailed design either during or preferably shortly after PHA/Hazop.
b. Pressure limiting safety instrumented systems at SIL 1 or higher integrity shall be subject
to reliability analysis with actual or assumed test intervals to demonstrate that the required
integrity level, or specified probability of failure on demand, is achieved as per GP 30-80.
c. In the design of safety instrumented system, spurious operation which result in significant
consequences should be avoided.
d. Genuine demands on the system shall be documented and the testing results evaluated
periodically to ensure that specified integrity is achieved. Testing regimes should be
adjusted accordingly. See GP 30-81 for details.
7.5. Implication of changes in design conditions

a. If there is any change in the design conditions that could result in an additional case of
overpressure, calculations for the revised conditions shall be carried out and submitted for
approval by IMSL to ensure IMSL requirements for overpressure protection are fully met.
1. The relief and overpressure protection design basis shall be modified or updated
accordingly.
2. For modification to a closed relief system, refer to GP 44-80.
b. It shall be recognised that a change in a control system design or philosophy could
necessitate a corresponding change in the design of an overpressure protection system and
its supporting documentation. For example:
1. Modification to a high integrity safety instrumented system (see GP 30-76, GP 30-80
and clause 6.4.11).
2. Replacing a system of single control loop integrity by a distributed shared loop
system (clause 6.4.12).
3. Multivariable control or computer optimisation linking control loops in a manner not
envisaged in the original design (clause 6.4.12).
Page 21 of 54
4. Changing pump impeller size, control valve trim size, or the removal or repositioning
of limit stops (clause 6.4.9).
7.6. Emergency depressuring

a. Means for emergency depressuring may be necessary in certain conditions (see GP 44-25)
including:
1. Potentially uncontrollable reaction conditions in which rapid depressuring systems are
more effective than normal pressure relief devices, i.e. pressure relief valves and
rupture disks. In such cases instrumentation shall be provided to sense potentially
hazardous conditions and initiate necessary corrective action according to GP 30-80.
2. Uncontrolled temperature rises that could lead to possible equipment failure at or
below design pressure.
3. Fire conditions in which the equipment is uncooled by process liquid contact, again
leading to failure at or below design pressure.
4. Units operating at a pressure above 17 bar (ga) (250 psig) for refining or oil
production facilities. For chemical plant these limits do not necessarily apply.
b. In calculating the capacity of a depressuring system, it shall be assumed that during a fire
there is no feed to or product from a system, and that normal heat inputs have ceased.
c. The auto-refrigeration effect of depressuring shall be considered, in the case of high-
pressure gases and liquefied gases, in accordance with GP 46-01 and GP 42-10.
Calculation procedures for estimating the temperature of vessels and pipework are given in
GP 44-25, but other suitable procedures may be used subject to IMSL approval.
d. Both depressuring valve and pressure relief device protecting a common vessel should not
usually be considered to be open at the same time unless both are needed to vent the
required relief load. In cases in which either device can handle the required load then
generally the larger of the two loads is used in the disposal system design.
7.7. Vacuum relief

a. The possible need for vacuum relief on vessels and systems shall be considered. Protection
may be provided by vacuum-breaking systems, inert (non-condensable) blanketing
systems, etc. The basis of protection shall be included in the documentation required in
clause 6.5.
b. As an alternative to vacuum relief, pressured equipment may be designed for full vacuum
conditions.
7.8. Cold service

a. If auto-refrigeration or freezing of released vapours may occur, e.g. from low-temperature
storage of methane to butane hydrocarbons, fluorocarbons or other low-boiling materials,
the pressure relief device shall be constructed of materials suitable for the minimum
temperature encountered. Reference GP 44-25.
b. Any non-flammable non-toxic liquefied gas, e.g. CO2, capable of forming solid particles
on discharge, shall be vented directly to atmosphere with no piping downstream of the
pressure relief device.
c. If the discharging process fluid may result in ice formation such as to prevent the reclosing
of a valve, the valve shall be heated and insulated as necessary.
Page 22 of 54
7.9. External fire condition

a. Pressure relief devices shall be provided for the fire relief condition on vessels and
equipment that could be subjected to a sustained external fire. Calculation methods shall be
in accordance with ISO 23251 and API RP 521.
b. A closed system for the fire relief case shall be sized to handle the simultaneous discharge
from all pressure relief devices that are judged to be affected (i.e., within the specified fire
zones). This judgement shall be based on the maximum fire relief discharge rate from a
plot or fire zone that can be isolated by fire-fighting personnel and their equipment.
1. The fire zone shall be determined by reference to the plot plan, making allowance for
adjacent roads, bund (dike) walls, and drainage conditions.
2. The areas considered shall be consistent with the design of the surface water drainage
system so that it is not possible for the fire to be spread further as a result of burning
hydrocarbons being carried along on top of draining fire water.
3. When evaluating drainage credit, consideration should be given to the amount of
firewater that might be applied in the fire area (can be several hundred cubic meters
per hour or 1 000’s of gallons per minute).
c. For each fire relief area the following shall be taken as the basis for calculation:
1. No process heat input or removals.
2. Fire heat input load on all equipment.
d. For any particular plot area, where fire conditions require relief capacity in excess of that
required for any other emergency conditions, insulation or cladding of selected equipment
against fire shall be applied, if economical, to reduce the discharge rate and the size of any
closed relief system.
1. If the pressure relief device is sized on this basis, the insulation and cladding shall be
specifically designed and installed to resist the forces of fire hose streams and to
maintain its insulation properties for an extended period [904°C (1 660°F)] for
2 hours per ISO 23251 and API RP 521).
2. Details of the insulation shall be included in the relief and overpressure design basis.
(clause 6.4.5)
e. General requirements for passive fire protection by insulation and cladding shall be in
accordance with GP 24-10 (onshore).
f. No credit for firewater/fire protection system in reducing the fire heat input shall be taken
unless specifically allowed by the code (e.g., NFPA 30 for flammable/combustible storage
tanks) and approved by IMSL .
g. Requirements for shell-and-tube and air-cooled heat exchangers during external fire
conditions are covered in clauses 9.2.3 and 9.3 respectively.
7.10. Thermal relief

a. Thermal relief on piping is not normally required in short isolatable sections within battery
limits. However, liquid lines that can be blocked-in during normal operation whilst subject
to heat input from external sources such as ambient conditions, heat tracing or steam
jacketing, adjacent hot lines, or radiation from flares shall have thermal relief valves if the
increase in fluid pressure so caused will increase pressures beyond those permitted by the
relevant piping design code.
1. Expansion of the trapped fluid shall be calculated, and the pressure relief device sized
accordingly.
Page 23 of 54
2. In the case of most systems, a DN 20 x DN 25 (NPS ¾ x NPS 1) relief valve can be

used, even though it will commonly be oversized.
b. Thermal relief for equipment shall be provided if fluid can be trapped between inlet and
outlet valves, and if sufficient heat can be supplied to the fluid to increase the pressure
above the equipment design pressure. Such equipment shall include heat exchangers,
vessels and pumps.
1. This shall not apply when the valves are locked open during operation and closed
only under permit (see also clause 9.1.d).
2. If relief is to the process, the thermal relief valves shall discharge to a location that is
always capable of absorbing the relieved material. The location of other valves and
their possible positions at the time of discharge of the thermal relief valve shall be
taken into account.
c. A heat exchanger shall be provided with a pressure relief device for thermal expansion if
the cold side can be blocked-in between inlet and outlet valves with flow on the hot side.
Note however the dispensation permitted by 9.1.d.
d. The sizing of the thermal relief shall assume that:
1. The fluid is initially at the most severe operating conditions.
2. The ratio of gas, vapour, and liquid is the most arduous of the predicted design
conditions over the life of the plant for the assumed flow, pressure, and temperature.
3. Pumps and compressors on the process fluid continue to operate unless there is an
automatic shutdown initiated by the blocking-in, for example, on low flow. Relief
devices on pumps and compressors and kickback systems operate.
4. Heat input continues at the design operating rate. If temperature sensors are located so
that the blocking of the process flow gives a low temperature at the sensor, then the
maximum possible heat input should be used in sizing the thermal relief.
5. The potential for multiphase relief sizing should be considered if the fluid boils at the
relief device opening pressure.
e. Sizing of thermal relief shall be based on the maximum flow of fuel to fired heaters or of
heating medium to the other equipment. Control valves on heater fuel or heating fluids
shall be assumed to be fully open.
f. If thermal relief valves discharge into a closed system, the effects of back pressure shall be
considered on the selection of relief valve type and its set pressure.
8. Relief design guidelines for let-down stations
8.1. Definitions
8.1.1. A let-down station

a. A let-down station is a flow restriction in which the upstream operating pressure is greater
than the downstream design pressure. It normally consists of an arrangement of control
valves, valves, and/or orifice plates.
b. ‘Choke’ valves in Exploration and Production operations are Let-Down Stations.
c. Less obvious situations could include reverse flow through pumps or non-return valves,
drains to closed drain systems, heat exchanger tube failures.
Page 24 of 54
8.1.2. A high reliability trip system

