DESIGN OF PRESSURE RELIEF, FLARE AND VENT
SYSTEMS
DEP 80.45.10.10-Gen.
January 2010
DESIGN AND ENGINEERING PRACTICE
This document is restricted. Neither the whole nor any part of this document may be disclosed to any third party without the prior written consent of Shell Global
Solutions International B.V., The Netherlands. The copyright of this document is vested in this company. All rights reserved. Neither the whole nor any part of this
document may be reproduced, stored in any retrieval system or transmitted in any form or by any means (electronic, mechanical, reprographic, recording or otherwise)
without the prior written consent of the copyright owner.
DEP 80.45.10.10-Gen.
January 2010
Page 2
PREFACE
DEP (Design and Engineering Practice) publications reflect the views, at the time of publication, of:
Shell Global Solutions International B.V. (Shell GSI)
and/or
Shell International Exploration and Production B.V. (SIEP)
and/or
other Shell Service Companies.
They are based on the experience acquired during their involvement with the design, construction, operation and
maintenance of processing units and facilities, and they are supplemented with the experience of Shell Operating Units.
Where appropriate they are based on, or reference is made to, international, regional, national and industry standards.
The objective is to set the recommended standard for good design and engineering practice applied by Shell companies
operating an oil refinery, gas handling installation, chemical plant, oil and gas production facility, or any other such
facility, and thereby to achieve maximum technical and economic benefit from standardization.
The information set forth in these publications is provided to Shell companies for their consideration and decision to
implement. This is of particular importance where DEPs may not cover every requirement or diversity of condition at
each locality. The system of DEPs is expected to be sufficiently flexible to allow individual Operating Units to adapt the
information set forth in DEPs to their own environment and requirements.
When Contractors or Manufacturers/Suppliers use DEPs they shall be solely responsible for the quality of work and the
attainment of the required design and engineering standards. In particular, for those requirements not specifically
covered, the Principal will expect them to follow those design and engineering practices which will achieve the same
level of integrity as reflected in the DEPs. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting
from his own responsibility, consult the Principal or its technical advisor.
The right to use DEPs is granted by Shell GSI, in most cases under Service Agreements primarily with Shell companies
and other companies receiving technical advice and services from Shell GSI or another Shell Service Company.
Consequently, three categories of users of DEPs can be distinguished:
1)
Operating Units having a Service Agreement with Shell GSI or other Shell Service Company. The use of DEPs
by these Operating Units is subject in all respects to the terms and conditions of the relevant Service
Agreement.
2)
Other parties who are authorized to use DEPs subject to appropriate contractual arrangements (whether as part
of a Service Agreement or otherwise).
3)
Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) or 2)
which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said
users comply with the relevant standards.
Subject to any particular terms and conditions as may be set forth in specific agreements with users, Shell GSI
disclaims any liability of whatsoever nature for any damage (including injury or death) suffered by any company or
person whomsoever as a result of or in connection with the use, application or implementation of any DEP, combination
of DEPs or any part thereof, even if it is wholly or partly caused by negligence on the part of Shell GSI or other Shell
Service Company. The benefit of this disclaimer shall inure in all respects to Shell GSI and/or any Shell Service
Company, or companies affiliated to these companies, that may issue DEPs or require the use of DEPs.
Without prejudice to any specific terms in respect of confidentiality under relevant contractual arrangements, DEPs shall
not, without the prior written consent of Shell GSI, be disclosed by users to any company or person whomsoever and
the DEPs shall be used exclusively for the purpose for which they have been provided to the user. They shall be
returned after use, including any copies which shall only be made by users with the express prior written consent of
Shell GSI. The copyright of DEPs vests in Shell GSI. Users shall arrange for DEPs to be held in safe custody and Shell
GSI may at any time require information satisfactory to them in order to ascertain how users implement this
requirement.
All administrative queries should be directed to the DEP Administrator in Shell GSI.
DEP 80.45.10.10-Gen.
January 2010
Page 3
TABLE OF CONTENTS
1.
1.2
1.3
1.4
1.5
1.6
INTRODUCTION ........................................................................................................5
DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS .........5
DEFINITIONS .............................................................................................................5
CROSS-REFERENCES .............................................................................................7
SUMMARY OF CHANGES SINCE PREVIOUS EDITION .........................................7
COMMENTS ON THIS DEP .......................................................................................7
2.
2.1
2.2
2.3
PRESSURE RELIEF DEVICES..................................................................................8
GENERAL ...................................................................................................................8
RELIEF DEVICE LOCATION, INSTALLATION AND ARRANGEMENT ....................8
PREVENTION OF MALFUNCTIONING OF RELIEF VALVES ................................10
3.
3.1
3.2
3.3
3.4
3.5
3.6
3.7
FLARE AND VENT SYSTEMS ................................................................................12
GENERAL .................................................................................................................12
DESIGN OF PIPING UPSTREAM OF A RELIEF DEVICE ......................................12
SELECTION OF DISPOSAL SYSTEMS ..................................................................13
FLARE/VENT SYSTEM LOAD ANALYSIS ..............................................................17
SIZING OF DOWNSTREAM PIPING SYSTEMS .....................................................20
LAYOUT OF DOWNSTREAM PIPING SYSTEMS...................................................22
BLOCKAGE DUE TO HYDRATE/ICE FORMATION IN DOWNSTREAM
PIPING SYSTEM ......................................................................................................25
FLOW MEASUREMENT REQUIREMENTS ............................................................26
PIPING SYSTEM DESIGN .......................................................................................26
3.8
3.9
4.
4.1
4.2
4.3
KNOCKOUT DRUMS, WATER SEAL VESSELS AND LIQUID DISPOSAL
FACILITIES...............................................................................................................29
DESIGN OF KNOCKOUT DRUMS ..........................................................................29
WATER SEAL VESSELS (SEE APPENDICES 3, 4, AND 5)...................................34
LIQUID DISPOSAL FACILITIES...............................................................................35
5.
5.1
5.2
5.3
5.4
5.5
STRUCTURES FOR FLARE AND VENT STACKS AND LIQUID BURNERS .......37
GENERAL .................................................................................................................37
TYPE OF STRUCTURES .........................................................................................37
HEAT RADIATION LEVELS .....................................................................................38
DISPERSION LEVELS .............................................................................................41
NOISE LIMITS ..........................................................................................................41
6.
6.1
6.2
FLARE AND VENT TIPS..........................................................................................42
GENERAL .................................................................................................................42
FLARE TIP DESIGN CONSIDERATIONS ...............................................................42
7.
7.1
7.2
7.3
7.4
FLARE AND VENT PURGING.................................................................................45
GENERAL .................................................................................................................45
PURGING DESIGN CONSIDERATIONS.................................................................45
PURGE REDUCTION SEALS ..................................................................................47
FLAME/DETONATION ARRESTORS ......................................................................47
8.
8.1
8.2
VENT SNUFFING .....................................................................................................49
GENERAL .................................................................................................................49
VENT SNUFFING REQUIREMENTS.......................................................................49
9.
9.1
9.2
9.3
FLARE PILOTS AND IGNITION ..............................................................................50
GENERAL .................................................................................................................50
FLARE PILOT REQUIREMENTS .............................................................................50
FLARE IGNITION REQUIREMENTS .......................................................................51
10.
10.1
10.2
10.3
10.4
10.5
DOCUMENTATION ..................................................................................................52
ENGINEERING ANALYSIS ......................................................................................52
DISPOSAL SYSTEM SIZING CALCULATIONS ......................................................52
DATA SHEETS .........................................................................................................52
FLARE LOAD DOCUMENTATION...........................................................................52
ELECTRONIC FILES................................................................................................52
DEP 80.45.10.10-Gen.
January 2010
Page 4
10.6
10.7
FLARE EQUIPMENT FILES .....................................................................................52
REVIEW OF DOCUMENTATION .............................................................................53
11.
REFERENCES .........................................................................................................54
APPENDICES
APPENDIX 1
TYPICAL ARRANGEMENT FOR PRESSURE RELIEF VALVE
MANIFOLD ......................................................................................................56
APPENDIX 2
TYPICAL LINE-UPS OF THERMAL EXPANSION RELIEF VALVES .............57
APPENDIX 3
HYDROCARBON FLARE SYSTEM AND H2S FLARE SYSTEM ...................59
APPENDIX 4
WATER SEAL VESSEL DESIGN CHART ......................................................62
APPENDIX 5
TYPICAL DESIGN FEATURES OF WATER SEAL VESSEL .........................63
APPENDIX 6
ARRANGEMENT OF BLOCK VALVE FOR ISOLATING UNIT ......................64
APPENDIX 7
NATURAL GAS F-FACTORS USED IN THE API MODEL TO
DETERMINE RADIATION ...............................................................................65
APPENDIX 8
ESTIMATE OF STEAM INJECTION REQUIREMENTS FOR FLARING........66
APPENDIX 9
PURGE RATES REQUIRED FOR PIPE FLARES ..........................................67
APPENDIX 10
FLARE KNOCK-OUT DRUM DESIGN CONSIDERATIONS ..........................68
DEP 80.45.10.10-Gen.
January 2010
Page 5
1.
INTRODUCTION
This DEP specifies requirements and gives recommendations for the design of pressure
relief, flare and vent systems.
The relieving facilities for pressure vessels shall be in accordance with the following
standards, as clarified, amended or supplemented by this DEP:
•
•
•
•
ASME VIII, Division 1 or 2;
API RP 520, Part I and Part II;
ISO 23251 (identical to API Std 521);
ISO 28300 (identical to API Std 2000).
The prevention of and protection against overpressure and underpressure shall be in
accordance with DEP 80.45.10.11-Gen.
Emergency depressuring
DEP 80.45.10.12-Gen.
and
sectionalizing
shall
be
in
accordance
with
This is a revision of the DEP of the same number dated January 2009; see (1.5) regarding
the changes.
1.2
DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS
Unless otherwise authorised by Shell GSI, the distribution of this DEP is confined to Shell
companies and, where necessary, to Contractors and Manufacturers/Suppliers nominated
by them.
This DEP is intended for use in oil refineries, heavy oil production facilities, heavy oil
upgraders, chemical plants, gas plants, exploration and production facilities and
supply/distribution installations.
When DEPs are applied, a Management of Change (MOC) process should be
implemented; this is of particular importance when existing facilities are to be modified.
If national and/or local regulations exist in which some of the requirements may be more
stringent than in this DEP, the Contractor shall determine by careful scrutiny which of the
requirements are the more stringent and which combination of requirements will be
acceptable with regard to the safety, environmental, economic and legal aspects. In all
cases the Contractor shall inform the Principal of any deviation from the requirements of
this DEP which is considered to be necessary in order to comply with national and/or local
regulations. If possible, the Principal may then negotiate with the Authorities concerned, the
objective being to obtain agreement to follow this DEP as closely as possible.
1.3
DEFINITIONS
1.3.1
General definitions
The Contractor is the party, which carries out all or part of the design, engineering,
procurement, construction, commissioning or management of a project, or operation or
maintenance of a facility. The Principal may undertake all or part of the duties of the
Contractor.
The Manufacturer/Supplier is the party, which manufactures or supplies equipment and
services to perform the duties specified by the Contractor.
The Principal is the party, which initiates the project and ultimately pays for its design and
construction. The Principal will generally specify the technical requirements. The Principal
may also include an agent or consultant authorised to act for, and on behalf of, the
Principal.
The lower-case word shall indicates a requirement.
The capitalised term SHALL [PS] indicates a process safety requirement.
DEP 80.45.10.10-Gen.
January 2010
Page 6
The word should indicates a recommendation.
1.3.2
Specific definitions and abbreviations
CDTP
Cold differential test pressure
CSC
Car Seal Closed
CSO
Car Seal Open
Combustion efficiency
The percentage of the combustible fluid totally
oxidized in the burner. In the case of
hydrocarbons, combustion efficiency is the
weight percent of carbon in the original fluid
that oxidizes completely to CO2.
E&P
Exploration and Production
EHT
Electrical Heat Tracing
FFG
Flame Front Generator
Flare Burner/Tip
The part of the flare where fuel and air are
mixed at velocities, turbulence and
concentrations required to establish and to
maintain proper ignition and stable combustion
HSE-MS
Health, Safety and Environment Management
System
IPF
Instrumented Protective Function
LC
Locked Closed
LNG
Liquefied Natural Gas
LO
Locked Open
LPG
Liquefied Petroleum Gas
LODMAT
Lowest One-Day Mean Ambient Temperature.
NGL
Natural Gas Liquids
OP
Oil Products
Pressure and temperature terms
see DEP 01.00.01.30-Gen.
PFD
Probability of Failure on Demand
POV
Pilot Operated Valve
PRV
Pressure Relief Valve
SIL
Safety Integrity Level
TERV
Thermal Expansion Relief Valve
Very toxic (substances)
substances that are very hazardous for the
environment or human health, as specified in
DEP 01.00.01.30-Gen. (which also identifies
"toxic" substances by reference to chemical
substances databases)
WOBBE Index
An Index which measures the combustion
value of a fuel and interchangeability of fuels
where Wobbe Index = gross heating value
divided by the square root of the specific
gravity of the fuel (relative to air)
DEP 80.45.10.10-Gen.
January 2010
Page 7
1.4
CROSS-REFERENCES
Where cross-references to other parts of this DEP are made, the referenced section
number is shown in brackets. Other documents referenced in this DEP are listed in (11).
1.5
SUMMARY OF CHANGES SINCE PREVIOUS EDITION
This is a revision of the DEP of the same number dated January 2009. The only changes
have been to indicate process safety requirements by the use of the capitalised term
"SHALL [PS]".
1.6
COMMENTS ON THIS DEP
Comments on this DEP may be sent to the DEP Administrator at standards@shell.com.
Shell staff may also post comments on this DEP on the Surface Global Network (SGN).
DEP 80.45.10.10-Gen.
January 2010
Page 8
2.
PRESSURE RELIEF DEVICES
2.1
GENERAL
A pressure system can be protected by one or more relief valves, provided it is ensured
that the relief path remains open under all conditions. It SHALL [PS] be established that
blockage cannot occur due to valve closure, freezing, solidification, fouling, sublimation,
damage of internals, etc., which could cause a section of the system to become isolated
with no means of overpressure protection.
2.2
RELIEF DEVICE LOCATION, INSTALLATION AND ARRANGEMENT
2.2.1
Relief device location and installation
To ensure protection of the whole system, the relief assembly should be located, where
practical, in the upstream part, i.e. where the highest pressure occurs, and as close as
possible to the source of overpressure.
Relief devices shall be connected to the protected equipment in the vapour space above
any contained liquid or to piping connected to the vapour space. This means that the relief
device is preferably connected to the highest point of the vessel. An exception can be made
if the vessel is fitted with a demister mat. In this case the relief connection shall be
upstream of the mat. The relief valve may be installed downstream of the demister mat if
the relief flow is not greater than the operating flow and the operating flow due to the
emergency situation will be stopped.
If a system is subject to fouling that may remain undetected for considerable time, this
should be taken into consideration while determining relief valve location. Particularly for
multiple vessels protected by a single relief valve, when the velocities within a relief path
significantly exceed those during normal operation, the potential for undetected fouling or
restrictions due to internal damages caused by high velocities shall be considered.
Spring-loaded, pilot-operated or air-assisted relief valves, and thermal expansion relief
valves (TERVs) shall always be installed in the upright position. The inlet and outlet piping
shall be installed without pockets to ensure that liquid does not accumulate at the relief
valve outlet or inlet. An exception to the latter may be made for TERVs, since a position
close to the protected equipment is preferred. However, it should be ensured that the
discharge pipe will not be plugged by freezing or solidification. Many thermal expansion
relief valves are susceptible to failure of the body-to-nozzle connection when piping loads
apply a bending moment to the valve. Care shall be taken to support and align the inlet and
outlet piping properly.
Relief devices connected to a closed relief system shall be located above the relief header.
Relief device outlet lines should be connected to the top of the header, or at least so that
the header cannot drain back into outlet lines.
NOTE:
If a discharge line is filled with liquid (e.g. for relief valves handling liquids), a sudden opening of the
relief valve could cause an instantaneous pressure peak, which could cause damage and possible
loss of containment.
If the relief devices cannot be put above the header, they shall be lined up to discharge into
a local drain vessel sized to contain any condensation that could accumulate in this low
spot. This approach shall require approval of the Principal and should not be used for liquid
discharges. This line shall be locked or car-sealed open and adequately sized: DN 50
(NPS 2) for headers up to DN 200 (NPS 8), DN 100 (NPS 4) for headers up to DN 400
(NPS 16) and DN 150 (NPS 6) for headers larger than DN 400 (NPS 16). The local drain
vessels shall be equipped with a high level alarm, set as low as possible to provide a
maximum hold up.
Alternatively, if the problem of elevation is confined to a few valves, and if the Principal
agrees, outlet lines to the header shall be heat-traced from the relief device to the highest
point of the line. Such an arrangement is not permitted for relief devices discharging to a
medium which can leave a deposit. The heat tracing may be omitted if the relief valve and
DEP 80.45.10.10-Gen.
January 2010
Page 9
connecting header only handle products which vaporise completely at the lowest ambient
temperature and there is no possibility that vapours in the flare system can condense,
freeze, or cause corrosion.
Relief devices require periodic inspection and maintenance and hence they should be
easily accessible.
For liquids with a high pour point, insulation and heat tracing of piping upstream and
downstream of the relief devices should be applied. The piping upstream, and sometimes
also downstream, of the relief device may be flushed with a low viscosity hot process fluid.
If the downstream lines are flushed, a local knockout drum shall be provided. This knockout
drum will prevent introduction of any liquid into the main flare system. The flushing rate
shall be such that only a small layer of liquid will be present in the relief header. This
introduction of a liquid into the relief system shall not cause a slug flow due to other vapour
discharges.
2.2.2
Spare relief valves
Different relief valve arrangements may be used depending on the on-stream factor
required and the testing interval for the relief valve if different from the inspection interval of
the protected equipment. This determines whether a spare relief valve or a location where a
spare relief valve can be installed, is appropriate. Relief valves with the same inspection
intervals as the protected equipment and with very low frequency of discharge do not have
to be equipped with a spare. If economically justified, relief valve bypasses may be
considered if it is practical to use the bypass to depressure equipment during shutdowns.
