9. Pressure Relief System Components
Pressure relief devices are required for all equipment subject to overpressure that results from outside
pressure sources, external heat input or exothermic reactions. Acceptable types of pressure relief devices
include spring-loaded pressure relief valves, pilot-operated pressure relief valves, rupture disks and rupture
pins.
9.1 Pressure relief devices
9.1.1 Pressure Relief Valves. Pressure relief valves shall be designed and constructed in accordance with
API STD 526 and API STD 527 and sized in accordance with API RP 520 PT I and API RP 521.
a. Pressure relief valves shall be set in accordance with Paragraph 9.1.6
b. For pressure relief valves in water and steam services, appropriate sections of the ASME Code
shall apply. The ASME Code shall be the minimum acceptable where local codes do not cover relief
valves or are less stringent.
c. For pressure relief valves in refrigeration service, appropriate sections of the ASHRAE Standards
shall apply. The ASHRAE standards shall be the minimum acceptable where local codes do not cover
relief valves or are less stringent.
d. Weight-loaded pressure relief valves shall not be used
e. Venting and breathing equipment for atmospheric and low-pressure, aboveground storage tanks
at less than 1.03 barg (15 psig) shall be sized as specified by API STD 2000
9.1.1.1 Backpressure
a. Conventional pressure relief valves shall only be used when the built-up backpressure or the
variable superimposed backpressure in the piping, downstream of the valve, is not expected to
exceed 10 percent of the set pressure or 21 percent of the set pressure for ASME designed vessels
under fire load conditions only
b. Balanced pressure relief valves shall be used in vapor or gas service in which the built-up
backpressure or the variable superimposed backpressure is expected to be between 10 percent and
50 percent of the set pressure. When backpressures are expected to exceed 30 percent of the set
pressure, the valve manufacturer shall be consulted. The capacity of the valve and the maximum
allowable backpressure on the bellows shall be verified with the manufacturer. Pilot operated relief
valves shall be used when the built-up backpressure or the variable superimposed backpressure is
expected to exceed 50 percent of the set pressure.
9.1.1.2 Operating Pressure
Operating pressures over 95 percent of the relief valve set pressure are not recommended. Vessels that
operate between 90 and 95 percent of set pressure require pilot-operated pressure relief valves. Resilient
seated valves may be considered only with approval from SABIC Engineering.
9.1.1.3 Valve Types
All pressure relief valves shall be the manufacturer’s standard type, recommended for specified services.
These valves shall conform to the following ASME and API standards: ASME SEC VIII D1 AB; ASME SEC
VIII D1 BB; API STD 526, for materials of construction and sizes of flanged valves; API STD 527, for seat
tightness.
9.1.1.4 Sizing and Identification
a. Pressure relief devices shall be sized in accordance with API RP 520 PT I or local codes,
whichever is more stringent. Each device shall be tagged with the valve number or other identification
as specified on the purchase order. The data may be stamped on the nameplate or on a separate
corrosion resistant tag that is permanently attached to the device.
b. Where required by local regulations, the pressure relief valve inlet and the mating flange of the
protected equipment shall be die stamped with the tag number
9.1.1.5 Materials
Construction materials of valves for sour gas service shall conform to NACE MR0175. For pressure
relieving valves in unusually corrosive process conditions, body, bonnet and trim materials shall be
approved by SABIC Engineering. An example of unusually corrosive process conditions is
high-temperature production fluids containing high chloride levels in addition to acid gases.
9.1.1.6 Ambient Temperatures
Pressure relief valves with Q, R and T size orifices shall not be used where the temperature exceeds
177 °C (350 °F) and the molecular weight is less than 10. For special services, for example, hydrogen
service, pressure relief valves with soft seats or secondary O-rings may be used, subject to SABIC
approval. Rubber materials for example, Buna-N and Butyl may be used at temperatures below 93 °C
(200 °F) and fluoroelastomers may be used at temperatures below 204 °C (400 °F).