HIPS are systems that are used in place of, or to reduce the size of relief systems. They have
suitable equipment and architectures to meet the required integrity level and may be of voted
multiple detectors and shut-down valves. They require a full reliability analysis and regular
testing under strict supervision. See clauses 7.3 and 7.4.
8.2. Let-down station relief design considerations
8.2.1. General
In considering process systems in which fluids pass from a high pressure to a low pressure
system, the low pressure system must be protected from overpressure. Relief devices should be
sized to take into account the fluid conditions and all undesirable circumstances in operation of
the let-down station.
8.2.2. Design for gas breakthrough

a. Relief design shall consider the case in which all valves across a high pressure (HP) to low
pressure (LP) interface are fully open and gas breakthrough occurs in liquid systems.
Bypass valves across the HP/LP interface shall also be assumed to be fully open and not
simply having an equivalent opening to normal process operation unless adequate controls
are in place. Adequate controls may require smaller bypass valves or restriction orifices (in
the case of existing plant) to be installed consistent with normal process flow requirements.
b. To calculate the amount of gas breakthrough from a high pressure system to a low pressure
system with the letdown valve fully open, the high pressure system should be assumed to
be at its normal operating pressure and temperature and with its normal molecular weight
gas.
1. These values should be modified if there is a known condition in which distinctly
different values prevail.
2. All possible operating conditions shall be considered.
3. The Cg (the valve sizing coefficient for gas) of the actual letdown valve(s) and bypass
valve(s) in their fully open position shall be determined. The manufacturer’s equation
for gas flow, or a recognized industry equivalent equation, shall utilize this Cg data to
calculate the gas flow volume between the upstream high pressure system and the
downstream lower pressure in the liquid system. Adequate downstream relief system
capacity for the potential gas volumes through the liquid valves shall be provided and
verified.
c. In addition to the gas breakthrough case, the effect of displacement of large quantities of
liquid from the high pressure system and piping into the low pressure system shall be
considered. If the low pressure system gas space is not large enough to accommodate this
liquid, then the relief valves and relief lines shall be sized to accept this liquid at a
volumetric rate equal to the gas flow across the letdown valve (gas expanded to relieving
pressure of the low pressure system).
d. If the manual bypass(es) installed around a control valve is capable of much higher flow
rates than the control valve itself, potential flow through the bypass may need to be
reduced by modifying the valve size, installing a restriction orifice, or applying
administrative controls (e.g., locked or sealed closed), dependent on capacity of the
downstream relief system. See clause 6.7.
8.2.3. Design for liquid overfill

a. In addition to the gas breakthrough case, the opening of the letdown valve from the
normal, liquid containing, operating situation could displace the high-pressure vessel liquid
inventory into the low-pressure vessel.
Page 25 of 54
1. If this occurrence could cause overfilling of the low pressure vessel, when starting
from normal operating levels, then full liquid relief capacity shall be considered from
the low pressure vessel.
2. It may be possible to reduce operating levels to prevent becoming overfilled. This can
take one of two forms:
a) Full liquid relief capacity shall be provided, together with suitable means of
disposing and holding a sufficient quantity of liquid (See GP 44-80).
b) A safety instrumented device of suitable integrity shall be provided to stop
further liquid inflow a sufficient time before the equipment space is filled.
b. Good engineering design utilizes normal process interventions to reduce demand
frequency on safety instrumented systems (SIS); however, SIS design must consider and
allow for the full range of potential process conditions including start up, restart, control
system trip recovery, or other non-routine operations.
8.2.4. Operating conditions

a. The full range of operating conditions shall be considered, from purging, through pre-start-
up and start-up procedures to shut-down, regeneration and gas freeing. If there is a range of
operating conditions, then the extreme shall be used in the calculation.
b. The calculation of gas flow in which gas breakthrough is possible shall be based on gas at
the normal operating conditions and properties, unless it is known that there are situations
(e.g. at start-up) in which more arduous conditions are possible.
8.2.5. Control valve sizing

In designing the relief system, the installed valve size shall be reflected in the relief calculations
and the basis shall be clearly defined.
a. Since the control valve trim size and the size of any orifice plate in the bypass are central
to the relief case, this data should be listed with the relief valve data as part of the relief
system and should not be changed without appropriate resizing calculations.
b. In new plant design relief valve sizing and associated piping hydraulic calculations shall be
revalidated after control valve selection even though control valve definition is often late in
the program.
8.2.6. Credit for open outlets

The HAZOP approach shall be used to specify the operating scenarios under which relief
conditions including gas breakthrough could occur. Blockage of normal outlets during gas
breakthrough shall be evaluated to determine if it is a credible scenario.
8.2.7. Credit for operator intervention

In the design of relief systems on let-down stations in either vapour or liquid relieving
situations, no credit shall be taken for operator intervention.
8.2.8. Credit for instrumentation

a. If conventional design leads to an impractical or grossly uneconomic solution, e.g. offshore
or pipelines, then a safety-instrumented system of sufficient integrity may be considered as
an alternative to providing relief. The integrity (reliability) required shall be determined
per GP 30-76.
b. Instrumentation (which is not high reliability) used for minimizing the frequency and
extent of relief valves operating shall not contribute to a reduction in the design capacity of
the relief system.
Page 26 of 54
8.2.9. Design for multiple jeopardy

Two unrelated emergency conditions should not be considered to occur simultaneously in relief
design. If the two emergency conditions have a common cause, they shall be included in the
design.
8.2.10. Bypass sizes and restrictors

The following criteria may be used to address bypasses around control valves during evaluation
of downstream equipment overpressure protection and relief system design.
a. If the upstream pressure at the time the bypass valve is opened is less than the maximum
allowable accumulated pressure (i.e., relieving pressure) in the downstream equipment,
then existing procedures may be utilized to protect against inadvertent opening of the
bypass valve. Definition of the upstream pressure shall consider not only normal process
conditions but also non-routine operations such as start-up, shutdown, etc.
b. The following cases consider that the upstream pressure exceeds the maximum allowable
accumulated pressure (i.e., relieving pressure) in downstream equipment at the time the
bypass valve is opened.
1. Case 1) If opening the bypass valve does not affect the flow rate entering the vessel,
then inadvertent opening of the bypass does not need to be considered as a separate
overpressure scenario. This case would also apply if flow through the control valve
and bypass is limited by another device (e.g., restriction orifice), another control
valve further upstream, or other equipment such as a pump. In certain cases a
transient pressure surge caused by the initial opening of the bypass valve may
overpressure downstream vessels and, hence, should be considered.
2. Case 2) This case applies to capacity limited processes in which flow through both a
control valve and its bypass are required to achieve process rates. If both the control
valve and the bypass are normally open (even partially), then the following
overpressure scenarios should be considered for overpressure protection of the
downstream equipment:
a) Normal flow through the inlet control valve and bypass with a closed outlet on
the vessel, and
b) Maximum flow through a wide open inlet control valve and wide open bypass
minus the normal flow rate entering the vessel, and
c) In cases in which a closed vessel outlet can occur in conjunction with a wide
open inlet control valve and a wide open bypass due to a credible common
failure mode, then the maximum flow through a wide open inlet control valve
and wide open bypass should be considered along with a closed outlet.
The pressure relief device should be sized for the largest of the credible scenarios.
When developing the relief load, the pressure drop through the lines at the higher
flow rates should be considered to avoid over-estimating the relief load. Options to
further reduce the relief load contribution from the bypass line include:
1) Removal of the bypass line,
2) Installation of a smaller bypass valve, or
3) Installation of a restriction orifice in the bypass line.
3. Case 3) In this case, the bypass is used primarily for maintenance of the control valve.
Further, the upstream pressure exceeds the hydrotest pressure of the equipment
downstream of the control valve when the bypass is inadvertently open.
If opening of the bypass has the potential to cause a rapid or undetected
overpressurisation of downstream equipment beyond the hydrotest pressure, then the
Page 27 of 54
downstream equipment should be equipped with a suitably sized pressure relief

device or the bypass should be removed. For example, opening a bypass across a
level control valve has the potential for rapid overpressurisation of downstream
equipment once the level in the upstream vessel is lost (i.e., results in gas blowby).
If opening the bypass causes a process upset that becomes readily apparent to
operators and there is sufficient time for operators to intervene and correct the
condition, in accordance with documented procedures; then administrative controls
(e.g., car-sealing closed or chain-locking closed the bypass valve) should be
implemented to prevent overpressurisation of downstream equipment. Note that
elimination of the bypass or installation of a suitably sized pressure relief device can
be done in lieu of these administrative controls.
4. Case 4) In this case, the bypass is used primarily for maintenance of the control valve.
Further, the upstream pressure is less than the hydrotest pressure of the equipment
downstream of the control valve at the time when the bypass is inadvertently open.
If opening of the bypass has the potential to cause a rapid or undetected
overpressurisation of downstream equipment, administrative controls (e.g., car-
sealing closed or chain-locking closed the bypass valve) should be implemented to
prevent overpressurisation of downstream equipment.
If opening the bypass causes a process upset that becomes readily apparent to
operators such that prompt action, in accordance with documented procedures, to
correct the condition is required; then existing procedures can be utilized to protect
against inadvertent opening of the bypass valve.
8.2.11. Temperature effects

Since there can be appreciable temperature effects when hydrocarbon fluids are reduced in
pressure, the significance of these temperature changes shall be considered in both relief valve
sizing and the suitability of the materials of construction.
8.2.12. Interconnecting pipework

a. Normally in design, pipework lengths and valve sizes are such that the flow is determined
by pressure drop through the valve rather than through the piping. However, this is not
necessarily so in all retrofit cases and checks should be made.
b. If credit is to be taken for the influence of piping pressure drops, the relevant data shall be
recorded in the relief and overpressure design basis. See clause 6.4.7.
9. Design procedure for protection of equipment, tankage, and piping
9.1. General
a. Pressured systems in the plant or facility shall be designed to:
1. Identify primary causes of overpressure.
2. Assess the reliability of any means provided in the system to limit this pressure.
3. Specify to the vessel designer the resulting design case pressure relief device
requirement(s).
Either pressure relief devices of the specified requirement(s) or safety instrumented
systems of sufficient integrity shall be provided.
b. For protection of individual equipment items or sections of process plant, relief devices
shall be provided, taking no credit for provision of automatic pressure-limiting
instrumentation, except in special circumstances that shall be in accordance with GP 30-76
and GP 30-80. Examples of such circumstances are:
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1. If there is no practicable location to which relief can be discharged.