2.2.3
Application of relief device isolation valves
Where possible, the approach should be to use a relief device arrangement which does not
utilise any isolation valves. This approach eliminates the possibility of a relief device being
isolated in error. However, in this case inspection and maintenance of the relief device, vent
or flare system, and any other equipment connected to it, requires the complete shutdown
of the whole system. For example, pressure relief valve isolation valves would not be
required for a positive displacement pump that relieves back to pump suction whenever the
pump is taken out of service for the purposes of PRV maintenance/inspection. If the normal
operating pressure is atmospheric pressure (e.g. in an atmospheric storage tank), no inlet
isolation valve is required either.
If a complete shutdown is not practicable, then the use of separate flare or vent systems for
each part of the plant which can be shut down independently could be considered.
However this could lead to a costly design.
In light of the above, it may be necessary to use isolation valves either to isolate the
individual relief device or to isolate a complete plant section. If isolation valves are used to
isolate relief devices, there is a basic difference between the need for an inlet valve or for
an outlet valve. An inlet valve is needed if the process cannot be shut down. An outlet valve
is needed if the relief header cannot be taken out of service or if the discharge point is not
within the boundaries of the protected equipment that is being taken out of service.
A single relief valve (without a spare) connected to a relief header which cannot be shut
down shall have only an outlet isolation valve. A multiple relief valve arrangement (including
a spare) shall have an inlet isolation valve and an outlet isolation valve. The spare relief
valve could be substituted by an open spool piece (in fact a dummy RV with the same
flange geometry). Maintenance isolation valves may be provided on flare header laterals
based on the requirement to shutdown and isolate individual units. Butterfly valves shall not
be used in relief device inlet and outlet piping.
A slip blind SHALL [PS] be able to be installed in piping downstream of pressure relief
devices that discharge into a closed system unless the closed system can be shutdown or
has an isolation block valve with an upstream slip blind in the downstream piping.
DEP 80.45.10.10-Gen.
January 2010
Page 10
2.2.4
Isolation valve operation control
It is vital to ensure that the relief device isolation valve and all other valves in the relief path
are in the proper position. The method for managing the valve positions SHALL [PS] be
consistent with the site's HSE-MS.
The preferred method for controlling this is to use valve interlocking systems on block
valves used on the inlet and outlet of relief valves, their spares and their open spool pieces
(in accordance with DEP 80.46.30.11-Gen.).
Alternatively, valve locks or car seals may be employed provided there are strict
administrative controls in place. With the valve locking method, the correct fully open or
fully closed position can be identified by having a locking system with two keys with
different colour codes, e.g. yellow and green. When the yellow key is in the key cabinet
mounted in the control room, it is known that the isolation valve is locked fully closed.
When using the valve locks/car seal methods, installed spare PRVs shall have the inlet
valve Locked Closed (LC) or Car Seal Closed (CSC) and the outlet valve Locked Open
(LO) or Car Seal Open (CSO). PRV bypass valves are normally closed (NC) and do not
required key locks or car seals. Emergency depressuring valves do not provide pressure
relief but, since they do play an important role, the isolation valves for these SHALL [PS] be
LO or CSO.
To indicate the proper operation of the upstream block valve, a vent connection shall be
provided between the upstream block valve and the relief valve.
For pipeline TERVs (which may be removed while the system is in operation), a single relief
valve with upstream and downstream isolation valves should be provided. Strict procedural
controls should ensure that the line is not shut in while the relief valve is out of service. The
block valves may be car sealed open rather than locked open, in a manner to be agreed by
the Principal and consistent with the site’s HSE-MS.
2.2.5
Balanced PRV bonnet venting
Balanced PRVs in very toxic service or balanced PRVs that discharge into a closed system
containing very toxic substances shall have the bonnet vent discharge to a safe location.
The amount of toxic gas leakage shall be estimated assuming complete failure of the
bellows with the flow limited by the annular area between the disk holder and the guide,
vent hole in the valve guide plate (if the vent hole is present), and vent opening in the valve
bonnet. Dispersion analysis shall demonstrate that the toxic gas levels are acceptable.
Providing a continuous purge at the relief valve outlet could reduce these levels. As an
alternative to performing dispersion analysis, the bonnet vent discharge can be located 8 m
(25 ft) away from the potential location of personnel. If the vent piping is installed it shall be
designed to prevent ingress of rain and shall have no pockets. For a balanced PRV in very
toxic service a balancing piston may also be considered.
2.3
PREVENTION OF MALFUNCTIONING OF RELIEF VALVES
2.3.1
Relief valves affected by hydrates and freezing
The Joule-Thomson effect, occurring across the relief valve when relieving, may lower the
temperature to within the hydrate or ice formation region. Due to the high velocities, there
will likely be no problem of relief valve blockage at relieving conditions. For additional
details, see (3.7).
Valve blockages could occur, however, due to small leaks across the relief valve seat. To
prevent this blockage, heat tracing/insulation SHALL [PS] be provided around the relief
valves that can be affected by hydrates and freezing.
If a relief device and/or its inlet/outlet piping requires heat tracing to ensure an open relief
path, then:
a. Steam tracing system shall have dual circuits (i.e., dual supply, tracers, and traps).
DEP 80.45.10.10-Gen.
January 2010
Page 11
b. Electric tracing system may use diagnostic alarms instead of dual tracing circuits.
These alarms shall be segregated from non-critical heat tracing alarms and
appropriately classified by the alarm management work process.
The integrity of the heat tracing shall be ensured by proper instrumentation including low
temperature alarm on the valve/piping itself. In addition, the injection of hydrate inhibitor
may be considered.
Relief valves or depressuring valves protecting a cold process [i.e. lower than 0 °C (32 °F)]
and releasing into a common flare and relief system could be exposed at the downstream
side to a water-saturated environment. Water from this environment may condense and
freeze and may cause the relief valve or depressuring valve to stick close.
Removable insulation covers shall be used on relief devices if insulation is required.
2.3.2
Relief valves affected by corrosive process fluids
Corrosive fluid, e.g. sulfolane, HF, HCL, may attack the internals of the relief valve. Proper
material selection is required to guarantee the suitability of the relief valve. However, the
corrosivity of the fluid could be such that a proper material is virtually unobtainable.
Furthermore, a relief valve cannot be assumed to be fully leak-tight and corrosive fluid may
then enter the flare/relief system. To prevent the fluid from corroding and/or passing
through the relief valve, one of the following preventive actions shall be taken:
• purging or flushing of the inlet piping with a clean fluid which can be accommodated by
the process.
• installation of a bursting disk upstream of the relief valve.
2.3.3
Relief valves affected by solidifying process fluids
Although relief valves are installed at the highest point of the vessel, which normally
contains vapour, it shall be assumed that liquid may reach the relief valve. This could be by
condensation or by liquid entrainment during emergency relief action. This liquid could
solidify (e.g. high pour point liquid) or form coke and affect the operation of the relief valve
and downstream piping. In this case either or both of the following preventive actions
SHALL [PS] be carried out:
• provision of heat tracing at the relief valve and along its inlet and outlet piping
• purging or flushing of the inlet and outlet piping with a clean fluid that can be
accommodated by the receiving system.
DEP 80.45.10.10-Gen.
January 2010
Page 12
3.
FLARE AND VENT SYSTEMS
3.1
GENERAL
In order to ensure safe disposal of flared and vented streams, certain factors shall be taken
into consideration when designing the pipework upstream and downstream of the relief
device. These are covered in this section, together with certain design methods.
Mechanical design and installation of piping systems shall conform to API RP 520 Part II.
All disposal systems, including those that go back to process, shall be free draining and
shall be designed without pockets. Relief stream disposal shall be consistent with the
environmental or sustainable development premises specified for the project or the plant.
Wherever possible, the need for disposal should be avoided (by process changes or by
raising the design pressure).
3.2
DESIGN OF PIPING UPSTREAM OF A RELIEF DEVICE
Piping upstream of a relief device should be designed with as few flow restrictions as
possible and SHALL [PS] not be pocketed.
If two or more relief valves (spares not counted) are fitted on one connection, the crosssectional area of this connection shall be at least equal to the combined inlet areas of the
valves, and the pressure drop requirement in (3.2.1) SHALL [PS] apply for the combined
flow of the valves.
Relief valves on cold process streams shall have an uninsulated inlet line of sufficient
length to prevent icing of the relief valve, in particular the disk and spring. Alternatively, heat
tracing may be required. Special attention shall be paid in this respect to valves, which
discharge into the atmosphere, i.e. in those having open outlets that may become blocked
with ice.
To avoid the need for special high temperature materials, relief valves on hot process
streams may be installed by means of an uninsulated length of inlet line, creating a cold
dead ended leg between the process stream and the relief valve. However, consideration
should be given to vapour condensation and deposit formation and solidification, which
could affect operation of the relief valve.
3.2.1
Inlet piping pressure losses
All relief devices, except directly mounted tank pressure vacuum vents, require inlet loss
calculations. Based on the rated relief valve capacity at the allowable overpressure, the
pressure drop in the inlet piping and fittings for new facilities shall not exceed 3 % of the
valve set pressure (this is to avoid chatter, which may result in significant seat damage and
loss of capacity). Exceptions to this requirement are only allowed in the case of a pilotoperated valve with a suitably arranged remote pilot connection close to the source of
overpressure.
The above is especially applicable to relief valves handling gas or vapour. Relief valves in
pure liquid service require special attention, since in this case chatter may also be caused
by the acceleration of the (non expandable) liquid in the inlet piping: a change in pressure
amounting to more than 3 % of the set pressure will readily occur and cause valve chatter.
In this case the likelihood of chatter can be limited by installing a relief valve with a special
liquid trim (linear flow characteristic). To avoid chatter, the relief valve in liquid service could
be equipped with a vibration damper. Inspection and maintenance of the damper is
required to assure its proper operation. An alternative to this could be to use pilot operated
relief valves with a modulating action. In this case, the liquid shall be clean and not affect
proper operation of the pilot valve. Any non-metallic parts (e.g. elastomers) shall be
resistant to the fluid handled by the relief valves.
For existing systems, an inlet pressure drop exceeding 3 % of the valve set pressure may
be allowed if the engineering calculations and relief device performance history have been
reviewed and approved by the Principal.
DEP 80.45.10.10-Gen.
January 2010
Page 13
For systems containing pressure relief valves in combination with rupture disks, the
pressure drop across the rupture disk shall be ignored if the inlet losses are based on the
PRV's capacity adjusted with the certified Combination Capacity Factor. However, if inlet
loss assessment involves rigorously calculating the inlet pressure of the PRV, the effects of
the rupture disk shall be taken into account.
Hydraulic calculations shall be performed for all permanent line losses. Recoverable
pressure drop shall not be counted.
3.3
SELECTION OF DISPOSAL SYSTEMS
Streams requiring disposal are:
-
relief vapour and/or liquids;
-
depressuring vapours;
-
any operational waste streams that do not have a more suitable outlet.
In selecting a means of disposal for these streams it is important to find a solution in which
all streams are handled with the smallest number and diversity of systems and individual
outlets.
3.3.1
Flaring versus venting
Wherever possible disposal streams shall be collected in a closed system and directed
preferentially to a flare, unless they can be sent back into the process or stored. To limit
flaring, the use of a flare gas recovery system shall be considered.
Disposal by venting directly to atmosphere for facilities other than storage shall only be
allowed with approval of the Principal and where the following criteria are met:
•
Disposal by venting is allowed by local regulations;
•
The release of flammable vapours occurs only in an emergency situation;
•
The vapours are lighter than air. Gases shall be considered to be lighter than air if the
actual density of the gas after release, taking into account the cooling associated with
expansion, is less than 0.9 times the density of the air in the area at 15 °C (59 °F);
•
Concentrations of toxic and/or corrosive components in the dispersed vapour cloud will
not reach harmful or irritating levels on nearby work levels (platforms) and outside
property limits (see 5.4). Calculations of effluent emissions shall be submitted for the
approval of the Principal;
•
In the event of accidental ignition of the vent, flames shall not impinge upon adjacent
equipment and the thermal radiation to equipment or personnel shall be within the limits
of (5.3.2);
•
The vapours are such that the condensation of flammable, corrosive or toxic
substances cannot occur. This shall be calculated as outlined in API Division of
Refining, Volume 43, III. The LODMAT value shall be used in this calculation;
•
The stream does not contain any flammable, combustible or toxic liquids;
•
The (hot) vented stream cannot self-ignite;
•
Dispersion analysis, based on ¼ of the flow through any individual pop action pressure
relief device connected to the vent, shows that the limits of flammability satisfy the
criteria outlined in (5.4);
•
Dispersion analysis, based on the full range of possible flows through any individual
modulating pressure relief device connected to the vent, shows that the limits of
flammability satisfy the criteria outlined in (5.4);
•
The vent system is provided with a knockout drum, see (4.), to prevent the release of
any non-toxic or incombustible liquids;
DEP 80.45.10.10-Gen.
January 2010
Page 14
•
The systems being protected by relief devices or piping discharging to the vent system
cannot contain any hydrocarbon liquid that will be above flash point if released.
Additional considerations in deciding whether to vent to atmosphere or flare the disposal
streams are:
• the impact on the environment;
• the safety and integrity of the disposal system, taking into account that disposal streams
could contain products which are not combustible;
• economic evaluations;
• the risk associated with the release of hydrocarbon liquids to atmosphere.
A common vent system may be provided if it is economically more viable or if the
requirements for safe venting of relief and depressuring streams cannot be met by
providing a limited number of individual vent outlets because of the magnitude of the
streams. In this case it shall be assured that the disposal streams do not contain products
which, when mixed with other relief streams, may endanger the operation of the vent
system through exothermic reactions or the formation of deposits, freezing, solidification
etc.
Venting of storage facilities (e.g. spheres and tanks) to atmosphere is generally allowed;
however, for LNG and LPG storage, these relief streams shall not be connected to a
common vent system (see also DEP 30.06.10.12-Gen.). The criteria outlined above should
also be met while considering storage facility venting. Environmental regulations or HSE
premises specified for the project or the plant may dictate additional environmental controls.
Streams that result from overfilling of storage facilities may be vented to the atmosphere if
the storage facility is isolated with respect to process areas and other facilities, and if the
stream does not create a serious hazard due to the presence of ignition sources or
personnel.
A risk assessment SHALL [PS] be performed for any atmospheric relief streams that might
include toxic, flammable, or combustible liquids to determine the appropriate safeguards to
prevent release of the liquids to atmosphere.
In addition to the above, utility streams (e.g. air, nitrogen, steam, water) and streams which
are not foreign to the atmosphere may be vented without environmental reservations
subject to local regulations. However, safety near the point of discharge shall be
considered, i.e. factors such as temperature, noise, local concentrations of carbon dioxide
and nitrogen, potential for rainout of hot water, ice fog, potential for freezing and generating
large ice chunks, etc.
3.3.2
Disposal back into process or storage
Consideration shall be given to the lining up of relief valves for discharge into an
unrestricted, lower-pressure part of the same process system, or into a suitable receiving
(storage) vessel.
This line-up should be used for streams which cause problems when flared or vented or,
particularly in the case of liquids, where their recovery is of value. It can also be used to
temporarily take away the initial high load on a flare relief system during an emergency
depressuring situation. The pressure in the receiving system into which the relief valve
discharges generally varies between certain values. The maximum value of this pressure
shall be taken as the constant superimposed backpressure for the determination of:
-
relief device capacities;
-
the maximum allowed Cold Differential Test Pressure (CDTP) for conventional relief
valves.
The maximum value of the pressure in the receiving system shall generally be taken to be
equal to the set pressure of the relief valves protecting this receiving system.
However, the pressure in the receiving system can be assumed to be the maximum
operating pressure therein if it can be shown that:
DEP 80.45.10.10-Gen.
January 2010
Page 15
-
none of the contingencies resulting in operation of the relief valve under consideration
would also overpressure the lower-pressure equipment;
-
the load imposed by the higher-pressure relief valve would not result in a pressure rise
that will exceed the maximum operating pressure in the equipment under lower
pressure;
-
the maximum relieving pressure in the low pressure vessel does not exceed the bellows
rating of the higher pressure relief valve (if applicable).
If the discharge of the higher-pressure relief valve is handled by the relief valves of the
lower pressure system, it SHALL [PS] be checked that these are adequate for the
additional load.
If the relief valve is of a conventional type, it shall be checked that the lowest pressure of
the process system into which the relief is discharged does not cause inadvertent discharge
of the relief valve with its spring setting (CDTP) determined on the basis of the highest
constant superimposed backpressure. For this check, the lowest pressure of the process
system under all foreseen process conditions (including start-up) shall be used.
Non-flammable chemical streams that do not have toxic gases may be discharged by
piping to a recovery sump or to a chemical sewer.
Two-phase releases that discharge back to process shall be evaluated for slug flow; see
(3.9.3).
3.3.3
Segregated flare systems
Multiple flare system arrangements may offer significant advantages or may be required
based on an analysis of the streams that require disposal.
Segregated flare systems may be required in order to:
i)
segregate sources of release into high and low pressure systems. This may be
required to accommodate the differing back pressure limitations of individual
relief/depressuring devices, or to enable a high pressure low radiation tip to be used
with a consequent saving on flare structural requirements. This may also mean that
only the low pressure gas requires assistance in order to burn cleanly;
ii)
segregate sources with widely differing potentials for liquid release;
iii)
segregate sources of cold, dry gas from significant quantities of warm, moist gas and
thereby avoid the possibility of freezing and hydrate formation. A relief header after
passing a cold stream will be cold. If a warm, moist gas then passes, hydrates or ice
could be formed and block the relief header;
iv)
segregate corrosive or potentially corrosive fluids (e.g. CO2 and H2S) from noncorrosive or moist fluids;
v)
meet requirements dictated by the plant geometry or layout and/or economics;
vi)
segregate disposal streams containing products which, upon mixing with other relief
streams, may endanger the operation of the flare system through exothermic reactions
or may result in formation of deposits or solidification of entrained heavy liquids.
The selected design should use the minimum practicable number of separate systems but
remain operable and safe under all foreseeable conditions. The systems installed may be
totally independent, or may share common facilities such as flare knockout drums and flare
tips in certain circumstances.
Streams containing highly corrosive or very toxic vapours SHALL [PS] be neutralised
before being discharged into the flare system.
When the requirement for a high and low pressure disposal system is considered, the relief
valve set pressures present in the system shall be taken into account. If there are a large
number of high pressure sources with large gas volumes and relatively few low pressure
sources, then generally it is more economical to install one high pressure relief header and
DEP 80.45.10.10-Gen.