9.1.1.7 Testing
a. Pressure relief valves shall be hydrostatically tested after assembly with a gag in place. The gag
shall be removed prior to valve set pressure and leakage tests. The valve body shall be tested
hydraulically or pneumatically, depending on the valve’s service, as follows:
(i) The inlet side shall be tested at 1.5 times the specified set pressure for casting integrity
(ii) The outlet side shall be tested at 1.5 times the maximum allowable backpressure specified by the
manufacturer for casting integrity
(iii) The outlet side shall be tested at a minimum pressure of 345 kPa gauge (50 psig) for soundness
of mating parts
b. Prior to field installation, all pressure relief valves shall be tested in the manufacturer’s shop by
qualified personnel for set pressure and seat leakage, using air, steam or water. Cold differential set
pressures shall be stamped on the nameplate in accordance with API STD 526.
c. Pressure relief valves shall not be gagged to permit hydrostatic testing of equipment or piping.
Blinds shall be installed as required
9.1.1.8 Documentation
The relief device calculations describing the sizing basis and the relief cases considered will be prepared
by contractors and shall be submitted to and approved by SABIC prior to solicitation of quotes from
supplier.
9.1.1.9 Block Valves
a. A spare pressure relief valve with appropriate block valves shall be installed:
(i) In services where plugging, fouling or corrosion is likely to occur
(ii) Where valve testing or maintenance is required between turnarounds
b. Pressure relief valve installations and relief valve installations with an upstream rupture disk
which require maintenance and/or testing between turnarounds shall be provided with block valves
arranged for example, those shown in Table 1
c. Block valves used on the inlet or outlet of a pressure relief valve shall have full round port areas
equal to or greater than, the inlet or outlet size of the pressure relief valve. Block valves shall be used
only as permitted in the applicable codes. (See Section 9.1.8).
9.1.2 Rupture Disks
a. Rupture disks shall not be used without prior SABIC approval. They shall comply with the
requirements of API RP 520 PT I, ASME SEC VIII D1 AB and ASME SEC VIII D1 BB, Paragraph
UG-127
b. Only non-fragmenting rupture disks shall be used in series upstream of a pressure relief valve
9.1.3 Rupture Pins
Rupture pins shall not be used without prior SABIC approval. They shall comply with the requirements of
ASME SEC VIII D1 AB and ASME SEC VIII D1 BB, Paragraph UG-127-C. When installed upstream of a
pressure relief valve, a “balanced” rupture pin assembly shall be used so that any pressure trapped
between the rupture pin and the pressure relief valve will not affect the opening pressure of the rupture pin.
9.1.4 Pressure Relief Device Location
a. To prevent equipment overpressure, pressure relief devices shall be located in conformance with
ASME SEC VIII D1 AB, ASME SEC VIII D1 BB, API RP 521 and API RP 520 PT II. Pressure relief
devices shall be shown on P&I diagrams.
b. Pressure relief devices provided to discharge vapors shall be positioned to discharge from the
vapor space or from the overhead vapor line of the protected vessel in order to minimize liquid
entrainment
c. Pilot sensing points for pilot operated pressure relief valves shall be at the pressure relief valve
location. Remote sensing points may be considered only with SABIC approval. Pilot lines shall be
sized to prevent blockage.
d. On towers or vessels containing demister pads or packing, pressure relief devices shall be
located so that dislodgement of the demister pad or packing would not obstruct the pressure relief
device, or mechanical reinforcement is provided to prevent dislodgment.