2. For protection against internal explosion.
3. For protection against uncontrolled chemical reaction.
4. Highly toxic, non-flammable material.
c. The pressure relief device set pressure, or lowest set pressure in the case of multiple
devices, shall be no greater than the vessel design pressure and associated piping design
pressure, or maximum allowable working pressure if applicable. See clause .
d. If intermediate isolating valves are provided for maintenance purposes to be used only
during plant shut-down, they may be taken as locked open, subject to local codes and
approval by IMSL . If closure of the valve (due to mechanical failure or error) can result in
pressures exceeding the hydrostatic test pressure, then:
1. The block valve shall be eliminated, or
2. A pressure relief device shall be installed that would protect the equipment from
overpressure due to closure of the valve, or
3. Administrative controls (procedures and locks or car seals) and valve failure controls
(i.e., ensuring the valve would fail in an open position) and valve operation controls
shall be implemented.
e. If isolating valves are used on equipment without pressure relief protection then:
1. They shall be subject to approval by IMSL .
2. They shall be clearly identified in the relief and overpressure system design
documentation (clause 6.3) and, if appropriate, also included in the Register of Safety
Critical Equipment (clause 6.4).
3. The plant operating instructions shall state that such valves shall be closed only after
issue of a permit, under supervision.
4. If they are installed around an exchanger so that it can be isolated, then either relief
capacity should be installed or the exchanger shall be vented and drained immediately
after it has been isolated. If the option of venting and draining is adopted,
consideration should be given to erecting a warning notice stating that the exchanger
shall be vented and drained immediately after being isolated.
This paragraph does not apply to the isolation of pressure relief devices, which are covered
in clause 10.6.3.2.
f. Overpressure as a result of reverse flow from a high-pressure system shall be considered.
No credit shall be taken for the presence of a single non-return valve or steam trap in a
line.
1. Two check valves in series may be used as an acceptable means of overpressure
protection. However the installation of two check valves shall not be the sole means
for the isolation of the low and high-pressure sources. A positive means of isolation
of the line shall be installed.
2. Two dissimilar check valves in series that are periodically maintained are preferred to
improve reliability by eliminating common mode valve failures.
3. If reliability of two check valves in series cannot be tested or assured, then a reverse
flow leakage rate based on an orifice equivalent to 1% of the largest check valve
orifice diameter shall be applied. As this presumes two failures, one check valve fails
open completely and the second check valve fails open partially.
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g. If there is only a single check valve, complete failure of the check valve shall be
considered. The reverse flow rate shall be based on the full orifice diameter within the
check valve, assuming complete failure.
h. The requirement for additional isolation to prevent ongoing leakage raises some practical
issues that shall be considered for the overall level of protection to be satisfactory. A
LOPA may help understand the issues involved and sensitivities of the key assumptions. If
a detailed consideration shows that a manual isolation is not a practical option,
consideration should be given to automatic isolation or an alternative means of protection.
1. Circumstances that require additional manual isolation shall be clearly identified and
agreed with operating personnel. This additional manual isolation shall be readily
identifiable in the field and the requirement for isolation shall be clearly identified in
operating procedures.
2. The system design shall ensure that it is safe for field personnel to make required
manual isolations – the rate of pressurization of the low pressure system shall be
sufficiently slow that a dangerous level of pressure is not reached within the timescale
for effective isolation.
3. Assessment of the time-scale for isolation shall take into account the likely
circumstances of the initiating event – e.g., a total power failure – and the alarm
loading and work load on field personnel at the time. The human factors aspects of
the situation shall be considered, including the potential for the isolation step to be
omitted.
4. Any manual isolation valve that is required to supplement the check valves should be
maintained in working order.
5. Any manual isolation valve shall be accessible in all foreseeable situations – e.g., if
the cause of the reverse flow was a fire that could lead to a pump being shut down,
then the isolating valve would need to be accessible unless the consequences of any
reverse flow were judged to be far less than the initiating event.
6. Consideration of the potential consequences of failure should be made – whilst
catastrophic failure of a vessel is always a very serious event, if the consequences are
particularly severe a higher standard may be warranted.
7. Consideration should be given to the implications of assumed leakage rates on the
inspection regime of the check valves, and whether simple visual inspection is
sufficient, or whether a higher standard of testing (e.g., periodic leak testing) is
required.
8. The orientation of the check valves shall ensure that the check valves can function
reliably – manufacturer’s recommendations shall be followed.
9.2. Shell-and-tube heat exchangers
9.2.1. General
a. In exchanger systems consisting of more than one shell, both shell or tube sides
interconnected without intermediate isolating valves may be considered as single systems
for the purpose of overpressure protection design, unless severe fouling could occur. Both
shell and tube side of heat exchangers should be protected by pressure relieving devices in
accordance with requirements set forth in local codes such as ASME Code Section VIII,
European Pressure Equipment Directive (PED), PD 5500, etc.
b. Overpressure conditions to be considered shall include the possibilities set out in API
RP 521 or ISO 23251, and any other specific plant emergency condition.
1. In particular the blocked-in and burst tube conditions shall be allowed for, together
with any implications of more gradual tube leakage.
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2. These overpressure conditions shall be met by designing for pressure containment

whenever this is economical.
9.2.2. Burst tube condition

a. A complete single tube failure shall be taken for design purposes, with calculation in
accordance with API RP 521 or ISO 23251.
b. Even if the design pressure of the low pressure side is increased to meet this pressure ratio,
then a tube failure shall still be considered for possible overpressure of connected piping,
cross-contamination consequences, and possible effects downstream of the exchanger
where the tube failure occurred.
c. Provision of overpressure protection for the heat exchanger and associated pipework does
not remove the need for a Process Hazard Analysis to consider the wider process
implications of any inter-stream leakage.
d. The effects of a broken tube shall be considered with possible impact on the entire low
pressure system not just the exchanger in which the tube failed. For example, increasing
the pressure rating of the low pressure side of the heat exchanger without a similar increase
in pressure rating of the connected low pressure side piping can lead to piping failure.
e. Credit for excess material escaping via the normal process system shall only be taken if it
can be demonstrated that the low pressure process system has the capacity for the material
and there are administrative controls in place and little risk that operators would block in
the low pressure side (i.e. block in the relief path).
f. If tube failure produces the controlling relief case, the process design should be
reconsidered to check if it is economical to eliminate the relieving requirement, e.g. by
uprating the design pressure of the low-pressure side of the exchanger so that its test
pressure equals the design pressure of the high-pressure side (see API RP 521 or
ISO 23251). However, other items connected to the low-pressure side shall also be
considered for uprating if they could be overpressured by a tube failure.
g. Overpressure protection of equipment shall be provided along the low pressure side flow
path to the final destination, i.e., atmosphere or collection tank since past incidents have
shown it possible to overpressure equipment some distance from the exchanger when tube
failure occurs.
h. In assessing the behaviour of steam and cooling water systems for the burst tube and
external fire conditions, the following should be noted:
1. On steam systems, inlet non-return valves and downstream steam traps, if fitted, shall
be taken as equivalent to closed valves, i.e. the steam side is completely blocked in.
Therefore, steam system piping and components between these check valves or steam
traps and the process shall be designed for the maximum overpressure case from
either the process or utility systems.
2. On cooling water systems, although a downstream pressure escape route may
normally be open, isolating valves in it shall be regarded as closed in emergency
unless administrative controls are in place, e.g. particularly if light flammable fluid is
found to be leaking into a cooling water system. Accordingly in such cases, these
systems should normally be regarded as blocked-in and cooling water system
components between the exchanger and cooling system isolation valve(s) shall be
designed for the maximum overpressure from either the process or the cooling water
system.
i. Each case for the possible fitting of pressure relief devices for this condition should be
considered individually. For example, if the pressure differential and potential leakage is
great, such as with high-pressure gas coolers, or in any other case in which a high pressure
can rapidly build up on the low-pressure side with a tube failure during normal operation,
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then a relief device should be fitted, but if a pressure leak can be accommodated in normal
flow, a relief device should not be automatically fitted. Accordingly, pressure relief for
tube failure may be omitted provided all of the following are true, however the possible
need for thermal relief should not be overlooked in any case:
1. The low-pressure side can absorb the tube break flow without causing other problems
upstream or downstream of the tube break.
2. The volumetric flow from the tube break is less than the normal volumetric flow
through the low-pressure side.
3. It is unlikely to close the low-pressure side discharge line during normal operation.
j. A coil fitted into a vessel shall also be considered for the burst tube condition, depending
on the design and construction of the coil.
9.2.3. External fire condition

a. Pressure relief capacity shall be provided on heat exchangers for the external fire condition
on both sides if they can be isolated without draining or in an area where a fire could be
sustained. This applies even if the exchangers are designed for pressure containment.
b. Consideration should be taken that operations/emergency responders tend to stop process
and utilities flow during a major fire.
The facility may accept this risk provided that failure of the heat exchanger would not
affect emergency responders nor add appreciably to the extent/duration of the fire.
c. Sizing for the shell side shall be based on heat input to the shell area exposed to the fire.
Sizing for the tube side shall be based on heat input to the channel area exposed to the fire.
d. On water-cooled exchangers with hot fluid on the shell side, pressure relief devices need
not necessarily be for steam formation if the maximum temperature of the shell fluid is
below the boiling point of water at the tube side design pressure. However, relief capacity
shall be made available for any steam generated by heat input into the channel and/or
bonnet, possibly through pressure relief valves provided for thermal relief.
e. If chemical cleaning is required on a routine basis during normal operation, pressure relief
devices for the fire condition shall be sized not only for the normal process fluid but also
for water, to represent a chemical cleaning fluid.
f. For high boiling-point liquids, vapourisation due to external fire may not need to be
considered; however, pressure relief devices for thermal expansion should be provided.
9.3. Air-cooled heat exchangers