January 2010
Page 16
one low pressure relief header. An economic analysis is usually required to ascertain the
optimum number of flare systems, and to which system each relief device should
discharge.
3.3.4
Disposal of TERV discharge
TERVs should discharge back into the process, the storage system, or a plant disposal
system (for more details see Appendix 2). However, if the discharged liquid cannot be
accepted in any of these outlets, TERVs may discharge into an open drainage system,
subject to local regulations and depending on any possible impact on the environment.
Light hydrocarbons should be discharged only to a location where vapours may safely
disperse, and only with the agreement of the Principal.
Systems containing very toxic fluids SHALL [PS] never be discharged into an open
drainage system.
Liquids containing components which impair gravity separation emulsifying agents or spent
chemicals which tend to flocculate upon dilution shall not be discharged into the oily open
drainage. Liquids containing components that impair biological activity shall not be
discharged into open drainage systems leading to a biological waste treatment unit.
3.3.5
Disposal of hydrogen sulphide gas
Streams which are rich in hydrogen sulphide (e.g. relief streams from sulphur recovery
plants) shall not be discharged into a common HC flare or vent system unless it has been
designed for this purpose. This precaution can reduce corrosion and plugging issues and
prevent the accumulation of pyrophoric iron sulphide deposits.
Besides sulphur compounds, the crude oil could contain nitrogen compounds. In some
conversion processes (e.g. hydrocracking and cat cracking) these compounds will partly be
converted to ammonia. When entering the flare and relief system, ammonium salts such as
ammonium sulphide and ammonium carbonate can be formed. These salts are not formed
when the temperature is higher than 60 °C, in which case the ammonia will exit the flare
and relief system as a gas and formation of ammonium deposits is prevented. This is one
of the reasons why an H2S flare header should be heat-traced.
For the reasons mentioned above, H2S-rich streams shall have a separate line-up,
preferably a separate flare stack equipped with a tip of the air pre-mix ("Bunsen") type. For
large H2S releases, and if the Bunsen burner nozzle diameter would need to be larger than
150 mm (6 in), the installation of gas assist flare burner tips shall be considered since large
Bunsen burner nozzles are impractical.
The installation of a separate sour gas flare implies additional capital expenditure and may
not be practical for existing facilities. For this reason, feeding the stream into the
hydrocarbon flare should be considered. The following factors should be considered before
deciding that a separate H2S flare need not be installed, in which case the sour gas release
can be tied into the HC flare:
1)
continuous HC release with an H2S content < 2 % by volume;
2)
intermittent HC release (only during start-up and shutdown) with an H2S content <
20 % by volume, provided this stream is less than 10 % by volume of the total
continuous HC release rate;
3)
emergency HC release (e.g. PRV, emergency depressuring) with an H2S content <
50 % by volume.
The combustion efficiency of a large diameter open pipe flare is poor when gas at low exit
velocities has to be flared. Good combustion can only be guaranteed if a minimum exit
velocity of 0.5 m/s is maintained. When hydrogen sulphide rich gas has to be flared,
incomplete combustion may cause a hydrogen sulphide smell resulting in complaints by
people in the vicinity. At a low exit velocity back burning may occur, causing sulphide stress
corrosion, especially below the refractory. This means that when H2S rich gas has to be
released into the HC flare system, more combustible purge (sweep) gas has to be injected
DEP 80.45.10.10-Gen.
January 2010
Page 17
as well on account of the larger size of the flare, which could offset the saving on capital
expenditure.
If a hydrogen sulphide flare relief system is used, this SHALL [PS] be heat-traced up to 4 m
below the top of the stack. No water seal vessel SHALL [PS] be applied. Header materials
shall be carbon steel, except for the top 4 m of the hydrogen sulphide stack, which shall be
of type 310S stainless steel.
The knockout drum for the hydrogen sulphide flare system SHALL [PS] conform to the
requirements of (4.1). Since no water seal vessel has to be installed, the design pressure of
the knockout drum SHALL [PS] be 7 bar (ga). To prevent flashback and consequential
detonation, purge gas SHALL [PS] be used. In addition, facilities for injection of assist gas
in the flare for adequate combustion and plume buoyancy SHALL [PS] be provided.
3.3.6
Discharge of oxygen-containing gas
Streams that contain oxygen (or air) SHALL [PS] not be discharged into a common flare or
vent system on a continuous basis, unless this system is free from H2S and no flammable
mixtures are created. These streams typically originate from plant sections that operate
under sub-atmospheric pressure or vacuum, where some air will inevitably be drawn in.
NOTE:
Even small amounts of oxygen can convert H2S into elemental sulphur by partial oxidation (Claus
reaction). The generation of elemental sulphur in the common flare or vent system could give rise to
serious local blockages over a prolonged period. Such blockage will become apparent only during a
major relief load, and could remain otherwise undetected.
Flammable mixtures with gas and oxygen (air) SHALL [PS] not be permitted in a common
flare or vent system due to the risk of a detonation blast wave inside the header piping. The
ignition source in the header could be pyrophoric deposits or discharges of static electricity.
This type of explosion could lead to pressures in excess of the header's design pressure
and severe loss of integrity.
If an oxygen-containing stream is considered for intermittent routing to the flare system
such as on trip of a waste gas burner, a sufficient fixed purge of fuel gas or nitrogen
SHALL [PS] be added and an oxygen analyzer/trip shall be provided. The stream
SHALL [PS] not be released automatically to the flare system.
Relief devices in oxygen
DEP 31.10.11.31-Gen.
3.3.7
service
SHALL
[PS]
meet
the
requirements
of
Atmospheric and low pressure tank vents
For the pressure relief and venting of low-pressure storage tanks, including refrigerated
storage tanks, reference should be made to ISO 28300 and DEP 34.51.01.31-Gen. Due to
the very low design pressures of the tanks it is not normally permissible to connect them to
the flare headers, since the backpressure in this system is generally too high. In addition,
such tanks create a potential source of air ingress into flare systems if the vacuum side of
the PVRV were to open.
3.4
FLARE/VENT SYSTEM LOAD ANALYSIS
To determine the backpressure at the relief valves the required relief flow rates can be
used.
In order to size the main headers the maximum load that can be expected at any one time
SHALL [PS] be ascertained. This requires careful consideration of potential occurrences
that could affect several vessels or systems and cause them to relieve simultaneously. The
maximum load is not necessarily the largest mass flow rate at any time but rather it is the
flow that will impose the highest backpressure / set pressure ratio for one of the relief
valves linked to the system.
DEP 80.45.10.10-Gen.
January 2010
Page 18
The following relief scenarios (where applicable) could affect multiple pressure systems
simultaneously:
Relief Scenario
Multiple Discharges
from a Single
Process Unit
Multiple Discharges
from Multiple
Process Units
Cooling Water Failure
Yes
Yes
Partial Power Failure
Yes
Yes
Total Power Failure
Yes
Yes
General Steam Failure
Yes
Yes
General Instrument Air
Failure
Yes
Yes
Fire
Yes
No (see Note)
NOTE:
Unless a fire circle would affect equipment assigned to different process units
there will not be fire relief loads from more than one process unit at a time. More
than one fire at a time in a plant shall not be assumed.
Since the simultaneous occurrence of two or more unrelated contingencies is unlikely,
unrelated contingencies should not be used as a basis for determining the maximum
backpressure / set pressure ratio. Therefore, while lines from individual relief valves should
be sized for the maximum calculated design flow, sections of a main header or sub-header
should be sized for a specific maximum contingency. Care should be taken to ensure that
one contingency could not remain undetected for a long period of time; otherwise a
coincidental second contingency shall be considered.
Each facility (e.g. process unit) has a maximum relief load that is unique to that facility.
Normally, the maximum unit relief load constitutes the sizing basis for process unit
subheader and includes one or more of the following items:
i)
relief rates from a total utility failure (e.g. total power failure, general steam failure,
general instrument air failure, and cooling water failure);
ii)
effects of a partial utility failure (e.g. partial power failure);
iii)
maximum flow rate in the event of a single relief scenario;
iv)
maximum flow rate in the event of emergency depressurisation;
v)
maximum flow rate in the event of fire per fire circle scenario. There may be several
fire circle scenarios that need to be considered for flare piping design.
The main flare header SHALL [PS] be sized for both of the following cases:
•
flare loads from each individual unit;
•
simultaneous flare loads from multiple units.
The impact on the common discharge system design produced by relief flows from
connected process units as the result of a utility failure shall be calculated by taking 100 %
of the quantities established for the relief and depressuring load for each unit in turn,
together with 50 % thereof for the other units. The “low rate” depressuring (refer to DEP
80.45.10.12-Gen.) should be included in the assessment, if applicable. The rationale for
choosing 50 % of the other units rather than a greater value is because the actions of
operators and instrumentation control during the common mode failure will tend to limit the
peak flows, and stagger the times of occurrence. Moreover not all relief valves will
discharge at the same time, due to the dynamics of the process. It is hereby assumed that
the actual maximum flare relief load is always smaller than that determined by this rational
approach. If it is determined that multiple units will discharge simultaneously, the relief
loads from those units should be taken at 100 %. The individual relief valve backpressure
shall be taken as the highest value in any one of the above combinations.
DEP 80.45.10.10-Gen.
January 2010
Page 19
An alternative to the above is to make a statistical analysis of the process units, which
could generate relief loads, taking into account the classification of Instrumented Protective
Functions (IPFs); see (3.4.1).
Flare loads from systems with depressuring valves shall include the larger of:
a. the required relief flow for the scenario;
b. the peak depressuring valve flow for the scenario.
Depressuring valve flows shall be considered only for scenarios in which the use of the
depressuring valve is expected or procedurally required (e.g., fire case, scenarios which
could lead to reactor overtemperature conditions).
The standard design basis for flare header hydraulics for the fire scenario SHALL [PS]
assume that all emergency depressuring systems that protect equipment within a common
fire circle are activated. However, the emergency depressuring valves intended for other
scenarios (e.g., power failure) may also be operated. The effect of opening additional
emergency depressuring valves within the unit shall be evaluated. Depending on the risk
this may lead to flare system design modifications.
Relief flows and depressuring flows for fire conditions shall be calculated by assuming a fire
in only one of the established potential fire areas, thus taking each fire area in turn.
Flare loads from systems with pressure control valves shall be the larger of:
a. the required relief flow for the scenario;
b. the maximum control valve flow (100 % open with system at relieving conditions).
NOTE:
If the control valve flow is determined to be higher than the relief flow, the system will never reach the
assumed full relieving pressure. If this is the case and the control valve flow is a significant flare load,
it may be cost effective to evaluate the system at pressures at which the vapour generation rate
equals the control valve’s capacity.
Vessels that are protected by only a vent line to the flare (i.e., no PRV) introduce fire relief
loads that shall be taken into account.
Routine operational vents shall be assumed to exist as a background flare load unless it
can be shown that such loads would be redundant.
3.4.1
Use of Instrumented Protective Function for flare load mitigation
To reduce the total load on the common relief system, the use may be considered of
Instrumented Protective Functions (IPFs) consisting of one or more initiators, a Logic
Solver, and one or more Final Elements on a pressure system to eliminate the cause of
overpressure (e.g. close the heat input and thus prevent the individual relief case).
Designing the IPFs for flare load mitigation is a complex problem. Detailed guidance on the
design and verification of instrumented flare load mitigation systems can be found in report
GS 05-50616. Application of the method requires approval of the Principal. The IPF
approach specifies the required Safety Integrity Level as SIL-3 for the entire flare system
with respect to backpressure analysis. For non-backpressure analysis, (e.g. thermal
radiation, noise, velocity, and environmental analysis) the overall SIL shall be defined with
the use of the risk matrix in DEP 32.80.10.10-Gen.
The IPF approach considers the following steps:
•
Definition of general (or global) relief scenarios and load determination;
•
Construction of the flare header network model and determination of the back
pressures for the unmitigated flare load (base load plus IPF mitigated loads);
•
Identification of IPF candidate systems based on controlling general scenarios, limiting
equipment in the flare system, IPF application points and configuration;
•
Determining the most detrimental IPF load (the load which, if the IPF fails to function,
results in the highest backpressure effect on a PRV). Depending on system
configuration, the most detrimental IPF load may not be the largest IPF load;
•
Confirming the hydraulic design adequacy for the base flare load (occurring when all
associated IPFs work properly) combined with the most detrimental IPF load;
DEP 80.45.10.10-Gen.
January 2010
Page 20
•
•
•
Determining the individual and partial IPFs' required reliabilities;
Confirming the overall IPF system reliability by determining which combination of up to
three concurrent individual and partial IPF failures result in the acceptable
backpressure being exceeded and by determining the probability of failure on demand
(PFD) of the overall IPF;
Confirming that the PFD meets the required SIL. If the required SIL is not met, IPF or
piping system modifications are required.
The following items of the Flare IPF design shall be covered by the documentation,
preferably captured in a single "Flare System Safeguarding Memorandum":
1. A list of all relief valves with their assumptions, the mitigated (by an individual IPF) and
unmitigated loads and the associated individual and partial IPFs;
2. The rationale, assumptions and calculations demonstrating the claimed mitigated and
unmitigated loads;
3. Assumed failure rates, test intervals, test and diagnostic coverage factors for IPF
components;
4. Individual and partial IPF architectures and description of the locations in the process
and their resulting PFDs;
5. Mapping between individual IPFs and logic solvers;
6. Listing of all combinations of failing logic solvers, individual and partial IPFs that would
result in exceeding the acceptance criteria for the limit being analysed (for example,
backpressure), including the average PFD for each combination;
7. Overall resulting PFD;
8. Hydraulic Flare Models for all scenario combinations considered, including the relief
capacity calculations if backpressures can limit the individual relief system's capacity.
The Flare IPF design approach shall only be applied with the support of the location
management. It is essential that the location management understand that the flare IPF
design approach imposes substantial inspection, testing and maintenance requirements
that continue for the lifetime of the IPF. Installation of IPF systems will require the location
to maintain the IPF systems as defined in the analysis. In addition, any plant change with a
potential impact on the flare load will require an update of the flare analysis.
3.5
SIZING OF DOWNSTREAM PIPING SYSTEMS
Outlet line pressure drop calculations SHALL [PS] be done for all relief devices with outlet
piping, whether to flare, vent, process, or directly to atmosphere. This includes pressure
vacuum vents with outlet piping, as well as other relief devices. Unlike inlet line pressure
losses, the outlet line pressure drop shall be calculated based on the required relief loads,
not the PRV rated capacity.
In the case of multiple relief valves (including one spare), each relief valve shall have an
individual discharge pipe, which could be combined in a common header. The diameter of
the individual pipe should be equal to or larger than the corresponding relief valve outlet.
The diameter of the common outlet should be such that the cross sectional area is at least
equal to or greater than the sum of the areas of the individual discharge pipes. In the
common outlet the spare cross sectional area can be excluded.
Once the maximum design load for each header, sub-header, and lateral has been
ascertained it is possible to size the downstream piping system. By starting from the tip of
the flare or vent stack where the pressure is atmospheric or critical, and adding each
calculated pressure drop, the built-up back pressure downstream of each relief or
depressuring device can be determined. The flare system hydraulic analysis software listed
in (10.5) should be used, in which a roughness factor of 40 µm (assuming the pipe is clean)
may be applied. Adjustments in the assumed line sizes may then be made in order to
ensure that the operation of the relief or depressuring device is not hindered. If the required
piping becomes excessively large, particularly in systems where only low back pressures
are allowed, it may be preferable to replace non-balanced spring-loaded relief valves with
balanced bellows types, thereby increasing the maximum allowable back pressure and so
meeting the following relief valve selection criteria:
DEP 80.45.10.10-Gen.
January 2010
Page 21
i)
For conventional PRVs, the built-up backpressure SHALL [PS] not exceed the PRV’s
allowable overpressure for scenarios during which the conventional valve must open;
ii)
For balanced bellows PRVs, the total backpressure (superimposed plus built-up)
should not exceed 50 % of the set pressure. At higher backpressures, capacity
correction factors, provided by the valve Manufacturer, SHALL [PS] be applied to
account for possible flow reduction. The total backpressure SHALL [PS] not exceed the
mechanical limit of the bellows PRVs and valve outlet rating. For balanced bellows
valves that are not required to operate under the scenario being considered, the
possibility that this valve can open partially due to excessive superimposed
backpressure shall be evaluated if the backpressure exceeds 50 % of the set pressure.
The valve Manufacturer should be consulted for guidance.
iii) For pilot operated valves (POVs), the total backpressure should be limited to 70 % of
the set pressure. The use of pilot-operated relief valves shall meet the criteria specified
in DEP 80.36.00.30-Gen. The backpressures SHALL [PS] not reduce the POV capacity
below that required for the scenario. Pilot operated valves may need to be equipped
with backflow preventers if the discharge is routed to a common collection system such
as a flare header or vent header. When a diaphragm pilot operated valve is used, the
backpressures SHALL [PS] not exceed the mechanical limit of the diaphragm pilot
operated valve.
The design should also ensure that if two or more depressuring valves in any process
system are opened simultaneously, flow from the high pressure system will not back up into
the low pressure system sufficiently to overpressure it or hinder its operation.
To cope with future expansion (e.g. revamps), design velocities in the main relief header
should not exceed a Mach number of 0.7. Velocities in subheaders may be higher, up to
Mach 1.0. Choked flow due to the piping configuration (e.g. elbows, tees, or other
discontinuities) could occur at Mach numbers close to 1.0. Moreover, when the direction of
flow is changed, less than 100 % of the cross-sectional area may be available for the
choked flow. Therefore, if the calculated velocity in subheaders and lateral piping
approaches a Mach number of 1.0, the above back pressure limitations should be further
th
reduced by 1/10 of their recommended values. For example, for balanced bellows PRVs,
the total backpressure should not exceed 45 % of the set pressure.
Small branches and instrument connections SHALL [PS] not be provided on flare relief
systems, with an exception for pilot remote sensing lines, because they are vulnerable to
flow induced vibration.
Hot wells are often protected against overpressure by means of a seal leg that vents to
atmosphere. The vent line to the atmosphere shall have a head loss under relief conditions
(including fire case) that is less than the liquid seal height, as shown below.
DEP 80.45.10.10-Gen.
January 2010
Page 22
C
Atmospheric Vent
Discharge
Vapours to
Hot Well
Relief path shown
in red
Hot Well
B
A
Seal leg height controls
hot well liquid level
Liquid
Overflow
Drain
The vapour flow head loss between points B and C shall be less than the liquid static head
between points A and B to avoid vapour relief at the overflow drain point. If the pressure
drop in the vent line is greater than the liquid seal height, then the relief stream flows to the
path of least resistance and the vapours may be released at grade (where the liquid seal
leg normally discharges liquid).