9.1.5 Determination of Relief Loads
a. Pressure relief loads (see Appendix A) shall be calculated for each applicable failure in
accordance with API RP 521 and API RP 520 PT I. See Appendix B of this Practice for catalyst-filled
reactors. Calculations of pressure relief loads for process vessels under fire conditions shall be based
on a minimum fire area of 280 m
2
(3000 ft
2
) and a minimum height of 7.6 m (25 ft) above any level at
which a fire may be located, in conformance with API RP 520 PT I and API RP 521.
b. An Individual Pressure Relief Load is the maximum pressure relief discharge rate from a
particular piece of equipment for a single emergency condition (used for sizing pressure relief devices
and leads and individual atmospheric vents).
9.1.6 Pressure Relief Valve Set Pressures. Set pressure requirements for pressure relief valves are as
follows:
a. The pressure relief valve ambient set pressure, which initially shall be set in the supplier’s shop,
shall not exceed the maximum allowable vessel or equipment working pressure except as allowed in
ASME SEC VIII D1 AB and ASME SEC VIII D1 BB
b. The set pressure for a conventional pressure relief valve shall be corrected for any backpressure
expected to exist before the valve opens. This shall be done by reducing the ambient set pressure by
an amount equal to the constant backpressure present on the discharge side before the valve opens.
This backpressure is limited to 10 percent of the set pressure before and after the valve opens; per
API RP 521.
(i) For balanced and pilot-operated pressure relief valves the set pressure is not affected by the
backpressure present before the valve opens. However, backpressure present after a valve opens
affects the capacity of all types of pressure relief valves. Therefore, allowances shall be made in all
capacity calculations (see API RP 520 PT I).
c. When the bonnet temperature exceeds 93 °C (200 °F), the ambient set pressure (determined in
conformance with Section 6.1.4 and corrected for backpressure, if necessary, as noted in Section
6.1.5) be corrected for high temperature. The pressure relief valve manufacturer shall be consulted,
since corrections vary with different manufacturers. Some typical corrections are as follows:
d. Multiple or supplemental pressure relief valves used for an individual relief load, shall be set in
accordance with the requirements of API RP 520 PT I.
e. Single-spring pressure relief valves located in compressor or pump discharge lines shall be set
above the maximum pulsation pressure or 15 percent above the operating pressure, whichever is
greater. When this is not possible because of equipment design pressure or specified operating
pressure level, pilot-operated valves shall be used. Resilient seated valves may be considered with
SABIC approval.
9.1.7 Relief Valve Selection
The following are conditions for the selection of standard spring-loaded pressure relief valves versus
pilot-operated pressure relief valves for low molecular weight service at temperatures below 177 °C
(350 °F):
9.1.8 Pressure Relief Valve Sizing
Pressure relief valves shall be sized in accordance with API RP 520 PT I.
Notes:
a. Block valve shall be car sealed or locked open
b. Block valves shall be car sealed or locked open and the bypass valve shall be car sealed or
locked closed
c. Personnel shall be stationed at the bypass valve when the pressure relief valve is removed, until
the pressure relief valve has been reinstalled and the block valve is reopened and is re-car sealed.
(Reference ASME SEC VIII D1 AB and ASME SEC VIII D1 BB)
Table I
Examples of Block Valves with Pressure Relief Valves to Permit Removal of
Pressure Relief Valves for Maintenance or Testing
Notes:
Block
valve
shall be car sealed
or l
ocked
open
1)
Block valves shall be car sealed
or locked open and the by
pass
valve
shall be
2)
Personnel
shall be stationed at the bypass valve
when the pressure relief valve
is removed,
3)
Car sealed
or locked c
losed.
Until the pressure relief valve
has been reinstalled a
nd the bloc
k valve
is
reopened and is
Re-car sealed
. ( Reference ASM
E SEC VIII D1 AB a
nd ASME SEC VIIID1 BB. )
9.1.9 Special Protection for Devices in Dirty or Fouling Service
Pressure relief devices in dirty, waxing, polymerizing or other service where fouling is likely shall be
provided with a continuous flushing system on the underside of the seat or disk.