Air coolers are essentially piping and are not generally protected by a pressure relief device. For
the fire scenario, API RP 521 or ISO 23251 mitigation alternatives should be used in lieu of a
pressure relief device. The mitigation methods include:
a. Providing capability to isolate the air cooler if a fire were to occur.
b. Designing overhead air coolers to be free draining toward the tower or reflux drum to
minimize liquid content.
c. Sloping the ground underneath the air cooler to minimize the formation of a liquid pool
beneath the exchanger.
9.4. Double pipe heat exchangers

a. In general, double-pipe heat exchangers are fabricated from schedule piping and complete
tube rupture is unlikely (See ISO 23251 and API RP 521). Therefore, it is usually not
necessary to consider an internal failure in double-pipe heat exchangers. If specific
experience has shown an internal failure is credible, then an internal failure should be
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considered, but in most cases would constitute a partial failure (e.g., hole), rather than a
full-bore failure.
b. Regarding fire exposure, double-pipe heat exchangers are similar to piping (high surface
area per volume) and, as should be treated comparably to air-cooled heat exchangers.
9.5. Plate-and-frame heat exchangers

a. Relief protection of plate frame exchangers should be in accordance with API 521 or
ISO 23251 guidance related to shell-and-tube heat exchangers. However, instead of an
entire plate failure, the relief design should use a hole size comparable to a tube (e.g.,
12,5 mm to 19 mm (0,5 to 0,75 in) in diameter) for the relief system calculations.
b. Fire should not be considered in the design of overpressure protection systems for plate
and frame exchangers with elastomeric gasketing that would burn away upon fire
exposure.
9.6. Centrifugal pumps

a. If the suction side of a stand-by pump can be overpressured following inadvertent closure
of the suction block valve, the suction line and fittings, from and including the suction
block valve and the pump suction flange, shall be rated at the same line specification as the
pump discharge. If this cannot be achieved (due to an existing pump being re-used or a
vendor not making this style pump available), adequate relief for the potential backflow
pressures and rates or appropriate valve sequencing (such as holding the suction valve
open) shall be designed and verified during the PHA for this system.
1. In a constant-speed centrifugal pump, the pressure should be determined from the
following set of considerations:
a) Maximum suction head in normal operation.
b) Shut-in differential head.
c) Maximum specific gravity in normal operation.
2. In checking the pump design pressure against the pressure ratings of the suction line
and fittings, it is permissible, depending on local codes, to add 33% to the ratings for
the maximum allowable non-shock working pressure given in ANSI/ASME B16.5 for
flanges (including the pump casing suction flange) and fittings, or to add 33% to the
maximum allowable stress for other components.
a) The 33% allowance may be applied only if it lasts not more than 10 hours at any
one time, or 100 hours/year in accordance with ANSI/ASME B31.3, and shall
not be used for cast iron or similar non-ductile material.
b) Other local codes and standards may govern the temporary overpressure
allowance for piping in other worldwide locations.
c) The pump seal shall also be checked for adequate design pressure.
b. As an alternative to uprating suction piping, pressure relief devices may be fitted on the
suction lines between block valve and pump, relieving pressure downstream of the inlet
block valve to safe location. However, this is normally a more expensive design, and shall
not in any case be used for highly viscous or coking liquids.
c. Pump pressure relief devices should discharge to a feed drum, tank, vessel, or pump
suction. If discharging into the pump suction, consideration shall be given to guard against
eventual over-heating of the fluid from mechanical heating (e.g., trip systems and
administrative controls are commonly used).
d. For a relief device:
1. A detailed check shall be made to ensure the relief route is acceptably safe.
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2. The set pressure shall correspond to the maximum allowable suction system pressure
or stationary seal pressure, whichever is less. For the seal, the exact set pressure
requires agreement with the pump manufacturer.
3. The discharge rate shall be the maximum estimated flow possible through the non-
return valve bypass or other pressurising line under the relieving condition.
9.7. Positive displacement pumps

a. External pressure relief valves shall be provided in almost all cases because a positive
displacement pump has no upper limit on discharge pressure. Internal relief devices shall
not be the single means of overpressure protection because they can not be tested.
b. Some small pumps such as small metering pumps if designed to stall below MAWP of
equipment may not need a pressure relief device.
9.8. Steam turbine drivers

a. For back pressure turbines, in which the exhaust side can be overpressured following
inadvertent closure of the exhaust side block valve, a pressure relief device shall be fitted
between the turbine and the exhaust block valve. This device shall be sized for full design
turbine flow (the final rated flow supplied by the turbine vendor for the equipment actually
installed) or the capacity of the outlet at the relieving pressure (generally 110% or 133% of
system design pressure) and be set at the casing exhaust-side pressure rating or the
allowable exhaust-piping pressure, whichever is lower.
b. If back pressure turbines have intermediate takeoffs, the relief arrangements shall ensure
that no section of the turbine casing or interconnecting pipework is subject to overpressure
under conditions of wide open throttle valves, full design throttle pressure, and closed
intermediate takeoff valves.
c. Condensing turbines should be protected from overpressure by the provision of either
atmospheric relief valves or rupture disks. The minimum area of relief should be such that,
when the turbine throttle valves are wide open with the turbine inlet pressure at its design
value, no section of the turbine casing, condenser or interconnecting pipework should
exceed its design pressure.
d. This provision should also apply to condensing turbines with intermediate takeoff
connections.
e. In checking the manufacturer’s rating for the exhaust side of the casing and also the
maximum pressure rating for the exhaust line; it is permissible, depending upon local
codes, to add 33% to the ratings for the maximum allowable non-shock working pressure
given in ANSI/ASME B16.5 for flanges (including the casing exhaust flange) and fittings,
or to add 33% to the maximum allowable stress for other components.
1. The 33% allowance may be applied only if it lasts not more than 10 hours at any one
time, or 100 hours/year in accordance with ANSI/ASME B31.3, and shall not be used
for cast iron or similar non-ductile materials.
2. Other local codes and standards may govern the temporary overpressure allowance
for piping in other worldwide locations.
f. Condensing turbines shall have a pressure relief device to protect against overpressure
resulting from loss of cooling water or other operational failure.
g. Non-condensing turbines shall have a pressure relief device on the low-pressure side
upstream of the first block valve. Sentinel valves shall not be considered pressure-relief
devices.
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9.9. Furnaces
a. Pressure-relief devices should be located on furnace outlet, upstream of first block valve.
b. Pressure relief devices should only be installed at furnace inlet if there is the possibility of
the following:
1. Inside of pressure relief devices is subject to coking if located on the furnace outlet
and there is no steam or other purge available to keep pressure relief device inlet
clean.
2. Individual tubes can be blocked with coke.
c. A fuel shutdown system should be provided to prevent overheating and rupture of a tube if
a pressure-relief device located at the furnace inlet opens and causes inadequate flow
through tubes.
d. Failure of the process tubes should still be considered even if the fuel shutdown system
worked successfully because it may be possible for the residual sensible heat of refractory
to cause over-temperature failure of the process tubes after firing is stopped.
9.10. Boilers
a. Safety valves for ASME Section I Boilers should be set so the first valve to open is
downstream of superheater.
b. Safety valve(s) on steam drum should be set to open over as wide a range of pressure as
permissible with the first safety valve to open being the smallest size used.
c. Subsequent safety valves should be progressively larger.
d. Economizer/preheater safety valve should be set to open after all drum valves have
opened.
9.11. Compressors
a. Positive displacement and centrifugal compressors in which pressure during surge or
closed discharge can exceed MAWP of piping, equipment, or casing shall have a pressure-
relief device.
b. Compressor pressure-relief valves should discharge to a safe area such as a flare if
compressing hydrocarbons. If the pressure-relief valve discharges back to suction of the
compressor, an analysis should be performed to verify that temperature and pressure of
compressor suction and process fluid do not exceed their maximum safe operating limits.
c. Compressor pressure relief valve discharges shall be designed to prevent possible
compressor surge or system malfunction.
d. If positive displacement compressor suction piping can be overpressured due to internal
back-leakage through compressor discharge valves of discharge gas when machine is
shutdown, suction piping shall have a pressure relief device or the compressor inlet flange
and suction piping back to the first block valve shall be rated for the higher pressure.
e. Positive displacement compressors shall have a pressure relief device on discharge side
upstream of the first isolation valve.
f. Multistage positive displacement compressors shall have pressure relief devices for each
stage.
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9.12. Main transmission pipelines and associated equipment
9.12.1. General
a. For the purposes of this GP, main transmission pipelines and associated equipment shall be
defined as follows:
1. Oil or gas transmission pipelines both on land and offshore, but excluding processing
plant.
2. Departure and arrival terminals immediately associated with transmission pipelines
plus any intermediate stations as required. This includes pig launchers/receivers and
slug catchers, but not processing facilities associated with a terminal.
b. In main transmission pipelines and associated equipment, the provision of pressure relief
devices may not be acceptable or effective, apart from any provision for thermal
expansion.
c. When considering overpressure protection, all types of protective devices should be
considered, including overpressure controls, automatic shutdown equipment, and pressure
relief devices.
9.12.2. Surge
a. The maximum pressure in the system that can arise as the result of operating conditions
plus any surge pressure shall be evaluated and taken into consideration in the design, after
allowing for the effect of all practical methods for surge protection, e.g. expansion vessels,
slow-closing valves, etc. If the operating pressure plus the resultant surge pressure exceeds
that permitted by the appropriate code, then either overpressure devices or pressure-
limiting instrumentation shall be installed.
The manufacturer should be consulted for more precise data for specific types. The times
need to be correctly considered in the hydraulic surge analyses.
b. Surge pressures that are likely to be significant shall be determined and provided for in the
design, either by reducing the level of permitted operating pressure or by provision of
protective devices to keep the maximum pressure within that permissible.
9.12.3. Static head

If a pipeline that crosses undulating or mountainous terrain (whether or not it is designed for
slack line operation) can be shut down under pressure, means of overpressure protection shall be
provided to limit static head pressures due to differences in elevation to within the maximum
permitted internal design pressure at any point of the system.
9.12.4. Fluid expansion