3.6
LAYOUT OF DOWNSTREAM PIPING SYSTEMS
3.6.1
Common discharge systems
It is usually simpler and more economic to combine discharges from a number of facilities
into a common discharge system served by a central vent or flare.
In the normal configuration of a common discharge system designed for venting or flaring
gas at an elevated height, a knockout drum situated close to the stack is required. The
relief valves or depressuring valves installed according to the requirements specified in (2.)
and DEP 80.45.10.12-Gen., respectively, shall discharge via plant subheaders with
connections into a main header running outside the battery limits. If this arrangement is not
feasible, the flare/vent piping may be routed through process areas. However, the risk of an
upset situation that can result in a local failure of the flare/vent piping should be minimized
and flare/vent piping should be welded wherever possible.
In the following cases additional knockout facilities shall be installed within the units:
a)
presence of cold flashing liquids in the relief streams, e.g. liquefied gas which may
cause blockages in the main knockout drum or water seal vessel (if installed);
b)
presence of liquids at a very high temperature, which may cause high stresses due to
thermal expansion in the main flare system;
c)
presence of liquid which, when running at the bottom of the flare header, may cause
cryogenic bending;
d)
presence of liquids with a high pour point which may solidify in the main header or with
a high concentration of solids, e.g. catalyst, polymers;
e)
need to recover liquid relief streams which are expensive or very toxic and streams
which need to be neutralised before entering the main system;
f)
need to prevent liquids entering the main flare relief system, since this liquid may be
picked up by vapour emergency relieves from other plants, generating liquid slugs and
resulting in high forces at elbows and tees;
DEP 80.45.10.10-Gen.
January 2010
Page 23
g)
need to overcome problems with header elevations.
Where small quantities of liquids are expected, a small drain pot or drip leg may be
installed. These SHALL [PS] be regularly inspected to avert blockage of the header. Traps
or other devices with operating mechanisms should not be used since they become
plugged very easily and have a tendency to freeze.
The disposal piping SHALL [PS] be self-draining towards the knockout drum. The minimum
slope shall be 1:200 for sub-headers and 1:500 for main headers (e.g. off plot flare
headers). The headers should slope in the direction of the flare knockout drum. Back
sloping is not allowed with the exception of the flare header downstream of the flare KO
drum to the flare stack. This is one of the reasons why the KO drum should be installed
close to the flare stack.
If possible, connecting subheaders shall be connected at the top of the header and they
SHALL [PS] drain into the headers. The subheaders shall be connected in such a way that
there are no welds in the lower one-third of the circumference of the header.
The relief system headers shall leave a free passage to allow access for cranes and other
maintenance equipment (see DEP 31.38.01.11-Gen.).
The main flare header should be installed with a pressure reading device giving an
indication in the main control room. The device shall provide an indication of flare
backpressure and shall be provided with a suitable range.
It shall be evaluated whether thermal expansion loops are required in the relief header. For
new designs, expansion bellows SHALL [PS] not be used.
Where several units are connected to one common disposal system, isolating block valves
may be provided in the unit subheaders, if permitted by local regulations. To ensure that
these valves are open during operation, they SHALL [PS] be locked open (LO) or car seal
open (CSO). There SHALL [PS] be a provision for blinding off the line upstream of the block
valve. Also a drain and vent with a flange and a purge connection SHALL [PS] be provided
to facilitate draining and venting of the isolated branch. See Appendix 6, which shows a
connection of the subheader into the main header.
In the relief header piping, gate or full bore ball valves shall be applied. Gate valves should
be provided with a flush connection. For sizes larger than DN 600 (NPS 24) butterfly valves
may also be used if there is an economic advantage and if approved by the Principal. An
adequate locking system is required to keep these valves LO/CSO or LC/CSC.
Isolation gate valves in the relief system SHALL [PS] have their stems in the horizontal
position. This requirement applies to all isolation gate valves for relief devices, flare laterals,
flare headers, and knockout vessels. This is not a requirement for PRV bypass gate valves.
Isolation gate valves for emergency depressuring valves shall have their valve stem in the
horizontal position, unless otherwise approved by the Principal. The purpose of this
requirement is to minimize the negative effect of dirt collecting in the gate valve and to
minimize the possibility that an internal valve failure (the gate breaking off the valve stem
and falling into the valve seat) will obstruct the relief path.
3.6.2
Individual vent outlets
Where it is impractical to route discharges to a common centralised vent or flare,
consideration may be given to individual local vents. The requirements listed in (3.3.1) shall
also be met.
The location of the vent outlet should be chosen so that:
• the discharge location of atmospheric vents and relief devices that relieve toxic vapours
shall be based on dispersion analysis results;
• the concentration of any toxic products is diluted to a safe level at any area in the vicinity
where personnel are likely to be present; see (5.4);
DEP 80.45.10.10-Gen.
January 2010
Page 24
• in the event of accidental ignition of the vent, flames shall not impinge upon adjacent
equipment and the heat radiation to equipment or personnel shall be within the limits of
(5.3.2);
• flammable vapours emanating from the vent outlet shall be sufficiently diluted; see (5.4);
• vent/relief device discharge piping shall have no pockets, shall discharge vertically, and
shall have its outlet at least 3 m (10 ft) above the tallest plant structure within a
horizontal radius of 7.6 m (25 ft) unless otherwise approved by the Principal. This radius
is specified to prevent flammable concentrations from entering elevated process areas.
Smaller radii may be considered if the relief stream is not hazardous;
• the noise requirements are met; see (5.5).
All such vent outlets should be clearly marked on the hazardous area classification drawing
and the appropriate Hazardous Zones shall be determined.
The end of the discharge pipe shall be cut off squarely. A toroidal ring shall be installed
where hydrogen content of the vapour exceeds 20 % (mol) to minimise the risk of ignition
by static electricity. The toroidal ring's mean diameter is the same as the pipe it is welded
to. Ring size is as follows:
DEP 80.45.10.10-Gen.
January 2010
Page 25
Pipe diameter
Toroidal ring diameter
Less than DN 200 (NPS 8)
13 mm (1/2 in)
DN 200 to DN 300 mm (NPS 8 to NPS 12)
20 mm (3/4 in)
Greater than NPS 300 (NPS 12)
25 mm (1 in)
For safe dispersion of hydrocarbon vapours, the vent velocity should be as high as
practicable; whenever feasible, not less than 150 m/s (500 ft/s) at the required relief
capacity. An alternate method for assessing safe hydrocarbon dispersion is the Reynolds
Number approach described in ISO 23251. When using the Reynolds Number approach,
the exit velocity calculation shall be based on the minimum stable PRV flow (25 % of PRV
capacity). If the exit velocity is less than 12 m/s (40 ft/s) or the ratio of the jet/wind velocity
is less than 10, then the Reynolds Number approach may not be valid and dispersion
analysis may be required.
NOTE:
There are no discharge velocity requirements for tank pressure vents as these are low velocity and
low flow devices.
For a common vent outlet, the diameter shall not be smaller than the outlet of the largest
connected relief valve, and SHALL [PS] satisfy the backpressure considerations. The exit
diameter and height of the common vent stack discharging flammable or toxic materials
shall be based on the results of dispersion analysis and shall satisfy the criteria outlined in
(5.4).
Relief devices discharging to atmosphere should be located at the maximum practical
elevation to keep discharge piping (to safe location) as short as possible. Atmospheric relief
device discharge piping shall be corrosion resistant (e.g. hot dip galvanized or stainless
steel construction) and shall have a weep hole of 13 mm diameter and an elbow at the
lowest point to prevent the accumulation of liquid.
Relief device discharge piping shall be supported independently of the relief device unless
analysis shows that the relief device can function properly with the piping loads during
relief.
Process vessels with free vents to atmosphere shall comply with the above requirements.
The discharge design requirements of storage tanks with free vents shall be determined on
a case-by-case basis. Unless vents are designed to limit the internal pressure to 0.2 bar
(ga) [2.5 psig] or less, the outlet of vents, and drains in vent lines, SHALL [PS] be arranged
to discharge so that localized overheating of any part of the tank is prevented if vapours
from the vents are ignited. Free vents on internal floating roof tanks shall be designed to
prevent ingress of rain.
3.7
BLOCKAGE DUE TO HYDRATE/ICE FORMATION IN DOWNSTREAM PIPING SYSTEM
The blockage of discharge piping downstream of a relief or emergency depressuring valve
is normally not considered a problem under relieving or depressuring conditions if the
discharge system is correctly designed.
The correct design of the discharge system should include:
•
•
•
•
sufficiently large diameter piping;
relatively high flow velocity;
short length tail pipes;
no flow restrictions.
In cold climates, wet streams should not be added to the flare systems without potential
freezing risks being considered. To prevent hydrate or ice formation due to small leaks
across the valve or low ambient temperatures, heat tracing SHALL [PS] be installed.
DEP 80.45.10.10-Gen.
January 2010
Page 26
3.8
FLOW MEASUREMENT REQUIREMENTS
Each new process unit shall have a flow-sensing device (flow detection, not flow
quantification) on the flare lateral so that a relieving unit can be quickly identified.
The Principal shall determine whether gas (from an environmental point of view) or liquid
(from a KO vessel sizing point of view) or both need detection.
New flares may require devices for flow measurement for flare control and regulatory
reporting purposes. The requirements for these shall be specified on a case-by-case basis.
Consideration should be given to installing flow-measuring devices in each of the main flare
headers.
The flow measurement instruments selected should be capable of:
i)
identifying significant changes in flow rate in order to assist the operator in recognising
the occurrence of upset conditions;
ii)
measuring normal operating mass flow rates to an accuracy of ± 5 % in order assist
the operator in monitoring flare and vent losses;
iii)
measuring low flow rates in order to quantify sweep gas requirements;
iv)
maintainability and possible removal while the flare relief system remains in operation;
v)
providing flow measurement of flare gas to determine the ratio of steam/air for
smokeless flares and assist gas requirements for sour gas flares.
In selecting the flow-measuring device it shall be verified that the installed device cannot
block the flare header and that no low points are created within the device or associated
piping.
In addition, the Manufacturer's recommendations should be sought with regard to the
correct installation of the device, particularly concerning upstream and downstream straight
run length requirements.
The application of ultrasonic flow meters should be considered, since these meters have a
high turn down ratio and low pressure drop.
3.9
PIPING SYSTEM DESIGN
3.9.1
General
All inlet and outlet piping to and from relief valves and depressuring valves shall comply
with DEP 31.38.01.11-Gen. All inlet and outlet piping to and from relief valves SHALL [PS]
be free draining away from the relief valve.
The port size of the inlet and discharge isolation valves shall be in accordance with ASME
VIII so that the flow area shall be no smaller than the inlet and outlet of the relief device and
shall be consistent with the port size assumptions used in the hydraulic calculations.
Ensuring full-port valves for valves smaller than DN 80 (NPS 3) requires special attention
(noting that valves to ISO 15761/API 602 are normally reduced port). Small flanged full-port
valves (e.g. those purchased as full port in accordance with ASME B16.34) are likely to be
considered as “specials”. Particular care shall be taken if reduced port valves are used, so
as not to assume them to be full port valves in the hydraulic calculations.
Inlet and outlet piping for PRVs SHALL [PS] not have check valves since their failure may
result in a blocked relief path.
Uninsulated flare header piping shall not use pipe shoes. Instead, round bar stock attached
to the pipe rack shall be specified to support the piping without restricting movement.
3.9.2
Design pressure
Relief system piping SHALL [PS] be designed to meet the requirements of the piping class
that has been specified.
DEP 80.45.10.10-Gen.
January 2010
Page 27
For new headers, the design pressure shall be based on the flange rating or the pipe wall
thickness, whichever is governing.
The relief system piping inside plot SHALL [PS] be submitted to hydrostatic testing. For
outside plot relief system headers, because of their large diameters and single routing to
the flare or vent stack, pneumatic tests, combined hydrostatic/pneumatic tests or alternative
tests in accordance with ASME B31.3 para. 345 may be adopted, subject to local
regulations and approval by the Principal.
As a minimum requirement the header and support SHALL [PS] be designed for the
presence of liquid. The assumption for the amount of liquid present for a given diameter
shall be in accordance with the table below:
Nominal diameter
Assumption
DN (NPS)
3.9.3
≤ 250 (10)
Full:
300 to 400 (12 to 16)
1/2 full
450 to 900 (18 to 36)
1/3 full
≥ 950 (38)
1/4 full
Liquid or two-phase flow releases
If liquid is released into the hydrocarbon relief system, the following shall be considered:
Even a small quantity of liquid present in the hydrocarbon relief system could form slug flow
if combined with a high gas release, generating high dynamic forces on elbows, tees,
reducers, etc. Therefore, the standing presence of liquid in a flare relief system SHALL [PS]
be prevented. For this reason the correct slope of the flare header (1:200 in plant; 1:500 off
plot) in the direction of the flow shall be provided for new installations. The coincidental
occurrence of a liquid and a major gas release should be evaluated to ensure the suitability
of the relief piping. For this, a complete inventory (matrix method) of all potential liquid and
gas streams feeding the flare header shall be made. Since liquid is not immediately drained
away through the long flare relief header, a gas release occurring even a considerable time
after the liquid release could generate slug flow. Depending on the flare header diameter,
even a relatively small liquid level could be enough to cause this.
Examples of systems that have steady state flows with the potential for slug flow include:
•
Vessel relieving two phases from a relief valve;
•
Unit that has a common mode failure that causes one system to relieve liquid and
another system to relieve or depressure vapour.
Examples of systems that have transient load conditions include:
•
A column that has a relief valve on the overhead line and a relief valve on the
accumulator. There may be a potential that on loss of reflux the accumulator will
(intermittently) relief liquid while the column relieves vapour.
•
A unit that has a power failure that sequentially causes one system to relieve liquid and
another system to relieve vapour.
To what extent liquid can accumulate without the formation of a slug is difficult to
determine. A short-cut approach is that if the liquid volume is less than that of a pipe
segment with 3-diameter length, the potential that this liquid volume will form a slug flow
can be ignored.
If during the early design stages the possible flow effects of all streams cannot yet be
established, one can assume:
DEP 80.45.10.10-Gen.
January 2010
Page 28
• 50,000 N (11,240 lbf) to be the maximum lateral force induced by two-phase flow at
sonic velocity in a DN 900 (NPS 36) header, provided the two-phase flow rate does not
exceed 500 kg/s (1,100 lb/s);
• 20,000 N (5,000 lbf) to be the maximum lateral force induced by two-phase flow at sonic
velocity in a DN 600 (NPS 24) header, provided the two-phase flow rate does not
exceed 200 kg/s (440 lb/s).
Both of these assume that no slug flow occurs and the fluid is a homogeneous mixture.
If excessive forces may occur, a separate gas relief and liquid relief header up to the
knockout drum, installed either at the battery limit or within the flare area, shall be
considered.
To limit the chance of slug flow, the back sloping of flare headers between the KO
vessel/seal vessel and the flare stack should not be more than 20 m.
For new headers, 45° entrances shall be specified for large liquid or two-phase flow reliefs
3
where the liquid portion of the relief exceeds 170 m /h (750 gal/min) or where the
superficial liquid velocity in the subheader is greater than 1.5 m/s (5 ft/s). To handle liquid
releases, the installation of an onplot KO drum shall be considered.
The possible flow effects of all streams which can enter the flare system shall also be
considered to identify the maximum forces on the supports. For this a total inventory of all
relief streams (e.g. operational, emergency) shall be made and the simultaneous
occurrence of liquid and gas releases shall be evaluated.
This evaluation shall consider design case scenarios that may occur during steady state
and transient two-phase flow where applicable. Sequential or simultaneous reliefs from
unrelated causes shall not be evaluated (double jeopardy).
3.9.4
Maximum design temperature
For new headers and laterals, the design temperature shall be a minimum of 150 °C
(300 °F). Design temperature shall be increased if the relieving temperatures are above the
minimum with the exception of the fire case.
If relief streams with a higher temperature could enter the relief system, a higher design
temperature could be applied. The higher design temperature shall be determined by
carrying out heat transfer calculations.
Relief valves in high temperature service, including piping, shall meet the selected piping
class (temperature, pressure etc).
3.9.5
Minimum design temperature
Due to flashing of liquid and the expansion of vapour, the temperature of the fluid will drop.
The isentropic process describes the fluid flowing across a relief valve nozzle. Thus, the
temperature in the relief valve throat at choked (sonic) velocity can be determined by
carrying out an isentropic flash. Since the velocity downstream of the relief valve will not
become supersonic, any further reduction in temperature drop can be determined by
performing an isenthalpic flash from choked pressure to the pressure in the relief system.
This will determine the minimum piping design temperature. If the temperature is just below
a point at which a more expensive (higher alloy) material would be required, more detailed
calculations can be performed taking into account the heat transfer from the flare header
wall and taking into account the fact that the flare gas velocity will not remain at sonic
velocities. The use of carbon steel may be possible where piping stresses are limited by
design.
DEP 80.45.10.10-Gen.
January 2010
Page 29
4.
KNOCKOUT DRUMS, WATER SEAL VESSELS AND LIQUID DISPOSAL FACILITIES
4.1
DESIGN OF KNOCKOUT DRUMS
The relief stream disposal system SHALL [PS] have a knockout vessel if there is a
possibility of liquid carry-over or liquid entrainment.
The objectives of a knockout drum are:
1.
2.
to separate liquid from the gas before it is disposed;
to hold the maximum amount of liquid, which can be relieved during an emergency
situation.
With the above it is important to recognise that the maximum gas relief case need not
coincide with the maximum liquid relief case. This means that the size of the knockout drum
shall be determined by both the maximum gas relief case as well as the relief case at which
a maximum amount of liquid is relieved.
The selection between a horizontal or vertical knockout drum shall be based on economic
considerations taking into account the required slope of the flare header and the maximum
amount of liquid which has to be contained.
4.1.1
Gas/liquid separation
Knockout vessels shall be economically sized and shall be capable of disengaging
entrained droplets of 500 µm and larger. Sizing shall be performed by the gas load factor
method described below or, if approved by the Principal, by the method specified in
ISO 23251.
NOTE:
For vertical KO drums, the ISO 23251 method usually leads to larger vessels than the gas load factor
method. For horizontal KO drums the ISO 23251 method can in some cases lead to smaller vessels
than the gas load factor method.