The effects of fluid expansion on internal pressure, due to temperature changes in any static
section that can be isolated shall be considered and pressure relief devices shall be installed, if
required. If main line isolating valves are provided with bypasses incorporating a pressure relief
device, the cumulative pressure increase shall be considered.
9.12.5. Intermediate stations and terminals

a. Surge protection and relief facilities shall be provided if necessary to ensure that both
upstream and downstream line pressures do not exceed the design pressure.
b. Relief storage of sufficient capacity to accommodate all relief discharges and drainage
shall be provided. Pumping facilities shall be provided wherever necessary to return
relieved fluids to the system.
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c. Facilities for depressuring shall be provided at compressor stations. Gas compressors shall
be fitted with a pressure-relieving system fully sized for the shut-in condition and installed
in the discharge line from each compressor.
d. Pressure-relieving systems, flares, and surge tanks shall be designed and located to meet
the requirements of GP 44-80.
9.12.6. NGL pipelines

The effect of high daytime temperatures and pressures, and low night-time temperatures and
pressures (even vacuum) shall be calculated, and protective systems shall be provided as
necessary.
9.13. Process and utility piping

The pressure relief devices should preferably be set at the design pressure as defined in
ANSI/ASME B31.3 or national equivalent, but in no case shall the pressure setting exceed the
allowances for variations from normal operating conditions permitted by ANSI/ASME B31.3,
or the maximum design pressure of the weakest component in the system.
9.14. Atmospheric/low pressure storage tanks
9.14.1. General
Pressure-relieving arrangements for storage tanks to operate at or near atmospheric pressure
shall be in accordance with API Std 2000 and GP 58-10.
9.14.2. Liquid storage tanks

a. Low pressure and atmospheric liquid storage tanks shall be protected by an emergency
vent.
b. Low pressure and atmospheric tanks shall be protected by a vacuum relief device to
prevent pressure from being reduced below design if any of the following may occur:
1. Liquid content capable of being withdrawn faster than either the liquid inlet, vent or
gas blanket can counteract, causing a decrease in internal tank pressure. During tank
vent evaluation, freezing conditions or plugging that could affect vent capacity shall
also be considered.
2. Tank overhead has compressor or blower capable of reducing the pressure in the
vapour space.
3. Materials capable of being introduced into the tank could cause a thermal contraction
of the product liquid volume or reduction of pressure in the vapour space.
4. Either changes in ambient temperature conditions or failure of heating device causing
a thermal contraction of the contents or a reduction of the vapour space pressure by
condensation.
c. An open vent to the atmosphere, i.e. a goose neck vent, may be used for both emergency
venting and normal tank breathing if:
1. Local environment laws permit and
2. Contained liquid is a combustible liquid with a flash point above 93°C (200°F) and
3. Operating temperature is a minimum of 28°C (50°F) less than liquid’s flash point.
These may also be used if local environmental loss permits and any vapour emitted is non-
toxic or dispersion analysis indicates personnel would not be adversely impacted.
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d. If air is not to be tolerated within the tank, consideration should be given to designing the
tank to withstand full vacuum or providing an inert gas system to prevent vacuum during
normal and emergency conditions.
9.14.3. Solid storage silos

a. Low pressure and atmospheric storage silos shall be protected by a venting device to
prevent pressure from rising above the positive design pressure of the silo.
b. Low pressure and atmospheric storage silos shall be protected by a vacuum relief device to
prevent pressure from being reduced below the vacuum design pressure if any of the
following may occur:
1. Liquid contents from the silo are capable of being withdrawn faster than either the
liquid inflow or vacuum vent can counteract, causing a decrease in internal silo
pressure. During evaluation of a silo, freezing conditions or any other plugging that
could affect vent/vacuum capacity shall be considered.
2. Silo’s overhead has a compressor or blower capable of reducing pressure in the
vapour space.
3. Either changes in ambient temperature conditions or a difference between ambient
and internal silo temperature, causing a reduction in pressure.
c. If air is not tolerated within the silo, consideration should be given to designing the silo to
withstand full vacuum or providing a backup inert gas system to be operational during
emergencies.
9.14.4. Other low pressure equipment

There may be other low-pressure equipment that does not fall under any specific code or
standard because their design pressure is low enough that they are not classified a pressure
vessel (per ASME Section VIII Div. 1 for example) nor are they classified a storage tank (per
API Std 2000).
a. These shall be treated on a case-by-case basis regarding overpressure and vacuum
protection.
b. Consideration shall be given to the possible consequences of failure if a relief device or
vacuum protection device is not installed (i.e., potential personnel exposure, fire,
explosion, environmental release, business interruption loss).
c. When specifying a relief device, guidance on API Std 2000 may be useful although the
relieving pressure may need to be adjusted based on the mechanical design specifics.
9.15. LPG/LNG storage

a. The overpressure protection of LPG storage systems shall be in accordance with the
IP Part 9 or API Std 2510. (Note this IP document is not applicable to LNG storage.)
b. Refrigerated LPG and LNG tanks shall be protected against low-pressure (partial vacuum)
conditions.
c. Non-refrigerated LPG tanks shall be protected against low pressure partial vacuum
conditions caused by extreme low ambient temperature conditions.
9.16. Cascade effects

If there are process connections from one part of a unit to another part of the same or another
unit, the need for overpressure protection due to an upset on one causing an overpressure on the
other shall be addressed. This shall particularly be examined for all cases in which gas
generated in one process is supplied to another.
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10. Pressure relief devices
10.1. General
a. Equipment, vessels, or process systems protected with more than one relief device for the
same overpressure contingency typically should have these relief devices with staggered
set pressures.
1. In some cases, a smaller relief valve with a lower set pressure for smaller and more
frequent upset should be considered in addition to the larger valve for the less
frequent, larger relief loads. Typically, a relief valve may be considered oversized
when the inlet flow is less than approximately 20-25% of the capacity.
2. One pressure relief device shall be set at or below the design pressure or maximum
allowable working pressure (MAWP) of the protected equipment.
3. Additional devices may be set at higher pressure (if allowed by local codes), but in no
case, except for fire, should the setting be more than 105% of the design pressure or
MAWP.
4. Only under fire conditions or other expected external heat input, could a supplemental
device be set as high as 110% of design pressure or MAWP.
b. Attention shall be given to relief situations that result in a wide range of relieving flow
rates under different upset conditions. In this case, consideration shall also be given to the
selection of two valves; a smaller pressure relief valve set at the equipment design pressure
to handle the upset conditions resulting in lower relieving rates, and a larger valve set at
105% of equipment design pressure for the largest relieving case or otherwise set as
permitted by code (the European Pressure Equipment Directive [PED] instructs EU
members that vessel design pressure should not be exceeded.).
c. Use of multiple pressure relief devices shall conform to the following:
1. Multiple pressure relief devices should be used if sufficient relief area cannot
practically be supplied by one relief device.
2. Consideration should be given to using multiple pressure relief devices, if a larger
size valve is being considered (e.g., Q, R or T size).
d. Similar considerations shall apply if a single large rupture disk is required for the
controlling scenario.
1. A parallel pressure relief valve set to open at lower pressure should be considered to
handle smaller upsets that do not require full rupture disk area but could occur more
frequently.
2. Depending on service, the pressure relief valve may require a rupture disk beneath it.
e. Relief valve set pressure corrections for temperature may be necessary for high
temperature systems.
1. Correction applied should be based on temperature at the valve when it is in the
closed position.
2. This temperature may not be the flowing process temperature even if the valve is
mounted directly on protected equipment but uninsulated.
3. Distance from process and effects of any thermal tracing shall be taken into account
when applying a thermal correction factor.
4. Once temperature is determined, manufacturer’s specific temperature correction
factor shall be applied.
5. Correction factor should be multiplied by set pressure to determine cold set pressure.
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f. The uses of pressure relief devices other than pressure relief valves, rupture disks, and
buckling pin type valves are not excluded, but shall be subject to approval by IMSL .
10.2. Pressure relief valves
10.2.1. General
a. The selection of a pressure relief valve type is unique to each individual application;
however, general guidelines and experience can be given as follows.
b. Relief valve material shall be suitable for the inlet and outlet temperatures that result from
the extremes of operating and emergency conditions. This includes the effect of cooling as
a result of reducing pressure through the valve during relief; however it does not include
extreme conditions such as external fire or explosion in which relief valves would
subsequently be discarded.
c. Relief valves should follow API RP 520 or ISO 4126 guidelines and local or national
design standards if applicable such as PED, BSI, and ASME.
10.2.2. Conventional type

a. Conventional-type pressure relief valves shall be of the nozzle-entry type having enclosed
springs and conforming with ISO 4126, BS 6759 Parts 1, 2, or 3, API Std. 526, or other
national standard approved by IMSL .
b. For steam, open bonnet relief valves should be used.
c. Bodies shall be of carbon or alloy steel with trims of 12% Cr alloy or other corrosion-
resistant alloy suitable for the service conditions.
d. For flammable service or for toxic service or for hot condensate service that can cause
burns, conventional-type pressure relief valves with closed bonnets should be used.
e. Normally, for conventional (or non-balanced) relief valves, built-up backpressure should
be limited to 10% of the set pressure.
1. In all possible cases the back pressure should not exceed the maximum pressure
rating on the outlet side of the conventional valve (refer to API Std 526 or
manufacturers' data).
2. If back pressure limits are exceeded, a special valve shall be made and a specific
manufacturer’s guarantee is required.
10.2.3. Balanced type

a. Balanced pressure relief valves may be used to reduce the effect of either constant
superimposed or built-up back pressure on relief valve set pressure since they incorporate a
means of minimizing the effect of both constant and variable back pressure on the
operational characteristics of balanced type relief valves.
b. The bonnet vent gases from balanced piston-type valves should be disposed of with a
minimum restriction and in a safe manner.
c. To provide for possible bellows failure or leak, the bonnet shall be vented separately from
the discharge.
d. The maximum back pressure that a balanced-type valve may be subjected to should not
exceed the lower of:
1. 50-60% of the valve set pressure.
a) At higher back pressures, the relief valve capacity reduction becomes
appreciable and if operation is required at back pressures greater than 50% of the
Page 40 of 54
valve set pressure, the particular valve manufacturer should be consulted for
sizing assistance and to assess the suitability of their valve in this application.
b) For a back pressure exceeding 55% of the valve set pressure, performance data
of the specific valve at the expected set pressure shall be obtained from the
manufacturer and be subject to IMSL approval.
2. The maximum pressure rating on the outlet side of the balanced valve (refer to API
Std 526).
e. Bonnet and bellows vents from balanced-type pressure relief valves shall be piped with
minimum restriction to a safe location, as approved by IMSL .
f. In bellows-type pressure relief valves, the bonnet shall be vented separately from the
discharge.
g. Bellows-type valves shall not be used in fouling conditions unless precautions are taken to
avoid or minimize bellows fouling or deposit build-up during relieving and normal
operation (e.g., due to leakage across the valve seat).
h. The auxiliary balancing piston type should be used for critical and fouling services as
specified by IMSL .
10.2.4. Pilot-operated type

a. These valves can only be used in clean vapour service in which plugging or freezing of the
pilot line is not anticipated.
b. Pilot-operated pressure relief valves have their major port or seat opening controlled by a
self-actuated auxiliary pressure relief valve and should be used primarily in non-fouling
service, but could also be used in fouling service if IMSL approval and suitable
precautions to avoid plugging are implemented (i.e. purging, flushing).
c. The type of pressure relief device selected should be compatible with temperatures that can
reasonably be expected when relieved fluid pressure drops across the relief device down to
atmospheric or to the system back pressure. (Joule-Thompson effect).
d. Filters can plug similar to the pilot valve and sensing lines and therefore should not be
used in pilot supply or sensing lines.
e. Discharge from the pilot valve shall be to a suitable low-pressure location. For pilot-
operated relief valves in which high back pressure on the pilot discharge could cause the
main valve to re-close, the pilot discharge line shall be vented to atmosphere rather than
into the main valve discharge piping, unless the pilot operator is a balanced valve.
f. If pilot operated relief valves have the possibility of the downstream pressure being higher
than the upstream pressure, these valves shall be equipped with a backflow preventer.
10.2.5. Pilot-assisted type

a. A pilot-assisted pressure relief valve, in which the valve is still capable of operating as a
normal spring-loaded valve in the event of pilot or actuator failure, is preferred to a pilot-
operated valve.
b. Pilot-assisted valves should be considered for use if accuracy of setting is important, or
rapid opening and closing are required. They may also be used to give a full-bore
discharge to maintain specific velocities when venting to atmosphere. However, their use
shall be subject to approval by IMSL (see GP 44-80).
10.2.6. Use of easing gear

Easing gear on pressure relief valves is not required, unless called for by statutory regulations.
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10.3. Rupture disks (bursting discs)
10.3.1. General
a. The margins between normal operating and design pressures are generally larger for
rupture disks compared to relief valves and shall be accommodated in the design. Rupture
disks are also susceptible to opening due to short duration pressure transients particularly
common in liquid filled systems.
b. Rupture disks may be considered for slurry, corrosive and erosive services, or to minimize
leakage of valuable, hazardous, or toxic fluids. The use of a pressure relief valve combined
with an inlet rupture disk should be evaluated on a case-by-case basis if corrosive fluids
dictate the material of construction of the valve.
10.3.2. Types of rupture disks

a. Dependent on the application, various types of rupture disk may be used, i.e., forward
acting scored, reverse acting scored, pre-bulged, or composite, subject to IMSL approval.
b. If normal domed rupture disks may be subject to vacuum, under any operating conditions
or if outlet pressure exceeds the inlet pressure temporarily, a vacuum support (per
BS 2915) shall be fitted.
c. If used upstream of a relief valve, disks shall be non-fragmenting, and shall be provided
with means of retaining the disk after opening. Fragmenting type rupture disks may be
considered if the disk vents directly to atmosphere (no downstream relief valve) and if
there is minimal outlet piping.
10.3.3. Use of rupture disks

a. The preferred method of providing pressure relief is with pressure relief valves due to their
reclosable nature. However, rupture disks are the preferred or only reasonable method for
the following cases:
1. For relief of a pressure that is rising too fast for normal pressure relief valves,
typically in a reaction vessel, shell and tube exchangers where the exchanger shell
requires rapid overpressure protection against tube rupture, or in the case of potential
explosions in a powder silo.
2. In services in which the operation of a pressure relief valve may be affected by
corrosion or corrosion products, or by the deposition of material that may prevent the
valve from lifting in service.
3. With highly toxic or other materials for which leakage through a pressure relief valve
cannot be tolerated.
4. For low positive set-pressures in which pressure relief valves tend to leak.
5. For slurry flow, chemically reactive, and/or extremely viscous fluids. A rupture disk
may be used to either protect a pressure relief valve located downstream or in place of
a pressure relief valve if the valve would plug during normal operation or while
relieving.
6. If it is necessary to provide for rapid depressuring to atmospheric pressure.
b. The selected burst temperature shall consider the day/night and seasonal temperature
variations, particularly if untraced and/or uninsulated.
c. The rupture tolerance range of rupture disk does not need to be considered when
determining the burst pressure.
d. Rupture disks shall not be used for pulsating flows or at working pressure too close to the
design bursting pressure.
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1. Normal domed rupture disks (i.e., non-scored) may be operated at working pressures
only up to 70% of the bursting pressure.
2. Forward-acting scored rupture disks may be operated at 80-90% of the bursting
pressure.
3. Reverse-acting scored rupture disks may be operated at up to 90% in many
circumstances.
4. Use of a rupture disk at an operating working pressure exceeding 90% shall be
subject to approval by IMSL .
5. API RP 520 or ISO 4126 should be used for general guidance on the maximum
suitable operating pressures for the various types of bursting disks. However, in all
cases, the manufacturer’s information on the specific disk should be used.
e. Rupture disks may be used to shield inlet or outlet of the pressure relief valves provided
that:
1. Telltale device shall be used between disk and relief valve to identify disk leakage or
failure. This device in most installations includes a pressure gauge, an excess-flow
check valve, and a vent to atmosphere.
2. If leakage is not permitted to atmosphere, the vent should be routed to a closed
system operating near atmospheric pressure even under upset conditions.
3. Any back pressure in the closed system shall be considered in the rupture disk relief
burst pressure design.
4. Any leaking rupture disk beneath a pressure relief valve should be replaced
immediately.
5. If a rupture disk is used upstream of a pressure relief valve so that a lesser metallurgy
relief valve can be used (e.g., the use of a titanium rupture disk with a stainless steel
pressure relief valve instead of a titanium pressure relief valve) and if the pressure
relief valve vents into a common header, the design shall consider any corrosive or
fouling products from other locations that can degrade the pressure relief valve from
the outlet side.
f. If rupture disks are selected, the design shall ensure convenient and safe replacement of the
disks considering the layout and installation.
g. Low pressure (less than 1,0 bar (ga) [15 psig]) rupture disk designs that do not permit
affixing a tag should only be used if tag is firmly secured to installed disk assembly and
special provisions are made to ensure correct installation.
h. For slurry or any other service in which material could build up, consideration should be
given to providing a small gas or clean liquid purge flow across the process side of disk to
prevent possible obstruction in front of disk.
i. Pre-scored forward-acting design and pre-scored reverse-acting design are the preferred
choice for rupture disks.
j. Reverse-acting rupture disks that rely on a cutting assembly shall not be used.
10.3.4. Rupture disk burst pressure considerations

a. To avoid a disk that bursts prematurely or a disk that is stamped above the equipment
MAWP the design shall consider both operating-to-stamped burst pressure ratio and
manufacture range.
b. Rupture disk burst temperature shall be specified as the temperature at which the rupture
disk normally operates. The rupture disk operating temperature may be significantly
Page 43 of 54
different from both the relieving temperature and the process operating temperature. To
prevent mismatch of temperature the following options shall be considered:
1. Heat tracing disk and holder to ensure it is always at a specified temperature. Design
burst temperature should be specified at this temperature.
2. Keeping disk temperature near ambient through remote disk location and/or
insulation removal. An average ambient temperature should be specified for design
burst temperature.
3. Locating disk near enough to process, so it is kept at operating temperature. Design
burst temperature should be specified at or near average operating temperature. The
temperature of the rupture disk shall be reconfirmed at the field.
4. Insulating rupture disk holder.
5. Jacketing rupture disk holder and applying heat through a temperature control system.
6. Using other engineered solutions that minimize the difference between operating and
set temperature.
7. Specify a disk material (e.g., Inconel 600 instead of 316 stainless steel) that is less
sensitive to temperature and still meets all other requirements.
10.3.5. Rupture disk configuration

a. Set pressure of a relief valve installed with a rupture disk on inlet side should be minimum
value of disk manufacturing range. The pressure relief valve set pressure shall not exceed
the value that would be allowed if there were no upstream rupture disk.
b. A free vent shall be provided in between the rupture disk and pressure relief valve so disk
bursts at desired pressure and not higher.
10.4. Rupture pin relief valves

a. When evaluating a rupture pin valve application rupture pin valve customers should be
contacted for their experience on valve performance. Caution should be taken when
considering a rupture pin valve first of its kind relative to size and/or pressure setting.
Though the manufacturer may have successful applications with a particular valve size and
setting; scaling up in either size or pressure may impact the precision and accuracy of the
relief setting.
b. If the rupture pin valve requires a lubricated O-ring for the rupture pin piston, lubricant
shall be insensitive to hydrocarbons (i.e. ensure lubricant viscosity is unaffected by process
fluids; for if it can be affected, the viscosity change can impact the relief pressure setting).
In-line lubrication features should be considered to minimize having to isolate and open
the valve to relubricate it.
c. A common failure mode for rupture pin valves is the O-ring, particularly for larger sized
valves [> DN 100 (NPS 4)]. Ensure the O-ring cannot be rolled out of its groove by proper
ring sizing and paying close attention to piston groove tolerances.
d. Pipe stresses or misalignment shall be carefully reviewed. Piping misalignment or undue
stress may result in the rupture pin valve setting inaccuracy.
10.5. Sizing of pressure relief devices