If liquid reliefs are expected, the installation of a unit KO drum shall be considered. This will
prevent a two-phase flow and slug flow reliefs into the main header, and since the unit KO
drum is located upstream in the system the higher operating pressure (e.g. back pressure)
will result in a smaller sized KO drum.
If there are multiple knockout vessels in series and the upstream knockout vessel volume is
not large enough to meet the gas/liquid separation criterion, then larger droplet sizes may
be acceptable as long as the downstream knockout vessel meets the separation
requirements and the risk of slug flow between the two knockout vessels has been shown
to be acceptable.
The gas/liquid separation efficiency of a knockout drum is determined by its gas load factor,
λ, and calculated from the following equation:
where:
λ
=
Gas load factor (m/s)
Q
=
Gas flow rate (m3/s) at operating conditions
Sg =
Area available for gas flow (m2)
for vertical vessels, Ag is the cross sectional area of the vessel
for horizontal vessels, Ag is the cross sectional area of the gas cap available
above the LA (HH) level (see also 4.1.2).
Gas density (kg/m3) at operating conditions
Sl
Liquid density (kg/m3) at operating conditions
Ag =
=
DEP 80.45.10.10-Gen.
January 2010
Page 30
Appendix 10 indicates how the gas load factor relates to the smallest droplet size still
separated.
For the purposes of gas/liquid separation, and taking into account the various situations, it
shall be determined which of the following requirements are applicable and the most
definitive.
1.
Absolutely dry gas
If the relief flow is an absolutely dry gas, the possibility could be considered of relieving
this gas through a separate (absolutely dry) gas relief line connected directly to the
flare or vent stack, bypassing the knockout drum.
2.
Essentially dry gas
If the relief flow (e.g. depressuring) is essentially dry or if an inside battery limit knockout drum is used for those units or plants that are expected to produce significant twophase flow quantities, a λ value of 0.25 m/s can be applied. Greater λ values could
lead to entrainment of resident liquid in the knockout drum.
Alternative designs should be considered for the approval of the Principal if the
knockout drum would otherwise become disproportionately large (e.g. diameter larger
than 6 m). In this case, if λ becomes larger than 0.3 and a schoepentoeter is applied,
the design shall be subjected to computational fluid dynamic analysis.
3.
Two phase flow
If significant liquid quantities are expected during the major relief case and no inside
battery limit knockout drum is used, a λ value not greater than 0.1 m/s shall be taken.
If a schoepentoeter is installed, a λ value of 0.15 m/s can be used. However, the
schoepentoeter shall be of a sturdy design to be able to cope with high loads.
Reference is also made to DEP 31.22.05.11-Gen. If the inlet pipe is used, it should be
internally directed to the head of the vessel. Any liquid is directed to the head of the
vessel, where it runs down into the liquid space. Therefore for horizontal KO drums
with an internal open pipe with the outlet directed to the head of the vessel (see
Appendix 10, Figures 1 and 3) a λ value of 0.15 m/s can be applied.
Since λ depends on the conditions of the fluid (e.g. gas density, liquid density, etc.), it
is important to determine which two-phase flow condition is the most definitive.
As indicated in the above equation, the λ value depends on the area available for gas
flow (Ag). For vertical knockout drums this will be the horizontal cross sectional area.
For horizontal knockout drums this will be the vertical cross sectional area of the gas
gap above the normal maximum operation level (LA (HH)) and not above the
maximum level the liquid will reach during a maximum liquid relief, unless a major gas
relief coincides with the major liquid relief or occurs shortly thereafter. In this case the
available cross sectional area for the gas cap for proper vapour/liquid disengagement
shall be above the liquid level reached after the major liquid relief.
If the horizontal knockout drum is provided with two inlets, the flow (Q) defining the
required cross sectional area shall be 0.5 times the maximum relief flow. In this case
the vessel should be of sufficient length (L > 5 D) and the KO drum inlet piping shall be
designed symmetrically.
Since the gas velocity in the knockout drum declines with increasing pressure, the size
of the knockout drum can be reduced by maintaining a higher operating pressure. This
can be accomplished by allowing choked (sonic) flow in the knockout drum discharge
piping or at the vent or flare tip. This shall take into account plant noise levels and
maximum allowable backpressures in the relief headers.
4.1.2
Liquid hold up and pump out capabilities
The liquid space in the knockout drum depends on the maximum amount of liquid the
knockout drum has to contain during an emergency situation. During normal operation the
vessel may already contain liquid to facilitate proper control and pump operation, and the
liquid relieved during an emergency be accommodated on top of this. This means that only
DEP 80.45.10.10-Gen.
January 2010
Page 31
the volume above the LA (HH) level can be taken as available. If a maintenance drains
system is integrated into the knockout facility, the knockout vessel SHALL [PS] be sized for
the volume expected from normal maintenance activities. The level due to normal
maintenance activities shall not reduce the volume required for emergency liquid hold up.
Knockout vessels that are also being used as a maintenance drain system may also have a
level alarm set below the LA (HH) and designated as LA (H) to remind the operators to
pump out. It has been common for this alarm to be soft wired and to utilize one of the two
high level transmitters.
Furthermore the type of liquid in terms of temperature, viscosity, solidification point etc.,
shall be taken into account. Attention shall therefore be paid to the following:
1. Liquid space on top of LA (HH) liquid level
This space SHALL [PS] be designed to contain the maximum emergency liquid relief
rate from the largest single contingency, including common mode contingencies, for a
period of at least 15 min for the unit knockout drum and at least 20 min for the flare
knockout drum, without taking credit for pump out capacity. Where liquid relief is likely
to continue for longer than mentioned above, for example for large complex refineries
or chemical plants, or when there is insufficient instrumentation to assist in identifying
the source of flow, the hold up time should be increased accordingly. The above time
period has been selected on the basis that corrective measures to control the relief will
be taken within this time. If a horizontal knockout drum is used, the provision of a liquid
boot at the bottom may be considered. The LA (HH) level could then be set in the top
part of the boot, in which case the full vertical cross sectional area of the knock-out
drum is available for gas/liquid separation.
The above has been written for a refinery based flare KO drum where it may not be
immediately clear which unit is sending liquid to the flare and where units are equipped
with individual unit KO drums. If the KO drum is linked to a single plant or single unit,
corrective measures can be taken by instrument action reacting on high level trip i.e.
LZA (HH). This instrumentation SHALL [PS] be subjected to an IPF classification.
Sufficient hold up SHALL [PS] be present to take into account the delay in instrument
response and to accommodate the liquid flow through the control valve that may be
shut in by the instrumentation, to prevent the KO drum being overfilled.
2.
Maximum liquid level
After the maximum emergency liquid relief:
a) in vertical knockout drums, the liquid level shall remain one inlet pipe diameter or
0.3 m (1 ft), whichever is greater, below the bottom of the inlet pipe;
b) in horizontal knockout drums, the liquid shall not exceed the level where adequate
gas/liquid separation as described in 4.1.1 can no longer be achieved.
3.
Pump out capacity
The knockout drum SHALL [PS] be equipped with electrically driven pumps (one
operating, one spare). Pump out rate from the flare knock out vessel shall be
evaluated on a case-by-case basis. The pump out rate is not based on the liquid load
to the knockout vessel, but is based on the time needed to pump out the vessel after
the liquid load has stopped. Past design practice has been to provide pumps to empty
the vessel between 2 h and 8 h.
Since the hold up volume needs to be sufficient to contain the maximum amount of
liquid generated during any emergency situation, a secured power supply for the
pumps is not necessary.
Appendix 3 shows the pumps operating “on/off”, to control the normal level. This is the
recommended mode of operation for operator convenience, if the product destination
point can accept all potential liquid streams to the KO vessel. Pump start-up can be
initiated by the operator in response to the high level alarm, and the stream routed as
appropriate. The pump can automatically shutdown at low level LS (L). The automatic
settings are described in (4.1.2.5). A period of 2 or more hours is acceptable for pumpout.
DEP 80.45.10.10-Gen.
January 2010
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If it is justified not to install a pump (instead relying on auto-evaporation and/or
occasional pump-out e.g. by vacuum truck and/or drainage to a safe location), the
level required for pump control need not be taken into account and the required control
level might be less than that determined in (4.1.2.5) below. A vacuum truck should not
be used unless the flare is shutdown or fluid is drained to an intermediate point such
as a sump.
If pumps are applied, they shall be designed so that liquid back-flow cannot occur from
the disposal system back into the flare liquid knockout vessels, either through gravity
flow from storage or from pressurised disposal systems, or back through the pump in
the standby operation mode. This will avoid pumps and/or alarms being actuated
unnecessarily. It should thus be verified whether single check valves are sufficiently
reliable or whether heat tracing is required to guarantee their proper operation, or
whether further backflow prevention redundancy may be required.
In some applications, such as compressor stations and in cryogenic service (LNG
plants), the use of blowcases instead of pumps may be considered with the approval
of the Principal.
4.
Heating coil / heat tracing
If the liquid could solidify or freeze (i.e. if the pour/freeze point is above LODMAT) then
electrical or steam heating SHALL [PS] be provided, with or without temperature
control. In this case external heat tracing SHALL [PS] also be provided to the piping
upstream and downstream of the pumps.
If the liquid is volatile (e.g. liquid propane) heating shall be provided to vaporise the
liquid. The heating may be provided by an electric heater or a steam coil, but the
possibility of (steam) condensate freeze-up shall be eliminated and an adequate steam
trap shall be installed. The impact of steam leaks on flare integrity due to freezing
issues shall be considered before installing a steam coil in a flare knockout drum.
A knockout vessel that requires a heating system to boil off light hydrocarbon may be
provided with external heaters (e.g., external bolt-on heating panels) in lieu of internal
heaters (e.g., bayonet heaters). Maintenance and inspection of internal heaters may
require taking the knockout vessel out of service.
5.
Instrumentation
The instrumentation requirements are specified on the basis of DEP 31.22.05.11-Gen.
taking into account the specific requirements inherent to the operation of a flare
knockout drum.
In the text below, LS/LSA are mentioned for the case when the pump-out system is
automatic, with pump start on LS (H) and pump stop on LS (L). It is also common
practice for the pump start-up to be initiated by the operator in response to the high
level alarm, and the stream is routed as appropriate. In this case the pump can be
configured for an automatic shutdown at low level LS (L). At E&P facilities, unmanned
or remote facilities, the flare liquids pump-out system may be fully automated.
It is essential that the specified distances be applied irrespective of pump-out mode,
since it will ensure the design of a proper volume in the vessel for normal level control.
a.
LSA (LL) is 0.15 m (0.5 ft) above BTL (vertical vessel) or 0.15 m (0.5 ft) above
vessel bottom (horizontal vessel). For large diameter vertical KO drums, having a
considerable hold up in the bottom head, a lower setting than 0.15 m (0.5 ft)
above the BTL can be considered. For a horizontal KO drum, a boot could be
installed at the bottom. This boot will hold the liquid, providing maximum area for
gas/liquid separation.
b.
LS (L) is 0.20 m (0.7 ft) above LSA (LL) or located so that there is sufficient liquid
hold-up time between LSA (LL) and LS (L) to prevent any nuisance alarm or
pump trip; alternatively the liquid volume between LS (L) and LSA (LL) should be
60 s pump-out capacity.
DEP 80.45.10.10-Gen.
January 2010
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c.
LS (H) is 0.20 m (0.7 ft) above LS (L) or the liquid volume between the two levels
should be at least 5 min pump-out capacity.
d.
LA (HH) is 0.15 m (0.5 ft) above LS (H) or 60 s pump-out capacity. Knockout
vessel SHALL [PS] have two redundant high level alarms. These alarms are
required to give the operator a timely alarm of high level in the drum soon enough
to take corrective action. They also may provide indication that the pump-out
facilities are not operating properly or that a major liquid relief is entering the
knockout drum.
These alarms are critical, shall be independent (i.e. separate nozzles), shall use
transmitters (not level switches), shall be set to alarm so that the operator has
sufficient amount of time to respond, and shall have proper safety integrity (SIL 1
as a minimum) and availability in compliance with an IPF classification in
accordance with DEP 32.80.10.10-Gen., which will determine the correct
hardware and testing frequency. The alarm should also have a very high priority
within the framework of the site’s alarm management system.
Knockout vessels may have an alarm at the liquid level where droplets greater
than the specified criteria (e.g., 500 µm) begin to get carried-out from the drum.
This level is considered the LA (HHH) point. It is the level after the operator's
intervention time has elapsed.
At facilities which are not continually manned, the high-high level SHALL [PS]
result in an automatic plant shutdown.
e.
TSA (L). The purpose of the low temperature switch is to prevent a pump from
being started if low temperature liquid has collected in the flare knockout drum.
This liquid could be volatile (e.g. propane or butane) and cannot be transferred
directly to the slops tank, since the contents of the slops tank could be too hot,
generating more vapour than canbe handled by the off-gas system of the slops
tank.
f.
TSA (H). The purpose of the high temperature switch is to prevent a pump from
being started if high temperature liquid has collected in the flare knockout drum.
The high temperature liquid could generate too much vapour when pumped into
the slops tank. As an alternative, passing the liquid through a cooler to the slop oil
tank may be considered.
4.1.3
Other requirements
4.1.3.1
Nozzle sizes
The momentum criterion (mix density multiplied by two-phase flow velocity squared) for
nozzles provided with a half open pipe shall not exceed 5000 N/m2 (105 lbf/ft2). With a
schoepentoeter inlet device this value can be increased to 10000 N/m2 (210 lbf/ft2). The
momentum criteria for the outlet nozzle shall be 6000 N/m2 (125 lbf/ft2).
The essential dry case need not follow the above criterion; however, the mechanical design
shall still consider the momentum (nozzle load). This is particularly relevant to horizontal
flare KO drums that have a deflector plate installed at the outlet. The deflector plates in
flare KO drums shall be of a sturdy design, and flat plate deflectors shall be at least 10 mm
thick. A mechanical check of the plate thickness and necessary reinforcements shall always
be carried out as part of the detailed mechanical design. To assure sufficient strength a gas
load factor of 0.6 shall be assumed.
For new designs a circular deflector plate at least 5 mm thick should be used. The deflector
plate SHALL [PS] not be installed in a flare KO drum with two inlets and one outlet (see
Appendix 10 figure 1).
DEP 80.45.10.10-Gen.
January 2010
Page 34
4.1.3.2
Design pressure
The knockout drum shall be designed as an ASME pressure vessel with a design pressure
of at least 3.5 bar (ga) [50 psig]. If no seal vessel is used, the design pressure SHALL [PS]
be at least 7 bar (ga) [100 psig]. The minimum design pressure of 7 bar (ga) [100 psig] is
specified for flare knockout vessels so that the vessel will safely withstand the
overpressures from an internal deflagration (i.e., flash-back).
4.1.4
Example drawings
Several rules are specified above to arrive at a suitable design of the vent or flare knockout
drum. Appendix 10, Figures 1, 2 and 3 give typical layouts of knockout drums to assist in
fulfilling these requirements.
4.2
WATER SEAL VESSELS (SEE APPENDICES 3, 4, AND 5)
The purpose of the water seal vessel is:
1)
to prevent any flashback, initiated from the vent or flare tip, from propagating further
upstream of the water seal vessel;
2)
to prevent air ingress due to a sudden temperature change in the flare and relief
system;
3)
to maintain a slight positive pressure in the flare and relief system to ensure that air will
not enter the system; this may also be necessary if a flare gas recovery system is in
use.
The design of the water seal vessel shall be based on the maximum vapour quantity to be
released (see Appendix 5). Appendix 4 gives rules for its sizing. Experience has shown that
seal drum design based on ISO 23251 guidance alone is not sufficient to avoid operability
problems. Experience has also shown that flare vendors' seal drums have had operability
problems as well.
If two or more flare stacks operate in parallel, each flare stack should have its own
dedicated water seal vessel. At a low gas relief rate, one stack shall burn preferentially and
to achieve this, the dip legs of the various seal vessels should be set staggered.
The seal vessel shall be equipped with a skimmer (intermittent operation); see Appendix 3.
A water seal vessel shall be installed as close to the flare stack as practical. Lines between
water seal vessel and stack shall be kept as short as possible. There shall be no expansion
loops downstream of the seal drum.
Although proper design of water seal vessel should prevent this, the potential for ejection of
water seal during a flaring event should be considered in the siting of the flare stack.
Water seals SHALL [PS] be protected against freezing by installing an internal coil (steam
heater) and/or electrical heat tracing (EHT), and continuous water makeup and purge. A
low temperature alarm and EHT alarms shall be provided.
For LNG, NGL, and most gas plants, no water seal vessels SHALL [PS] be used, since in
the event of a cold release this may form an obstruction in the flare relief system. If two or
more flare stacks operate in parallel, anti-flashback devices should be installed at the
bottom of the flare stacks. If one flare is spare to another flare, an anti-flashback device is
not necessary. However, operating procedures SHALL [PS] prevent flashback (e.g. higher
purge rate) when the operational flare is switched to the spare flare.
Since the operation of water seal vessels is cumbersome, an alternative could be to install
a bursting disk or a buckling pin device in parallel to a full size emergency control valve
(PZV). The parallel operation ensures 100 % availability of the flare and relief system and,
by giving the pressure switch of the PZV a lower setting than the bursting pressure,
prevents premature rupture of the bursting disk.
DEP 80.45.10.10-Gen.
January 2010
Page 35
4.3
LIQUID DISPOSAL FACILITIES
Depending on the required capacity, nature of the liquid (e.g. viscosity, pour point),
economic value, expected frequency and duration of disposal, different systems as
described below may be selected to safely dispose of the liquid. These systems should be
evaluated on their suitability, economic merits, and impact on the environment.
4.3.1
Process feed vessel
If the emergency liquid release is related to a certain process, it may be beneficial to
release it back to its feed vessel or other suitable vessel. It shall be ensured that the
receiving vessel will not be overfilled or overpressured.
4.3.2
Slop oil storage
Small quantities of liquids, occasionally released and collected in the flare knockout drum,
should be sent to slop/recovered oil storage. In this case it is important to consider the
following:
4.3.3
1)
Sufficient storage shall be available;
2)
The liquid shall not be too volatile, because this could generate too much vapour in the
receiving slop oil storage vessel and potentially result in overpressure;
3)
The liquid shall not be at too high a temperature [>70 °C (160 °F)], because this could
evaporate the liquid present in storage. If a temperature above 70 °C (160 °F) cannot
be avoided, the use of an intermediate cooler should be considered. The cooler shall
be able to function during a power failure event;
4)
The pour point of the liquid shall not be too high, since the liquid could solidify in the
transfer line to the slop oil storage tank, plugging the disposal system;
5)
Very toxic gases entrained with the liquid should be disposed of safely via the slop oil
tank vents, ensuring that this will not have adverse environmental and personnel
exposure consequences.