When the type of valve has been selected and the back pressures are known, the required orifice
area should be calculated using formulae listed in ISO 4126 or API RP 520, Part 1. This orifice
area shall be provided by one or more relief devices. In calculating the orifice areas, correction
factors, if required, should be obtained from the particular manufacturer’s data.
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a. The calculation of required free area for relief valves and rupture disks should be in
accordance with the appropriate National Code. For example, TüV in Germany have their
own pressure relief valve sizing procedures which shall be used when applicable. In the
absence of such a Code they should be sized in accordance with the methods described in
ISO 4126 or API RP 520 Part I, or other appropriate sizing method.
b. In sizing relief devices, the set pressure and accumulation pressure shall be in accordance
with the applicable pressure vessel design code.
c. The design of pressure relief devices discharging to a closed relief system shall take into
account the maximum back pressure arising at the discharge of the device for the particular
overpressure case under consideration. Additionally, the mechanical design shall be
suitable for the maximum back pressure to which a device can be exposed as a result of
other devices relieving.
10.6. Installation of pressure relief devices
10.6.1. General
a. Pressure relief devices shall be installed in accordance with ISO 4126 or Part II of API
RP 520 as amplified and amended below.
b. Relief devices intended to relieve vapour should be connected to the highest point of the
equipment to be protected if possible. If this is not possible and there is the possibility of
liquid above the relief device inlet line, the relief device shall be sized for an equivalent
volumetric rate of liquid and means available to minimizing slugging.
c. If thermal cycling has been shown to be an issue, pressure relief valves should be located
such that the fluid temperature at the valve during normal plant operation is near ambient
conditions when the valve is inactive so as to minimize thermal cycling. The valves shall
be heat traced should it be deemed that ambient conditions affect its performance.
d. Pressure relief devices shall be isolated before hydro-test of piping or vessels, but included
in system tightness testing.
10.6.2. Preinstallation
10.6.2.1. General
a. Before installation, pressure-relief valves shall be stored in an upright position in a clean,
dry area and rupture disks shall be stored in a clean, dry area in their original shipping
containers.
b. Inlet and outlet of pressure-relief devices shall remain covered until time of installation.
c. Before installation or bench testing, pressure setting engraved on pressure-relief device
nameplates shall be verified as being the same as specified on data sheet and facility
pressure-relief device records.
d. Inlet piping and associated equipment shall be free of foreign matter. This includes pipe
scale, welding beads, or other objects that could cause damage or prevent pressure-relief
valves from reseating after operation.
10.6.2.2. Preinstallation of pressure-relief valves

a. Before installation, protective covers shall be removed from pressure-relief valves and
valves shall be inspected for foreign matter.
b. Pressure-relief valves shall be made available to companies for testing before
commissioning.
c. On pressure-relief valves with bellows, a pipe elbow shall be installed in vent connection
on bonnet with wire mesh over female end. Conventional or unbalanced pressure-relief
Page 45 of 54
valves which do not have bellows shall have their bonnet vent connections plugged with a
metal plug.
10.6.2.3. Preinstallation of rupture disks

a. Rupture disks should be packed separately to help keep them clean and dry. Rupture disks
will be inspected to ensure clean seating surfaces unless disk is purchased pre-assembled in
its holder.
b. Disks shall be inspected for physical damage.
c. Disks that are dented, dirty, discoloured, or otherwise damaged shall not be used.
d. Rupture disk and holder assemblies of bolted construction shall be checked for torque as
recommended by manufacturer.
10.6.3. Installation of pressure relief devices
10.6.3.1. Use of ISO 4126 and API RP 520

Pressure relief devices shall be installed in accordance with Part II of API RP 520 or ISO 4126
as amplified and amended below. For installations covered by ASME Section I, ASME
Section VIII, PD 5500, European PED or other applicable national codes and standards, these
additional code requirements shall also be followed.
10.6.3.2. Isolation of pressure relief devices

a. The installation of block valves or spades in any location in which they could isolate a
vessel or system from a pressure or vacuum relief device or downstream flare system shall
not be permitted without prior IMSL approval. Their use shall be permitted only if they are
considered essential to safeguard the operation of the unit as noted in the following
paragraphs. Such valves shall be locked open during normal operation. See also
clauses 8.2.4 to 8.2.6 of GP 44-80.
Some block valves or spades are vital to the maintenance of items on operating units;
however, these should be kept to a minimum, identified, and a procedure shall be put in
place (generally a work permit or valve lock open procedure) for controlling their use.
b. Inlet or outlet block valves are generally not permitted for ASME Section I applications,
unless special 3-way valves are approved by local authorities and IMSL. For ASME
Section VIII applications, the PSV installation may provide in-place on-line testing
capability to improve safety and reduce turnaround time and maintenance costs.
Restrictions to block valve use in overpressure relieving services shall be determined in
compliance with governing local codes and standards.
c. Block valves to isolate pressure relief devices may be used if relief devices need to be
inspected or maintained during the protected equipment operation, if an additional relief
device is installed so that 100% design relieving capacity is available with any relief
device out of service.
1. Such block valves shall be fitted at the inlets to the relief devices and at the
discharges if this is to a closed system. Locked open isolation valves are also
acceptable downstream of single relief valves to isolate them from a closed disposal
system.
2. Such block valves shall be locked open or interlocked, by a system approved by the
operating management. A physical means of securing the isolating valve is preferred.
d. If block valves are installed on relief devices, the upstream or inlet block valve shall be a
full port valve with the valve inlet diameter the same as the relief device inlet flange. The
downstream valve shall also be full port if justified by the pressure drop. With supporting
pressure drop calculations a reduced port valve may be used. (See clause 10.6.j)
Page 46 of 54
e. A valved and blanked/plugged drain connection of minimum size DN 20 (NPS 3/4) shall
be provided between the relief device and any upstream block valve. A similar vent
connection shall be provided between the relief device and any downstream block valve.
10.6.3.3. Location of pressure relief devices

a. Pressure relief devices shall be installed in such a manner that the inlet drains back to the
equipment being protected, subject to the need to drain the discharge side to a header. If
possible, they should be placed directly on the equipment or pipeline they are protecting.
b. Pressure relief devices for fractionating columns should not be fitted to reflux drums or to
overheads piping in such a way that reflux pump failure can cause flooding of the inlet to
the device. They should normally be fitted between the fractionating column and the
overheads condenser.
c. Unless otherwise specified by IMSL, permanent access shall be provided to the following:
1. Rupture disk locations.
2. Those pressure relief valves that require inspection and/or maintenance between
major plant shutdowns.
d. Pressure relief devices discharging into a closed system shall be located such that there is a
continuous fall from the devices to the downstream knockout drum, so that the lines
contain no liquid traps.
e. Relief valves shall be mounted in a vertical position.
10.6.3.4. Piping to and from pressure relief devices

a. If pressure relief devices are not placed directly on the equipment or pipeline they are
protecting, their inlet piping:
1. Should be as short as possible with the inlet device connection located as near as
practical to the equipment being protected.
2. Shall have a bore area at least equal to that of the pressure relief device inlet.
3. Shall drain back to the equipment being protected.
b. For new installations to prevent relief valve chattering and damage, the total non-
recoverable pressure loss between the equipment or pipeline protected (including the pipe-
entrance loss) and a spring-loaded pressure relief valve inlet shall not exceed 3% of the set
pressure of the valve for the flow corresponding to the installed valve area, i.e. the rated
capacity of the valve.
c. For existing installations of spring-loaded pressure relief valves, the non-recoverable inlet
line pressure loss based on the rated capacity of the valve should not exceed 7% of the set
pressure or the blowdown, whichever is lower.
d. Inlet line losses for pilot-operated pressure relief valves may be higher than those for
spring-loaded pressure relief valves provided both:
1. The sensing line is connected to the equipment away from the effects of the inlet
pressure loss.
2. The relief area is calculated based on the pressure at the relief valve inlet flange (i.e.,
relieving pressure in the vessel minus inlet line pressure loss).
e. The “nominal” flow area through all pipe and fittings between a pressure vessel and its
pressure relief device shall be equal to or greater than the device inlet “nominal” flow area.
The pressure loss of the inlet piping shall be based on the actual pressure relief device
capacity for compressible flow.
Page 47 of 54
f. If two or more pressure relief devices are placed on one connection, the cross-sectional
“nominal” area of this connection shall be at least equal to the combined “nominal” inlet
areas of the valves, and the normal pressure loss requirement shall apply for the combined
rated flow of the valves.
g. Modulating action relief valves can use the required relief load rate instead of the rated
capacity when determining inlet line pressure loss.
h. Inlet piping shall be heat traced if the fluids handled have pour or freezing points above the
lowest ambient temperature, or if fluids being handled become excessively viscous when
cold. The high viscosity shall be considered in pressure drop and relief device sizing.
i. Inlet piping shall not be susceptible to blockage in the event of failure of other equipment
such as level-control float balls and pieces of mesh blanket/pad.
j. Isolating valves shall be so selected as to minimise the pressure loss in the inlet line. For
ball valves in LPG service, the valves shall be full-bore, to help mitigate potential freezing
problems.
k. Relief valve discharge lines connected to a closed system shall enter the top of the header
or discharge piping system if practical.
l. Generally the isothermal flow method is used to calculate the pressure drop in outlet relief
piping for gas service. See ISO 23251 or API 521 for details. If the adiabatic method is
used in high pressure gas service, then the k value shall be calculated for gas conditions
that exist in the outlet relief piping.
m. Relief valve outlet piping where the velocity can exceed 0,5 Mach shall be evaluated for
potential acoustic fatigue and appropriate supports shall be provided.
10.6.3.5. Relief valve sparing philosophy