Evaporators
Volatile liquids may be evaporated, either by installing a heating coil or electric heater in the
flare knockout drum, or by using an external heat exchanger. In this case the liquid is
disposed as vapour together with the other gases released to the flare.
If a heater is installed it shall be ensured that water cannot leak into the flare system and
result in a freeze plug during cold weather operation or during flaring of light ends
(Joule-Thomson effect).
4.3.4
Liquid disposal burners
Liquid burners should not be used; instead, the liquid should be recovered for re-use or reprocessing.
Liquid burners may be used if large streams of liquids (e.g. off-specification products) have
to be disposed of over prolonged periods and there is no economic or environmental
incentive to recover this liquid for other purposes.
The same criteria (e.g. radiation levels, noise levels) as outlined for flare stacks and flare
tips (see 5. and 6.) SHALL [PS] apply. To obtain high combustion efficiency and improve
the turn down capability of the liquid burner, assist gas shall be employed.
If required, an adequate purge shall be provided to prevent flashback.
4.3.5
Burn pits
Burn pits produce considerable smoke and therefore their use shall be considered in
exceptional cases only.
DEP 80.45.10.10-Gen.
January 2010
Page 36
A burn pit has a storage capacity, and hence drain lines can be routed directly to the pit. It
shall have its own sterile area of at least 100 m (330 ft) radius, not to be combined with the
sterile area of the main flare.
All piping to burn pits or liquid disposal burners shall be protected against fire by either
burying them or by putting them in a trench covered by concrete slabs.
If required, an adequate purge shall be provided to prevent flashback. Adequate pilots, pilot
monitoring and re-ignition systems for pilots shall also be provided.
DEP 80.45.10.10-Gen.
January 2010
Page 37
5.
STRUCTURES FOR FLARE AND VENT STACKS AND LIQUID BURNERS
5.1
GENERAL
The type and height of the structures supporting flare or vent stacks or liquid burners
depend on the following operational and environmental aspects:
i)
ii)
iii)
iv)
v)
5.2
required availability of the flare and relief system;
acceptable heat radiation levels;
acceptable dispersion levels;
acceptable noise levels;
maintenance considerations including the stack/tip itself or maintenance activities of
adjacent equipment/operations.
TYPE OF STRUCTURES
The selection and arrangement of flares and flare structures shall be subject to approval by
the Principal.
Various types of structures to support an elevated flare stack (or vent stack) are:
1)
free standing stack;
2)
guyed stack;
3)
fixed or demountable derrick structure;
4)
boom structure installed at an angle (especially on offshore platforms).
In addition to elevated flares, ground flares and enclosed flame flares may also be
considered in some applications, subject to the approval of the Principal. Ground and
enclosed flares should not be used on streams containing very toxic vapours due to
inadequate elevation and dispersion in case of loss of flame/pilots.
ISO 25457 data sheets should be used to specify flare stack details. The structures shall
comply with DEP 34.00.01.30-Gen., DEP 34.24.26.31-Gen., DEP 34.28.00.31-Gen.,
ISO 25457 and ASME STS-1.
NOTE:
API Std 537 is equivalent to ISO 25457.
The type selection is based on economic and operational considerations. If only one stack
is required, any of the four elevated flare types mentioned above may be selected. Single
and multi-burner flares may be applied for each type.
The flare tip has a limited service life and therefore inspection and dismantling of the tip
shall be feasible. This may be done using a crane (if locally available) or a davit. With the
latter it shall be taken into account that a davit installed near the tip will be exposed to the
flames of the flare, impairing its availability and safe operation. Therefore it shall be
possible to retract the davit underneath a heat shield to protect it against excessive heat
radiation. The radiation level shall be less than 15.8 kW/m2 (5,000 Btu/h⋅ft2)
The Principal shall specify whether 100 % availability of the flare system is required (as is
often the case for refinery, petrochemical and production facilities. If 100 % availability is
required, two flare stacks may be considered (one operating and one spare). These stacks
should be installed in one derrick structure and it should be possible to retract one flare
stack while the other remains in operation, without personnel having to work above the riser
removal/replacement platform. A typical arrangement is displayed in Standard Drawing
S 28.028. If 100 % availability is required, the flare structure above the riser
removal/replacement platform shall be designed so that no maintenance whatsoever is
required during its entire service life (e.g. 30 years or more). The materials and coating
system shall be selected to meet this requirement. For this reason, making the structure
with tubular members, and assuring that the tubes have adequate drain holes, shall be
considered.
A derrick structure shall be supplied with the following access equipment:
a)
a stairway from grade to the riser removal/replacement platform;
DEP 80.45.10.10-Gen.
January 2010
Page 38
b)
a ladder from the riser removal/replacement platform to the top platform;
c)
step-off platforms at intervals of 9 m (30 ft) to the top platform at the flare tip;
d)
platforms with ladder access for all manways and handholes;
e)
ladders from the riser removal/replacement platform to all eyes attached to the derrick
structure that are used to raise, lower and tilt the riser sections.
Riser removal/replacement platforms may comprise more than one level and shall be of a
retractable type.
The exact elevation of the riser removal/replacement platform will depend upon the number
of riser sections and the elevation of the hoisting blocks and associated eyes that are
attached to the support structure to raise, lower and tilt the riser sections.
The distance between the burner tips and the top of the structure shall be specified by the
flare system Supplier. The heat radiation from the burner tips shall not affect the structure
itself, nor the conservation system or personnel. Suitable heat radiation screens may be
considered to achieve this.
Surface preparation and surface protection shall be in accordance with DEP 30.48.00.31Gen.
Detailed calculations shall be carried out by the Manufacturer to verify the integrity of the
system. If the entire facility is planned to be shut down every 3 to 5 years, no spare flare is
necessary.
For aviation warning lights requirements see DEP 34.24.26.31-Gen.
If a retractable flare stack system is selected, the aviation warning lights shall be retractable
without shutting down the flare relief system.
5.3
HEAT RADIATION LEVELS
5.3.1
Calculation Method
The basic calculation method to determine the heat radiation levels of burning flares is
given in ISO 23251. The basic equation is as follows:
where:
K
=
Heat radiation level (kW/m2)
τ
=
Fraction of heat intensity transmitted through the atmosphere
F
=
Fraction of heat radiated
Q
=
Heat released related to Low heating Value (kW)
D
=
Distance from midpoint of flame to the object considered (m). To determine this
point a wind speed of 10 m/s (33 ft/s) shall be assumed.
The results of the calculations greatly depend on the factor F. Parameters influencing this
factor include the composition of the gas, the exit velocity of the gas and the geometry of
the burner. A limited number of experiments have been carried out to determine this factor.
Based on these experiments, the F-factors given in Appendix 7 have been determined for
natural gas containing predominantly methane. These factors can be used for preliminary
flare design to determine the required flare stack height taking into account the acceptable
heat radiation levels.
Since manufacturers have their own calculation methods and the F-factor also depends on
the geometry of the tip, the Manufacturer shall confirm that the specified radiation levels are
met at the given height and at other conditions specified in the requisition.
DEP 80.45.10.10-Gen.
January 2010
Page 39
Flare radiation calculations shall be based on the premise that the quantity of mist exiting
the flare stack is within the range specified in (4.1.1) for droplet retention size at the KO
drum. If the entrained droplet size exceeds the standard, flare thermal radiation calculations
may not be accurate.
To determine the thermal radiation levels for flares that are predominantly in service for
(natural) gas mainly containing C1 through C3, the Shell hazard consequence analysis
package ("FRED") using the Gas Jet Flame model shall be used.
NOTE:
5.3.2
FRED's gas jet flame model has only been validated for gas mainly containing C1 through C3.
Acceptable heat radiation levels
The acceptability of heat radiation levels depends on:
a)
the effect on humans; and
b)
the effect on equipment.
Normally, the only equipment allowed in the flare's sterile area shall be that directly related
to its operation, such as knock-out drums, seal drums, pumps, valves, etc. While this
equipment should be located as close as practical to the flare stack, risks to people and
equipment associated with thermal radiation, slug flow, and liquid carryover shall be
assessed and taken into consideration when determining the equipment layout. Equipment
located in the sterile zone should be kept to a minimum.
Special attention shall be paid to construction materials (for example, either eliminate or
ensure suitability of aluminium or plastic), heat sensitive streams (no open oil sewers
generating flammable vapours). Electrical equipment and instrumentation shall be able to
withstand the heat radiation in the sterile area.
Taking into account topographical and meteorological conditions, the height of the flare
stack shall be selected to meet the following conditions:
1)
For onshore facilities, the sterile area radius should be 60 m (200 ft).
2)
At the boundary of the sterile area the heat radiation level at maximum emergency
relief rate SHALL [PS] be 6.3 kW/m2 (2,000 Btu/h⋅ft2) maximum (excluding the effect of
solar radiation). Local requirements shall also be checked.
3) At the property limit the heat radiation level at maximum emergency relief rate
SHALL [PS] be 3.15 kW/m2 (1,000 Btu/h⋅ft2) maximum (excluding the effect of solar
radiation). Local requirements shall also be checked.
4) During flaring events that may occur during normal operations (including start up and
shut down but excluding emergency and upset events), the heat radiation (excluding
the effect of solar radiation) SHALL [PS] not exceed 1.5 KW/m2 (500 Btu/h⋅ft2) at the
boundary of the sterile area.
To determine the above maxima, the exposure times needed to reach the pain threshold as
outlined in ISO 23251 have been taken as a basis with the exception that the effect of solar
radiation can be excluded, since its spectrum is better accepted by the skin and a 100 %
addition is considered not to be realistic.
The following additional flare radiation limits (at grade and at elevated structures) shall be
used as the basis for design flare loads:
DEP 80.45.10.10-Gen.
January 2010
Page 40
Location
Radiation limit
2
2
kW/m (Btu/h⋅ft )
Public, sustained exposure
1.58 (500)
Public, short term exposure
2.37 (750)
Cooling water towers
3.15 (1000)
Sustained exposure where there is adequate training with respect
to flare thermal radiation
4.73 (1500)
Short-term exposure where there are large numbers of people
exposed and/or activities that cannot by stopped in a timely manner
(e.g., turnaround activities).
4.73 (1500)
Maximum short-term exposure where there is adequate training
with respect to flare thermal radiation. Entry into an area where this
or a greater level of radiation is expected requires special
precautions (e.g. reducing potential flare loads, use of personal
protective equipment)
6.30 (2000)
Cable trays
12.0 (3800)
Metal equipment. In accordance with API Publ 2510A, vessels
2
2
receiving more than 22.1 kW/m (7000 Btu/h⋅ft ) require cooling,
otherwise they may overheat and lose strength.
NOTE:
(7000)
The controlling case for hydraulic design and the controlling case for flare radiation may not
necessarily be the same.
In the maximum emergency release case, heat radiation levels may exceed the 6.3 kW/m2
(2,000 Btu/h⋅ft2) limit within the sterile area. Since flare-related equipment may be located
within the sterile area and sometimes requires maintenance, personnel could be exposed
to radiation levels higher than 6.3 kW/m2 (2,000 Btu/h⋅ft2). Such a situation could also occur
when a flare stack is being taken down. Personnel will be present on the first platform to
unbolt the flange connections of the different stack sections. Consequently, a proper heat
shield at the first platform and temporary shelters at grade SHALL [PS] be provided within
the sterile area to protect personnel.
If it is decided to build a plant just outside the sterile area consideration shall be given to
equipment that has elevated work platforms, for instance a platform installed at the top of a
column. This platform should be accessed by stairways installed on the side away from the
flare stack.
The same guidelines as applied to flares SHALL [PS] also be applied to (ignited) vents, with
the exception that a sterile area is not required. Shelters SHALL [PS] be provided if
personnel could be exposed to radiation levels higher than 6.3 kW/m2 (2,000 Btu/h⋅ft2).
Equipment installed in the vicinity may be used to serve this purpose. To limit the level of
heat radiation, advantage shall be taken of the fact that at high exit velocities the F-factor is
lower. Taking into account noise criteria (5.5) and backpressure requirements (3.5), the use
of sonic tips shall be considered in order to achieve a cost effective design.
For liquid burners, the same guidelines as specified for flare stacks are applicable, except
that the height of the structure may be less. To determine the heat radiation an F-factor of
0.3 shall be taken.
DEP 80.45.10.10-Gen.
January 2010
Page 41
5.4
DISPERSION LEVELS
An (emergency) release SHALL [PS] be at a safe location. This means that the release
SHALL [PS] be dispersed in such a way that personnel present at nearby work levels (e.g.
platforms, tank roofs, etc.) or equipment are not exposed to a hazardous situation. The
dispersion calculations shall take into account the most unfavourable concentrations in the
stream to be released and the most unfavourable weather conditions.
The following shall be met in order to meet the above criterion:
1.
Dispersion SHALL [PS] be such that within the hazardous contour (the area within
which either an ignition source or personnel could be present):
a)
the concentration of flammable components is less than 50 % of the lower
flammability limit;
AND
b)
the resulting concentration of toxic and very toxic substances at locations where
people may be exposed is less than the IDLH value.
NOTE:
2.
IDLH (Immediately Dangerous to Life or Health) values are are published by the US National
Institute of Occupational Safety and Health.
No noticeable stench or irritation levels shall be caused outside the property limits.
Proper operation of the flare (combustion efficiency > 98 %) may be assumed.
When utilizing physical effects modelling to determine hazardous contours, sensitivities
such as atmospheric stability, wind speed, humidity etc. shall be taken into account.
5.5
NOISE LIMITS
DEP 31.10.00.31-Gen. shall apply.
For emergency conditions:
• the noise level at the base of the stack shall not exceed 115 dB (A). If the stack is
provided with a derrick structure, including a platform for coupling/uncoupling segments
of the retractable stack, the noise limit applies to this platform.
For normal operation (including starting-up and shutting-down):
• Noise levels at the perimeter of the sterile area shall not exceed 85 dB (A) at flow rates
up to 15 % of maximum flaring capacity or at the maximum relief rate that may occur
during normal operation (including starting-up and shutting-down), whichever is higher
• If there are limits on the allowable noise levels outside the plant, then the sound power
level generated during normal operation shall be taken into account when assigning
sound power levels to noise sources.
DEP 80.45.10.10-Gen.
January 2010
Page 42
6.
FLARE AND VENT TIPS
6.1
GENERAL
This section is concerned with the general design of flare and vent tips. Specific proprietary
flare tips are not covered in this DEP. To obtain specific requirements for a particular type
of tip, the Manufacturer shall be consulted.
An overview of flare technologies, as well as good practices for design, operation,
maintenance and troubleshooting, is given in ISO 25457.
Flare and vent tips are only one of several components required for provision of a complete
system design necessary for the safe and reliable discharge of hydrocarbons from pressure
relieving and vapour-depressuring systems. The fundamental key elements in a flare
system design include:
6.2
•
Reliable pilot(s) proven for severe service;
•
Regulated natural gas supply to pilots;
•
Pilot monitoring;
•
Pilot ignition;
•
Flame retention device on the flare tip;
•
Main flame monitoring;
•
UPS power supply for all monitoring and ignition systems.
FLARE TIP DESIGN CONSIDERATIONS
A flare tip should be selected with the aim of:
(a) Safe and effective discharge of pressure relieving and vapour-depressuring systems
with a combustion efficiency of at least 98 %;
(b) Reducing radiation levels. If more than one flare stack is required, the tip's centre-tocentre dimensions shall be selected so that the heat radiated from an operating tip has
no detrimental effect on adjacent tips;
(c) Reducing or eliminating smoke formation;
(d) Ensuring that the flared gases burn with a stable flame over the whole operating
range;
(e) Reducing to a minimum the maintenance required over its operating life. For
maintenance purposes, provisions for lowering either the entire flare stack or the flare
tip alone shall be agreed upon with the Principal. Any impact on adjacent
equipment/operations and their maintenance requirements shall be taken into account;
(f)
Meeting permissible noise levels, which are specified in (5.5).
Fundamental to the physical design of all flare tips shall be a flame-stabilizing device.
Although the primary intent is to anchor the flame to the tip and prevent flame blow-off at
high discharge rates, the other important benefit is providing flame stability at low loads and
improving the ability for the pilots to maintain or reignite the main flame. All flare tips shall
incorporate a flame-stabilizing device of proven design. Open pipe flares without a flame
stabilization ring are not permitted.
In order to improve combustion, reduce smoke formation and reduce heat radiation, high
speed flare tips (sonic tips) should be used wherever possible. Manufacturers should be
contacted for more detailed data on particular types of tip.
The suppression of smoke formation is achieved by good pre-mixing with an excess of air
to reduce the release of elemental carbon through the flare. If there is a deficit of entrained
air due to a low exit velocity (e.g. pipe flare) then air can be forced into the gas using fans
or steam (i.e. air or steam assist).
DEP 80.45.10.10-Gen.
January 2010
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If one of the above is considered necessary in order to achieve a smokeless flame over the
whole operating range of the flare, an economic analysis of the above methods shall be
performed to find the most suitable. As a minimum the flare system shall be designed to
produce smokeless flame which meets Ringelmann No. 1 criteria (BS 2742) for the
maximum continuous flare flow rate or to cover an acceptable range of emergency flaring
(which is 15 % to 20 % of the maximum flaring capacity). Actual single events and the
expected frequency of emergency flaring shall be checked to ensure adequate smokeless
combustion capacity is provided. Periodic continuous flaring cases shall be checked too, in
case smokeless capacity over 20 % is required.
Where steam injection is selected, dry medium pressure steam (approximately 17 bar (ga)
[250 psig]) shall be used. The injection of excess steam wastes energy, can create a very
noisy flame and may even cause the flame to be extinguished due to steam capping. It is
therefore essential to ensure that the correct quantity of steam is injected and controlled.
The system design shall include a minimum flow of steam, as recommended by the
Supplier, for protection of the steam nozzles and manifolds from overheating and thermal
shock.
As a first estimate the table given in Appendix 8 may be used to obtain the required steam
flow rates. A typical flare gas composition should be used in performing the calculation.