Spare relief valves should not normally be installed unless required by regulations, codes, or for
relief valve testing requirements. Even if installed spares are required, they should not be
installed on spare equipment or as spare thermal relief valves on piping in cryogenic liquid
service.
10.6.3.6. Installation of rupture disks

a. The effects of the recoil resulting from the bursting of a disk shall be taken into
consideration in the design of the vessels and piping to which rupture disks are fitted.
Discharge lines should, so far as practicable, be straight.
b. Installation shall be to the manufacturer’s instructions. Both the rupture disk and the
associated retaining surfaces shall be kept clean during field installation.
c. Torque wrenches shall be used when securing a rupture disk in the holder and torque
values used shall comply with manufacturer’s recommendations.
d. Discharge from rupture disks may, if appropriate, be to atmosphere, subject to the
requirements of GP 44-80. If it is desirable to reduce the loss of contents of a vessel or
system, a pressure relief valve in series with a rupture disk may be used, normally
downstream of the disk. Alternatively, two bursting disks in parallel with a 3-way valve
may be used, to permit a change to the second disk upon failure of the first.
e. Rupture disk installation shall be verified by a designated and qualified witness who shall
not be the installer.
f. If a rupture disk is installed in series with a relief valve, or if two disks are installed in
series, a local pressure indicator shall be installed between them, and a permanent vent,
directed to a safe location operating at constant pressure, shall be provided between the
two. If possible, the vent shall be fitted with an excess flow valve.
Page 48 of 54
g. If a burst rupture disk is likely to discharge solid material such as polymer, arrangements
should be considered if appropriate to pass the discharge directly to a second vessel in
which the solid material may be retained, the gaseous element being discharged to
atmosphere, to treatment, or to flare, as appropriate.
11. Responsibilities of owner/operator
The owner/operator shall:
a. Ensure that the contractor has produced an adequate relief and overpressure protection
design basis along with adequate documentation per clause 6 before commissioning a new
unit or starting up a modified unit.
b. Ensure that there is an adequate management system for translating the relief and
overpressure protective requirements into the plant operating procedures and to keep the
relief system design basis and/or plant procedures up-to-date when any pertinent
modification to equipment or throughput is made.
c. Ensure, before construction, that it is possible and convenient to operate the unit with the
requirements for:
1. Clearly identifying locked open or locked closed block valves.
2. Pressure-limiting safety instrumented systems, especially with respect to their
reliability, testing, prevention of bypassing, and maintenance.
3. Compliance with any statutory or local requirements for relief device maintenance.
4. Draining of heat exchangers upon blocking in while the unit is in operation.
5. Maintenance of heat resistant insulation in an adequate condition.
d. Ensuring relief and vent systems have been installed with the necessary valves, blinding
provisions, access, and other support infrastructure to safely isolate, drain liquids, and gas
free these systems during unit shutdowns or maintenance periods.
e. Ensure that there is an acceptable disposal route for hydrocarbon liquids from disposal
system knock out drums and water from knock out drums and water seal drums at all
times.
f. Institute and update as necessary a management system using the Relief and Overpressure
summary to ensure all parts of the overpressure protection system are in place, performing
to requirements and tested at the required frequency while the plant is operating. This shall
include:
1. Pressure-limiting safety instrumented systems at SIL 1 and higher integrity level are
clearly identified with their design details and/or critical set points summarized in the
Relief and Overpressure database summary.
2. Identifying relevant process equipment or components in the Relief and Overpressure
database such as: relief valve tag numbers, sizes, design capacity, and the equipment
or system a relief valve protects; control valves with trim sizes, bypasses, restriction
orifices, locked valves and other facility elements if they impact the overpressure
protection system design.
3. Fire-resistant insulation is verified and maintained in place.
4. Other critical items derived from clauses 6.4.2 through 6.4.11 are identified and
verified as being correctly installed and operational.
g. Develop a Register of Safety Critical Equipment for new plant and create the same from
existing data on all units before modifications are agreed, particularly for modifications to
the relief and overpressure system. The Register of Safety Critical Equipment on each site
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shall also be kept up to date to reflect any relief and overpressure system changes as part of
the plant modification/ MOC procedures.
h. Ensure relief devices on relief and overpressure systems which are designated by the site
as safety critical are included in the Register of Safety Critical Equipment with the
following minimum information:
1. A list of safety critical relief devices with their tag numbers.
2. Identification of other instruments or systems classified as being necessary for safety
critical overpressure or underpressure protection in the process being operated.
3. The inspection or testing interval for safety critical relief devices.
Page 50 of 54
Annex A
(Informative)
Regional annex on local regulation
This GP does not necessarily include the requirements of all local statutory regulations. However, the
UK and many other countries have such regulations affecting overpressure protection. The most
important examples are:
a. The provision of pressure relief devices in steam-raising and compressed air installations.
b. Such restrictions as may be imposed on atmospheric discharge.
c. The method of sizing pressure relief devices.
Page 51 of 54
Annex B-1
(Normative)
Operator intervention decision tree for liquid relief to closed system
with adequate liquid retention or for non-hazardous liquids
For potential liquid relief situations, operator intervention may be considered under certain conditions.
Outside the battery limit it is impractical to ignore operator intervention and allowing for such
intervention is worldwide practice, which is considered acceptable.
NOTES:
1. Relief is not needed unless there is a case in which the inflow is greater than the outflow and the source pressure is greater than
the design pressure of the equipment.
2. To prevent relief, an operator must have an adequate number of separate independent indicators such as level alarms, flow
variation alarm, etc. along with the time to react.
3. Design relief capacity depends on the length of time before a potential incident can occur. If the available time is less than
10 minutes, there is insufficient time to ensure operators can take corrective action and adequate relief capacity or a high
reliability trip is required.
4. If the available response time is greater than 30 minutes, it is unlikely operators would not take appropriate action. This relies on
operators being aware that a problem is occurring. Therefore, it is vital that instrumentation warning the operators that something
is amiss must be in service and fully operational before any equipment is commissioned or placed in operation.
5. If the time is between 10 minutes and 30 minutes (which encompasses most of IMSL ’s cases) the relief design for different
hazard rates depends on the level of indication.
Page 52 of 54
Annex B-2
(Normative)
Operator intervention decision tree for liquid relief without adequate
retention or for hazardous liquids
Page 53 of 54
Bibliography
The following references are current at the time of publication, but are not maintained by IMSL, with
the exception of GP 48-03.
[1] GP 48-03 Guidance on Practice for LOPA - Layer of Protection Analysis.
[2] GPSA Engineering Data Book This Gas Processors Suppliers Association (GPSA) manual has a
section titled “Relief Systems” which covers design and operation of pressure relieving systems for
gas processing plants.
[3] Relief Valve sizing and Simulation Tools Normally relief and flare systems have enough capacity
to handle small increases in flow rates from debottlenecking or minor process changes. If significant
flare/relief system changes are planned or for new facilities, a full flow analysis is required. Tools for
this include:
Visual Flare
FlareNet
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Document No.

Guidance on Practice for

INEOS Manufacturing Scotland Limited

9.6. Centrifugal pumps........................................................................................................44

GP 30-80 Guidance on Practice for SIS - Implementation of Process Requirements.

American National Standards Institute/American Society of Mechanical Engineers

American Petroleum Institute (API)

British Standards Institute (BSI)

CP 2010-2 Code of practice for pipelines – Design and construction of steel

International Electrotechnical Commission (IEC)

Institute of Petroleum (IP)

International Organisation for Standardisation (ISO)

National Fire Protection Association (NFPA)

3. Terms and definitions

4. Symbols and abbreviations

HAZOP Hazard and Operability Study

HIPPS High Integrity Pressure Protection Systems

HIPS High Integrity Protection Systems

LNG Liquefied natural gas

LOPA Layer of Protection Analysis

LPG Liquefied petroleum gas

NGL Natural gas liquids

NPS Nominal pipe size

MOC Management of Change

P&ID Process & Instrument Diagram

PFD Probability of Failure on Demand

PHA Process Hazard Analysis

SIL Safety integrity level

SIS Safety instrumented system

TÜV Technischen Uberwachungsvereine (Technical Inspection Organizations)

US United States of America

5.2. Reference to other codes

6.3. Define stage – Comprehensive relief and overpressure design basis

3. Minimize losses during pressure upset.

6.4. Execute Stage – Relief and overpressure system detailed development

6.4.1. Relief and overpressure summary document

6.4.2. Design philosophy

3. Type of relief device and model number.

6.4.4. Relief loads

6.4.5. Fire areas, fire loads and fire-resistant insulation

6.4.6. Principal (or maximum) flare loads

6.4.7. Pipeline equivalent lengths and header pressure profiles

6.4.8. Control valve and restriction orifice data

6.4.9. Pump impeller data

6.4.10. Other equipment data

6.4.11. Safety instrumented systems (SIS)

6.4.12. Process control loop segregation

6.4.13. Test reports

8. Failure of automatic controls.

3. Overfilling, insufficient ullage for expansion.

7.2. Relief limitation by design

7.3. Pressure-limiting safety instrumented systems

b) Fuel shut-off valves.

7.4. Safety instrumented systems and reliability analysis

7.5. Implication of changes in design conditions

7.6. Emergency depressuring

7.7. Vacuum relief

7.8. Cold service

7.9. External fire condition