Fine adjustment of the steam flow rate may be performed during start-up. Steam supply
shall be controlled automatically on ratio from a flow measurement of the gases to the flare
together with manual over-ride from the control room. It is important to reduce the amount
of steam injection for smoke suppression once the vent gas stream is reduced in order to
prevent over-aeration or steam capping, both of which can extinguish the main flame. A
means of main flame monitoring from the control room, such as by television camera,
SHALL [PS] be provided.
Damage is most commonly caused to a flare tip when operating at low flow rates due to
flame impingement on the inside and outside of the tip, which causes thermally induced
stresses and oxidation. External burning of the tip is generally influenced by the wind force
itself and by low-pressure zones caused by the wind. The following points shall be
considered in order to increase service life and thus reduce maintenance costs and loss of
production:
(i)
The use of refractory linings, provided with adequate supports, on the inside of flare
tips (see DEP 64.24.32.30-Gen. and ISO 25457).
(ii)
The use of windshields or deflectors, which break-up the low-pressure zones, created
by the wind and physically stop the flame from coming into contact with the tip.
(iii) The use of multipoint flares which reduce or eliminate low pressure zones around the
tip, due to the smaller diameter of the individual burners.
(iv) The use of the available flare tips in increments related to the amount of gas to be
flared. This can be obtained by proper setting of the dip legs in the water seal vessels
or by applying a staged control of the number of burners of a multi-tip flare.
(v) Pushing the flame away from the tip by the use of a supplementary flow, such as
compressed air, to overcome the forces exerted by the wind.
(vi) Upgrading the material specification for the flare tip beyond the following requirements.
The material of the flare stack tip shall be sufficiently heat and corrosion resistant, e.g. type
310S stainless steel, Incoloy 800H or equivalent. The preferred choice for flares with any
H2S content is type 310S stainless steel rather than nickel-based materials such as Incoloy
800H. For offshore applications, a material highly resistant to chloride stress corrosion
(such as Inconel 625 or equivalent) should be used.
All ancillaries connected to the tip of the stack shall be of the same material.
In view of the high cost of Incoloy 800H or Inconel 625 material, the inlet flange of the tip
may be made of carbon steel if approved by the Principal.
NOTE:
This is justified since the hottest area is at the discharge end of the tip, and heat generation lower in
the tip due to back burning is prevented by applying a proper purge rate.
DEP 80.45.10.10-Gen.
January 2010
Page 44
Particularly high levels of heat emission from the flame will occur only under high gas flows and
consequently the cooling effect of the gas rising through the stack, together with the induced higher air
flow around the tip, will then be greatest, thus keeping the inlet flange sufficiently cool.
The wind strakes fitted to the tip shall be of the same material as the main body of the flare
tip. Any carbon steel materials should be coated with thermal sprayed metallic aluminium
and the bolts for mounting the tip to the rest of the flare shall be of a high nickel alloy. To
cope with thermal expansion the wind strakes shall be attached to the tip at one fixed point.
Other connection points shall be of the sliding type. Wind strake nuts shall be locked to
prevent them from getting loose due to vibration.
Centre tip lift/cooling steam should not be used in cold climates due to the potential to form
condensate, which can freeze within the flare stack creating an ice plug blocking the flare
path. If centre tip steam is considered, the steam line shall be isolatable at grade and
drainable. The supply line up to the tip shall be winterizable for cold weather operation to
avoid splitting. The smokeless steam shall be supplied from a separate line and shall not be
isolated by the same valves.
DEP 80.45.10.10-Gen.
January 2010
Page 45
7.
FLARE AND VENT PURGING
7.1
GENERAL
Unless otherwise specified, the flare stack SHALL [PS] have a purge. Since flare stacks are
idle most of the time, they are vulnerable to intrusion of air down the stack. A flare stack
purge prevents excessive air intrusion and possible internal deflagration. This section
defines the criteria applicable to the purge rates required in order to prevent oxygen ingress
and the possibility of detonation within the flare and vent system. The passive aids that may
be utilised are also considered.
7.2
PURGING DESIGN CONSIDERATIONS
Purging of a flare or vent system shall be considered, taking into account the following:
1. Oxygen ingress can lead to the formation of flammable air/fuel mixtures in the stack,
which when ignited will cause a flashback. This is most likely to limit itself to a
deflagration but under certain conditions could result in a detonation.
2. Oxygen ingress can lead to the formation of deposits (partial oxidation of sulphur
compounds) causing flare blockage.
3. If too little purge gas is used it can lead to back burning or a licking flame, reducing the
service life of the flare tip.
4. If too little purge gas is used an unstable flame could result in inefficient burning
causing an obnoxious impact (stench) on the surroundings.
5. If fuel gas is used as purge gas, this may have an impact on the environment.
6. If the relief system has to handle corrosive gas or gas prone to condensing or
solidifying then, in addition to purge gas, sweep gas shall be injected (either
continuously or intermittently) at strategic locations in the flare relief system. For an H2S
rich disposal system, see also (3.3.5).
7. Clean dry natural gas shall be used from a continuous reliable supply source that will
not be interrupted.
8. Steam shall not be used as a purging medium.
Air ingress into the stack may occur as follows:
a)
b)
c)
d)
e)
f)
diffusion of air down into the stack;
wind action across the tip at low flow rates, resulting in a differential pressure at the top
of the stack;
relief gas with a lower density than air; this may create a problem especially when two
or more stacks are operating in parallel. The relief gas could tend to leave through one
stack only, while the heavier air may enter through the other stack and mix with the
relief gas, creating an explosive mixture;
condensation and/or shrinkage of the contents of the relief system resulting in an
underpressure within the relief system. This may be caused by an increase in heat
removal as a result of a hot release or a rain shower on the header. This shrinkage
could be considerable after a major hot, heavy gas relief;
during a plant (relief system) shutdown, during which some connections are open and
the purge system is inoperative or inadequate for a prolonged period;
air ingress to the stack through a corrosion hole or through a cracked open flange.
Internal fire in the stack may jeopardize its structural integrity.
To prevent air ingress due to a) and b) the recommended minimum purge rates at different
flare stack diameters and purge gas molecule weights are as presented in Appendix 9.
Required purge rate for vertical flare stacks without seals in hydrocarbon service can also
be calculated in accordance with the following equation:
Q = 0.003528 × d3.46 × ∑{Ki⋅(Ci0.65)}
Where: Q = purge rate, ft3/h
d = stack diameter, in
th
Ki = constant for the "i " purge gas component
DEP 80.45.10.10-Gen.
January 2010
Page 46
th
Ci = volume fraction of the "i " purge gas component
For single component purges Ci = 1.0. Therefore, the summation equals K. The following
purge gas constants shall be used:
Purge Gas
K
Methane
+2.328
Nitrogen
+1.707
Ethane
–1.067
Propane
–2.651
CO2
–2.651
Butane
–6.586
NOTE:
If the purge gas is required to be heavier than air it should be assumed to be nitrogen.
Purge requirements for vertical flare stacks in hydrogen service, and flare stacks with seals
are normally specified by the flare tip Manufacturer.
Normal minimum flare streams (usually considered to be just the purge streams) should
have a minimum average lower heating value of 11.2 MJ/m3 (300 Btu/SCF).
Maximum design velocity and minimum heating values for flares operating under normal
conditions (i.e., not emergency conditions) shall conform to local regulations where
applicable.
To secure the purge gas supply the purge gas source SHALL [PS] be reliable and the
purge SHALL [PS] be carried out through a locked open block valve.
Detailed calculations show that considerable purge gas rates are required to prevent air
ingress due to the phenomena c) and d) above, and purge gas rates as specified in
Appendix 9 or derived from the equation above may be inadequate. If these phenomena
can occur, a water seal vessel shall be installed upstream of each flare stack and the purge
gas should be injected downstream of the water seal vessel. The design of water seal
vessels is covered in (4.2).
Air ingress due to d) may also be protected against by a temporary additional purge
following a flaring event (temp-purge) regulated by pressure and temperature at the flare
stack base. This specifically applies when no water seal vessel is included in the system.
If cold gas (e.g. in NGL plants) can be relieved, water freezing can occur and glycol
SHALL [PS] be used instead of water in the seal drum. If very cold gas can be relieved (e.g.
in LNG plants), a seal vessel should not be used, even if it is filled with glycol. In this case,
if two stacks have to operate in parallel, an anti-flashback device at the inlet of the stack
should be installed. With single stack operation no anti-flashback device is required, since it
is realistic to assume that phenomenon d) will not occur in LNG plants only handling cold
gases at sub ambient temperatures.
Items e) and f) above should be addressed through operating, maintenance and inspection
procedures (e.g. inert purging during flare system shutdown, inspection of self-supported
structures, etc).
The above recommendations only have a direct effect on item 1) above and indirect effects
on items 2), 3), 4), 5) and 6). Recommendations for dealing with the effects of items 2), 3),
4), 5) and 6) are difficult to specify in this DEP and depend on the actual situation. Factors
of influence are:
-
The type of a purge gas available; hydrogen rich gas has a higher tendency to back
burning;
The economic value of the purge gas;
DEP 80.45.10.10-Gen.
January 2010
Page 47
-
-
The direct impact on the environment; residential areas require greater attention;
purging with an inert gas has less environmental impact but does not support
incineration and is not compatible with fuel gas;
The composition of the gas to be flared; H2S rich gas has a higher tendency to form
deposits; inefficient combustion will easily cause an obnoxious odour;
The layout of the vent and flare system;
The presence of a flare gas recovery system;
The type of flare tips used; tips with refractory lining are more susceptible to back
burning;
The flaring philosophy; for a non-flaring facility (i.e. with flare gas recovery or large
secondary stack) the use of an inert gas as purge gas may be attractive;
Consequence of air ingress.
These factors shall be taken into account to arrive at an economic and environmentally
acceptable solution.
A typical purge supply system is shown in Appendix 3.
7.3
PURGE REDUCTION SEALS
Several types of device have been developed to reduce, but not eliminate, the overall purge
gas requirement.
Gas seals of the labyrinth type (e.g. molecular seal) SHALL [PS] not be used, as they are
easily blocked, and very heavily and easily damaged by shock loads, such as those
occurring at the start of emergency depressuring.
Only gas seals that prevent the infiltration of air along the wall of the stack by returning air
to the unrestricted central zone of the stack shall be used. Unlike the labyrinth type of seal,
this type of seal offers no protection against air ingress in the event of interrupted purge
flow. Manufacturers shall be contacted in order to ascertain purge rate requirements for a
particular type of seal.
Purge reduction seals shall be constructed of the same material as the flare tip and located
close to the flare tip base flange for ease of inspection and maintenance.
7.4
FLAME/DETONATION ARRESTORS
Flame or detonation arrestors shall not be used as an alternative to a continuous purge for
flare tip flash back protection because they:
• are susceptible to blockage;
• are susceptible to undetected mechanical damage;
• provide an obstruction to flow;
• become ineffective within a few minutes of ignition due to heat build up if located near
the vent tip.
Flame or detonation arrestors should only be used if the use of purge gas is not feasible
and the discharge fluid is clean. If used, arrestors shall be placed near to the tip of the vent,
but still be accessible for maintenance and inspection. This is to prevent explosions
occurring in the vent pipe.
The Manufacturer shall be given full details of the intended service, location and
arrangement of an arrestor so that a suitable selection can be made. Arrestors should be
installed at or near the end of vent pipes since long pipes would otherwise allow the flame
front to accelerate.
Regular inspection SHALL [PS] be carried out on all installed flame/detonation arrestors,
particular attention being paid to arrestors which do not have a constant vent stream
through them, those which are used on an inbreathing service and those used on any
service where the risk of blockage is relatively high.
DEP 80.45.10.10-Gen.
January 2010
Page 48
Consideration may be given to providing a constant nitrogen purge stream through normally
non-flowing flame arrestors so that blockage may be detected early.
A flame arrestor should not be specified for:
• relief valves releasing to atmosphere; or
• P/V valves on tanks,
since these could cause a flow restriction. In addition, these devices under high flow
conditions should prevent flash back into the equipment. P/V valves under some conditions
might not stop a flame front from entering the equipment. In applications where the
flammable range of composition can develop, additional safeguards to prevent ignition (e.g.
inerting) should be evaluated..
Open vent lines shall have flame arrestors if inbreathing via the vent lines can cause a
flammable atmosphere in vessels or tanks.
Flame and detonation arrestors shall be certified (e.g. UL listed) and installed as specified
by the arrestor Manufacturer.
Neither flame arrestors nor screens SHALL [PS] be installed on open vents where the
vented material can polymerize or condense and obstruct the flow out of the vent.
DEP 80.45.10.10-Gen.
January 2010
Page 49
8.
VENT SNUFFING
8.1
GENERAL
The fitting of a remote controlled snuffing system on all vent stacks should be considered in
order to avoid continuous burning in the event of accidental ignition of the vented gases.
Pressure relief vents that discharge flammable vapours to atmosphere shall have remotely
controlled manually operated steam, carbon dioxide or nitrogen snuffing facilities if the vent
discharge is more than 30 m (100 ft) above grade and if the site has frequent
thunderstorms.
8.2
VENT SNUFFING REQUIREMENTS
The snuffing medium may be nitrogen, carbon dioxide or steam (if available); Halon or
other CFCs shall not be used due to their adverse effects on the environment.
The snuffing system shall be operated from a manual station. Once the flame is
extinguished, the control system shall ensure that metal temperatures at the tip of the vent
drop sufficiently to prevent spontaneous ignition of gas and the danger of flashback.
The snuffing facilities shall be sized to extinguish the stack at least three times in
succession when it is burning and discharging at a rate corresponding to 1 % of the
maximum vent rate.
DEP 80.45.10.10-Gen.
January 2010
Page 50
9.
FLARE PILOTS AND IGNITION
9.1
GENERAL
All flare systems SHALL [PS] be provided with continuous pilot burners to ignite the flare
gas as it leaves the tip. The pilots SHALL [PS] each be provided with an ignition system in
case they are extinguished. Pilot and ignition management systems including routine
monitoring and testing shall be in place.
Further requirements and information regarding pilots and ignition systems are given in
ISO 25457.
9.2
FLARE PILOT REQUIREMENTS
The pilots provided at the flare tip SHALL [PS] be capable of sustaining stable combustion
under all flaring and meteorological conditions. Pilots should therefore be checked by
means of a flame stability model. Pilots shall be in accordance with ISO 25457, plus the
following:
• Pilots shall be certified through testing of the stability requirements under the specified
wind and rain criteria in any wind direction. The testing shall include exposure of the
pilot gas mixer to the same environmental conditions as the pilot tip and demonstrate
the ability to relight the pilot under the same conditions.
• Pilots shall be of the self-inspirating type with air mixer and gas orifice integral to the
pilot assembly. Pilot systems with a common air mixer and gas orifice at grade shall not
be used.
• For pipe flare tips up to 400 mm (16 in) diameter, at least two pilot burners shall be
provided. Three pilot burners shall be provided for flare tips larger than 400 mm (16 in).
Four pilot burners shall be provided for flare tips larger than 1100 mm (42 in). For
proprietary flare tips the Manufacturer's proposal should be considered in view of the
ISO 25457 requirements.
• The pilot tip shall be constructed of type 310S stainless steel.
Each of the pilots shall be ignited by means of an individual ignition line.
The location of the pilots’ mixer should be such that they are not engulfed by the flame of
the main flare even in strong winds. Ignition of the main flare shall be ensured under these
conditions.
The materials and design of the pilots and their method of support should be such that they
require minimum maintenance and are suitable for at least a five year service period. The
ignition lines to the pilot burners shall be stainless steel (AISI 321) to prevent the possibility
of internal corrosion, with the top 4 m (13 ft) being type 310S stainless steel. Allowance
shall be made for differential expansion between the flare stack and the pilot lines, with
particular attention being paid to the support brackets.
The use of advanced pilot systems is recommended. These systems are equipped with a
venturi device in the pilot nozzle, which allows a reduction in fuel gas consumption and
increases pilot gas exit velocity and so enhances air entrainment and improves flame
stability. The Manufacturer's recommendations should be followed concerning the quantity
of the fuel gas required for proprietary pilot light systems. The pilot flame can be further
stabilised by the installation of windshields around the pilot nozzles.
The fuel gas and the pressurized air used to supply the pilot lighting and ignition system
shall be dried and filtered to prevent blockage of the lines. Clean reliable and noninterruptible fuel gas shall be used for the pilots. The hydrocarbon and water dew points of
the fuel gas and the water dew point of the air shall be such that condensation is not
possible under any mode of operation. The filter shall be installed between the carbon steel
fuel gas supply line to the flare and the stainless steel supply lines to the pilots and ignition
system. In addition, the gas should be of a constant composition, since a change in the
Wobbe Index of the gas may affect flame stability.
DEP 80.45.10.10-Gen.
January 2010
Page 51
The pilot gas supply lines shall be arranged without pockets and any build-up of
condensation shall be alarmed at the control room before blockage can occur.
The pilot gas mixers/orifices shall be heat traced in plants subject to hoarfrost conditions.
One stainless steel gas supply line along the stack shall be used for each pilot burner.
Individual lines allow testing of the individual pilot flameout monitoring and auto-ignition
systems. The pilot gas supply piping arrangement shall include the following components:
• a filter between carbon steel and stainless steel piping systems;
• parallel pressure regulators at grade together with a high- and low-pressure alarm and
pressure indicator in a common manifold arrangement before branching into the
individual pilot gas lines, each including a quarter turn isolation valve and downstream
pressure gauge; and,
• each pilot shall include a strainer at the base of the gas mixer.
As a minimum, one 'K' type thermocouple located in a thermowell in the pilot head
SHALL [PS] be provided for each pilot. The thermocouple may be fixed or retractable. On
fixed thermocouples, thermowells extended to the base of the pilot should be used
(inherent with the retractable thermocouple design). Retractable thermocouples provide the
capability for online maintenance, and allow monitoring for pilots with a service life in
excess of 3 years.
Another acceptable method of direct pilot detection is acoustic monitoring, when applied
together with individual flame-front ignition lines to each pilot. The flame ionization method
may also be considered as an alternative but only if there is evidence of successful
application for at least 5 years' service.
Pilot monitoring shall be continuous and trended in a DCS system or equivalent. Failure of
a pilot shall be indicated in a local panel as well as in the control room by an alarm. Flame
failure shall initiate pilot re-ignition (see 9.3). A local multifunctional PLC system should be
used to handle pilot monitoring and ignition systems. PLC systems also offer diagnostic and
historical trending capability.
A back-up bottled gas supply shall be provided for start-up/normal operation if there is no
other reliable source of fuel gas available
9.3
FLARE IGNITION REQUIREMENTS
Considerable reliability problems have been encountered with ignition systems; it is
therefore essential that the whole of the pilot/ignition system is correctly designed,
operated, routinely tested, and maintained.
The ignition system should be of the flame-front generator (FFG) type, designed to ignite
the pilot burners at the design wind conditions. Separate ignition lines shall be provided for
each pilot. For cold climate conditions, flame front systems shall include a small
compressed air purge to avoid water (products of combustion) from back-flowing and
accumulating in the FFG lines. FFG systems with separate flame-front ignition lines to each
pilot can be fitted with acoustic pilot monitoring systems.
The pilot shall be re-ignited from a safe location at grade from where the flare tip is visible.
The use of a backup electronic spark ignition system shall also be considered.
For FFG systems, it is essential to create a (near) stoichiometric gas/air mixture, e.g. by
carefully designed restriction orifices and carefully controlled gas and air supply pressures.
For the flame front lines, particular care should be taken when routing the lines to ensure
no pocketing. The line material shall be stainless steel.
The gas and the air used to supply the ignition system shall be dry and filtered to prevent
blockage of the lines. Clean reliable and non-interruptible fuel gas shall be used for the
flame front generators.
DEP 80.45.10.10-Gen.
January 2010
Page 52
10.
DOCUMENTATION
10.1
ENGINEERING ANALYSIS
The engineering calculations of the relief loads, the relief device sizing, the pressure
system hydraulics, the relief device inlet loss calculations, the relief device backpressures,
the disposal system hydraulics, knockout drum sizing, flare radiation, etc. require
documentation. Documentation requirements are specified in this DEP and in
DEP 80.36.00.30-Gen..
10.2
DISPOSAL SYSTEM SIZING CALCULATIONS
Disposal system loads (both liquid and vapour) shall be tabulated to demonstrate the basis
for establishing the design load. Some non-controlling relief loads shall also be tabulated;
these include loads that may affect KO vessel sizing or flare header flow regime as well as
all those loads (both liquid and vapour) that may exist during common mode scenarios. An
example is a large vapour relief valve with a non-controlling liquid relief scenario that can
affect KO drum sizing.
10.3
DATA SHEETS
1. Data sheets for flare system elements shall be provided at the time of inquiry.
2. Data sheets shall include all pertinent data defining size, type, materials, and fluid
properties.
10.4
FLARE LOAD DOCUMENTATION
1. Relief and flare header loads shall be tabulated showing the governing individual relief
loads as well as the combined relief flows.
2. Schematic diagrams of the relief and flare header system shall be provided for each
common mode failure. Preferably, diagrams shall be a page from the Process Safety
Flow Schemes (PSFS) or Engineering Flow Diagrams (EFD) with the protected
equipment and piping circled.
3. Schematic diagrams shall show:
a. Line sizes and equivalent lengths;
b. Appropriate flows with process conditions;
c. Resulting backpressures, and allowable backpressures.
10.5
ELECTRONIC FILES
1. Documentation produced with PC based software shall be provided in electronic form.
This includes, for example, column simulations to determine the relief loads and flare
system hydraulic calculations.
2. Microsoft Word and Excel shall be used to produce documentation as applicable.
3. Unless otherwise specified, individual electronic documents that require more than one
program to produce shall be provided in a single file (e.g., Excel spreadsheet integrated
into a Word file).
4. Documents provided in Adobe Acrobat files shall also be provided in the native format
(e.g. Word, Excel, AutoCAD) so that future modifications can be made.
5.
10.6
Flare system hydraulic software shall be subject to the approval of the Principal.
FLARE EQUIPMENT FILES
1. The flare equipment file shall contain the following documentation:
DEP 80.45.10.10-Gen.
January 2010
Page 53
a. Flare load schematics that show the following for each common mode failure:
-
Header line pipe size and equivalent lengths;
-
Flows (with MW, temperature, and phase);
-
Calculated backpressures at each node;
-
Resulting backpressure (calculated) at the PRV;
-
Allowable backpressure.
b. Set of flare header isometrics with reference points that allow mapping from the
isometric drawing to the flare load schematic.
c. Narrative description of how the common-mode flare loads were determined (e.g.,
extent of utility failure, which pumps are assumed to operate, etc.).
d. Relevant process data, loads, and process conditions.
e. Hydraulic calculations.
f. Relevant notes and correspondence.
g. For a new flare system, the Basis for Design document and all specifications.
2. One set of the flare equipment file shall be issued to the Principal.
10.7
REVIEW OF DOCUMENTATION
The documentation specified in (10.) shall be reviewed by the Principal before any pressure
relief and flare system equipment is ordered.
DEP 80.45.10.10-Gen.
January 2010
Page 54
11.
REFERENCES
In this DEP, reference is made to the following publications:
NOTES:
1. Unless specifically designated by date, the latest edition of each publication shall be used,
together with any amendments/supplements/revisions thereto.
2. The DEPs and most referenced external standards are available to Shell staff on the SWW (Shell
Wide Web) at http://sww.shell.com/standards/.
SHELL STANDARDS
Definition and determination of temperature, pressure
and toxicity levels
LPG bulk storage installations
Metallic materials – Prevention of brittle fracture
Protective coatings for onshore facilities
Noise control
Gaseous oxygen systems
Gas/liquid separators – Type selection and design rules
Piping – General requirements
Classification and implementation of instrumented
protective functions
Structural design and engineering
Steel stacks (amendments/supplements to the CICIND Model
Code)
Steel structures
Vertical carbon steel storage tanks - selection and design (based
on EN 14015)
DEP 01.00.01.30-Gen.
Insulating and dense refractory concrete linings
Relief devices – Selection, sizing and specification
Overpressure and underpressure – Prevention and
protection
Emergency depressuring systems and sectionalizing
Interlocking systems for safety/relief valves
“FRED” (hazard consequence analysis package)
Work process to reduce flare loads through
instrumented protective function (IPF) design
Standard Drawing: Flare structure – Erection Procedure
DEP 64.24.32.30-Gen.
DEP 80.36.00.30-Gen.
DEP 80.45.10.11-Gen.
DEP 30.06.10.12-Gen.
DEP 30.10.02.31-Gen.
DEP 30.48.00.31-Gen.
DEP 31.10.00.31-Gen.
DEP 31.10.11.31-Gen.
DEP 31.22.05.11-Gen.
DEP 31.38.01.11-Gen.
DEP 32.80.10.10-Gen.
DEP 34.00.01.30-Gen.
DEP 34.24.26.31-Gen.
DEP 34.28.00.31-Gen.
DEP 34.51.01.31-Gen.
DEP 80.45.10.12-Gen.
DEP 80.46.30.11-Gen.
OP 97-47088
GS.05.50616
S 28.028
AMERICAN STANDARDS
Sizing, selection and installation of pressure-relieving
devices in refineries –
Part I:
Sizing and selection
Part II: Installation
API RP 520 Part I
API RP 520 Part II
Guide for pressure-relieving and depressuring systems
API Std 521
Flare details for general refinery and petrochemical
service
API Std 537
Steel gate, globe and check valves for sizes DN 100
and smaller for the petroleum and natural gas industries
API 602
Venting atmospheric and low pressure storage tanks
(non-refrigerated and refrigerated)
API Std 2000
DEP 80.45.10.10-Gen.
January 2010
Page 55
Fire-protection considerations for the design and
operation of liquefied petroleum gas (LPG) storage
facilities
API Pub 2510A
Requirements for safe discharge of hydrocarbons to
atmosphere (presented at the API Division of Refining,
th
28 midyear meeting, session on pressure-relieving
systems, May 1963)
API Division of Refining
Vol 43, III
Issued by:
American Petroleum Institute
Publications and Distribution Section
1220 L Street Northwest
Washington DC. 20005, USA
Process piping
ASME B31.3
Valves – Flanged, threaded, and welding end
ASME B16.34
ASME Boiler and Pressure Code – Section VIII: Rules
for construction of pressure vessels
Steel Stacks
ASME VIII
ASME STS-1
Issued by:
American Society of Mechanical Engineers
345 East 47th Street
New York, NY 10017, USA
BRITISH STANDARDS
Notes on the use of the Ringelmann and miniature
smoke charts
BS 2742
Issued by:
British Standards Institution
389 Chiswick High Road
London W4 4AL, United Kingdom
INTERNATIONAL STANDARDS
Steel gate, globe and check valves for sizes DN 100
and smaller, for the petroleum and natural gas
industries
ISO 15761
Petroleum, petrochemical and natural gas industries –
Pressure-relieving and depressuring systems
ISO 23251
Petroleum, petrochemical and natural gas industries –
Flare details for general refinery and petrochemical
service
ISO 25457
Petroleum, petrochemical and natural gas industries –
Venting of atmospheric and low-pressure storage tanks
ISO 28300
Issued by:
ISO Central Secretariat
1, ch. de la Voie-Creuse
Case postale 56, CH-1211
Genève 20, Switzerland
Copies can also be obtained from national standards organizations.
DEP 80.45.10.10-Gen.
January 2010
Page 56
APPENDIX 1
TYPICAL ARRANGEMENT FOR PRESSURE RELIEF VALVE MANIFOLD
RE LI EF VAL VE
O PTIO NAL
R U P TU R E
D I SK
PI
LO/CSO
CS O
NOT E 5
6 mm TELLTALE
M IN. O R SIDE
EN TRY
DN 20 LPB
MIN.
LO/C S O
NO P O C K E T S
AL LOW ED
BL O CK V AL VE S
NOTE 1
PI
BY PASS VA LV E
NO T E 2 , 3
N O TE 4
FL ARE HEA DER
MIN.
T OP
EN TRY
ALTERNATIVE ARRANGEMENT
FO R BYPA SS
NOTES:
1. All relief system isolation block valves shall have their stems oriented in the horizontal plane and
shall be full port.
2. Bypass valve is required only for operational reasons and shall only be included if approved by the
Principal.
3. Block valves and bypass valves shall be in accordance with the piping class. Valves may have
weld ends if blinding provisions are not required adjacent to the valve.
4. PI shall be readable from bypass valve location and shall be provided only with a bypass.
5. Rupture disk shall have either an excess flow check valve (for clean vapour service) or a block
valve (for liquid or corrosive vapour service).
DEP 80.45.10.10-Gen.
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APPENDIX 2
TYPICAL LINE-UPS OF THERMAL EXPANSION RELIEF VALVES
EXAMPLE 1
The thermal expansion relief valves (TERVs) in the above situation can be lined up to
discharge in the downstream direction, via the downstream isolation valve.
The spring setting (differential set pressure) of the TERVs shall not exceed the maximum
allowable operating pressure (design pressure) of the protected equipment minus the
maximum operating pressure at the point of discharge of the TERVs. The spring setting of
a TERV so lined up can generally be quite low [e.g. 1 bar (ga)] without causing troublesome
inadvertent relief, because there is also an upstream isolation valve, which is closed when
the equipment is isolated. The spring setting of the TERV shall also be higher than the
pressure drop between its inlet and outlet tie-in points with the isolation valves open. This
pressure drop should normally be quite low, unless the downstream valve is a control valve.
EXAMPLE 2
If the system as proposed in example 1 is not possible, the TERVs may relieve into a
header, transferring the liquid to another vessel. Depending on the operating conditions
(e.g. maximum operating pressure, maximum allowable working pressure and constant
(maximum) back pressure), a suitable spring setting of the TERVs shall be selected.
DEP 80.45.10.10-Gen.
January 2010
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EXAMPLE 3
The above represents a pipeline transfer system of which the various pipeline sections can
be blocked in. In this case the TERV nearest to the transfer pump relieves the liquid back to
storage. If operation procedures are such that after the system is blocked in the section
nearest the pump and is partly drained, the relief valve on this section may have a set
pressure of 110 % of the piping system design pressure. This takes advantage of the fact
that a pipeline system can occasionally be overpressured up to 133 % of the pipe pressure
rating (refer ASME B31.3). This will prevent liquid being recycled when the system is
operating close to its maximum allowable working pressure.
The spring setting of the other TERVs may be 1 bar (ga), similar to the settings proposed
for Example 1.
DEP 80.45.10.10-Gen.
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APPENDIX 3
HYDROCARBON FLARE SYSTEM AND H2S FLARE SYSTEM
Figure 1
Hydrocarbon/H2S flare system with seal drum
DEP 80.45.10.10-Gen.
January 2010
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NOTES:
1. The need for steam tracing depends on climatic conditions.
2. The pump capacity shall be such that the liquid hold-up of the knockout drum can be disposed of
within an acceptable time limit.
3. For LNG plants no water seal vessel and no steam injection in the flare tip is applied.
4. Water seal column height, "H" shall be at least 2 m (6.6 ft) or P/(gJ), whichever is greater
where
P = maximum gauge pressure in the water seal vessel (Pa);
g = acceleration due to gravity (m/s2);
J = density of liquid (kg/m3).
5. Steam flow depicted for electronic transmission of signals.
6. Operator set maximum steam flow.
7. Range of required steam flow may necessitate more than one transmitter (auto range selection).
8. TIC is optional but shall be applied when liquid which is too hot or too cold (e.g. hot flare liquids or
LPG) is pumped to slops. Hot systems will require a flare liquids cooler with appropriate TI/TSH.
LPG will not normally be routed to slops except in case of an LPG plant where the slops system
will be routed to a pressure vessel.
9. Ultrasonic flow meter.
10. Redundant level transmitters and level alarms shall be provided on all flare knockout drums.
DEP 80.45.10.10-Gen.
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Figure 2
Hydrocarbon/H2S Flare System without Seal Drum`
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APPENDIX 4
WATER SEAL VESSEL DESIGN CHART
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APPENDIX 5
TYPICAL DESIGN FEATURES OF WATER SEAL VESSEL
outside
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APPENDIX 6
ARRANGEMENT OF BLOCK VALVE FOR ISOLATING UNIT
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APPENDIX 7
NATURAL GAS F-FACTORS USED IN THE API MODEL TO DETERMINE
RADIATION
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APPENDIX 8
ESTIMATE OF STEAM INJECTION REQUIREMENTS FOR FLARING
Waste gas
Formula
Steam/gas
weight ratio
Paraffins
Ethane
Propane
Butane
Pentane
Hexane
C2 H6
C 3 H8
C4 H10
C5 H12
C6 H14
0.15
0.25
0.30
0.35
0.38
Olefins
Ethylene
Propylene
Butene
Pentene
C2 H4
C 3 H6
C4 H8
C5 H10
0.40
0.50
0.58
0.65
Diolefins
Propadiene
Butadiene
Pentadiene
C 3 H4
C4 H 6
C5 H8
0.70
0.90
1.05
Acetylenes
Acetylene
C 2 H2
0.55
Aromatics
Benzene
Toluene
Xylene
C 6 H6
C7 H8
C8 H10
0.80
0.85
0.90
For other components the following equations should be used to calculate the mass flow
rate of steam required.
Paraffins
W steam
=
W paraffin (0.49 - 10.8/MW), where MW = Molecular Weight
=
W olefin (0.79 - 10.8/MW), where MW = Molecular Weight
Olefins
W steam
DEP 80.45.10.10-Gen.
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APPENDIX 9
NOTE:
PURGE RATES REQUIRED FOR PIPE FLARES
Graphs are based on "Purging requirements of large diameter stacks" by H.W. Husa.
DEP 80.45.10.10-Gen.
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APPENDIX 10
1.
FLARE KNOCK-OUT DRUM DESIGN CONSIDERATIONS
LOAD FACTOR VERSUS DROPLET SIZE REMOVAL
In a vertical knock-out drum there is a direct relationship between the gas load factor and
the diameter of the smallest droplet which still can be separated from the gas stream,
provided there is no maldistribution in the vapour upflow.
This relationship is given in Table II for the two representative flow scenarios presented in
Table I.
The physical parameters in bold print determine the relationship between the gas load
parameter and droplet diameter.
Table I
Representative flow scenarios for flare knock-out drums
flow scenario 1
flow scenario 2
temperature, °C
244
0
pressure, bar (abs)
1.35
1.2
vapour molecular weight
87.2
44
vapour flow rate, kg/s
44.46
114.14
kg/m3
2.78
2.36
vapour viscosity, Pa.s
1.E-5
1.E-5
1
1
800
600
0.001
0.0003
vapour density,
liquid flow rate, kg/s
liquid density,
kg/m3
liquid viscosity, Pa.s
Table II
Relationship between gas load factor and diameter of smallest liquid
droplet which will still be separated
gas load factor
(m/s)
diameter (µm) of smallest droplet which
can still be separated
flow scenario 1
flow scenario 2
0.02
118
129
0.04
219
237
0.06
324
350
0.07
379
408
0.08
435
468
0.10
550
590
0.12
668
716
0.14
790
846
0.16
917
980
0.18
1047
1117
It is seen that both flow scenarios lead to roughly the same relationship.
The droplet diameters associated with a gas load factor of 0.07 and 0.10 m/s are printed in
bold.
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A similar gas load factor/droplet diameter relationship cannot be given for a horizontal
knock-out drum, since in a horizontal vessel the settling process is also determined by the
length of the vessel.
In ISO 23251 the vessel sizing method is based on the settling of droplets, assuming a
horizontal and uniform vapour flow.
However, in reality the vapour flow is far from uniform, especially if a small feed nozzle with
no feed inlet device is used.
Also, in reality, the vapour flow contains a vertical component, in particular in the vicinity of
the vapour outlet. Due to these two effects, the ISO 23251 method may results in smaller
vessels.
Therefore the more conservative design method should be folowed, taking the gas load
factor as the criterion. This is also the approach followed in DEP 31.22.05.11-Gen.
However, in the case of flare knockout drums the gas/liquid separation is not a critical issue
and the sizing rules for these type of separators can be relaxed, allowing high load factors.
Only in special cases where only limited space is available for the knockout drum, a
dedicated Computational Fluid Dynamics (CFD) study may be carried out to arrive at the
smallest possible separator, taking vapour flow maldistribution into account. The Principal
should be contacted for such a CFD study.
2.
TYPICAL LAYOUTS OF FLARE KNOCK-OUT DRUMS
accommodate
Figure 1
Horizontal knockout drum with two inlets
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Figure 2
Vertical knockout drum
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Plate thick enough
not to buckle
Figure 3
Horizontal knockout drum
Last page of this DEP