9.1.10 Vacuum Relief
The possible need for vacuum relief on all vessels and systems shall be considered. Suitable protection
may be provided by vacuum-breaking systems, inert (non-condensable) blanketing systems. As an
alternative to vacuum relief, pressured equipment may be designed for full vacuum conditions.
9.2 Piping
The pressure drop for pressure relief piping shall be determined and shall be subject to SABIC approval.
The pressure relief piping for new flare headers and systems shall be sized so that pressure relief valve
backpressure generated after the valve opens is no greater than that listed in paragraph 9.2.6 for the
particular type of valve installed.
9.2.1 Relief Valve Sizing
Relief valve sizing shall be based on instantaneous loads rather than decaying loads. Credit may only be
taken for decaying loads if a dynamic load analysis is performed in accordance with Appendix C.
9.2.2 Flare System Piping
a. Flare system piping shall be designed, anchored and guided to resist the forward, lateral and
upward dynamic forces that develop at bends as a result of high-velocity vapors and condensed
liquids. Flare pipelines that are supported by pipe shoes shall have shoes no shorter than twice the
calculated growth of the piping or a minimum of 457 mm (18 in). The piping shall include expansion
loops to accommodate sudden thermal expansion or contraction.
b. Where there is a wide range between PSV set pressures, independent high and low-pressure
relief systems shall be considered. When the ratios of pressure relief valve set pressures are in the
order of 5:1 or higher, separate systems that terminate in either a common knockout drum and flare or
in separate knockout drums and flares may be economical.
9.2.3 Relief System Piping
To prevent accumulation of liquids in the system, relief system piping shall be free of pockets and shall
slope downward toward the flare knockout drum for good drainage. The slope shall be at least 2 mm/m
(
1
/
in/10 ft), plus the calculated deflections of empty pipe between two supports. Where it is not practical to
design the lines with a continuous slope, changes in elevation may be made, subject to SABIC approval.
4
Such changes shall be made using knockout drums designed in accordance with Section 9.3.
9.2.4 Insulation
Insulation of pressure relief headers may be required for personnel protection, sound levels or process
reasons. The use of insulation and heat tracing to avoid ice accumulation within the pressure relief header
shall be considered where necessary.
9.2.5 Materials
a. Suitable alloy steel shall be used in applicable portions of pressure relief systems, including
pressure relief valves, if large quantities of light hydrocarbons are to be vented into the system.
Auto-refrigeration of these gases can result in freezing and ruptures of carbon steel pipe at metal
temperatures of -29.9 °C (-20 °F) or lower. Pressure relief valves shall be heat treated, not limited to
steam, if auto-refrigeration is expected.
b. Gate valves in the flare unit headers shall be installed with the valve stem in the horizontal
position to prevent blockage in the event that the gate separates from the stem (see Figure 1)
9.2.6 System Pipe Sizing
Following are general guidelines for the sizing of pressure relief system piping:
a. Inlet piping for a pressure relief valve shall be no smaller than the valve inlet nozzle
b. Piping shall not contain restricted area valves for example, plug valves
c. Leads shall be sized for the maximum individual pressure relief load determined in accordance
with Paragraph 9.1.5. Leads shall be no smaller than the outlet sizes of the pressure relief valves
d. Laterals shall be sized for the maximum individual lead load or the simultaneous relief loads from
one cause, whichever is greater. Laterals shall be no smaller than the largest lead they serve
e. Unit headers shall be sized for the maximum individual load or simultaneous relief loads that are
generated within the process unit as a result of a single failure, whichever is greater
f. Main headers, flare headers and flare stacks shall be sized for the maximum emergency relief
load
9.3 Flare and Vent System Knockout Drums (Scrubbers)
a. Knockout drums shall be sized to handle the maximum emergency relief load. In sizing the flare
knockout drum, credit shall be taken for liquids removed in upstream knockout drums. Mechanical
design of drums shall be based on ASME SEC VIII D1 AB and ASME SEC VIII D1 BB.
b. The design of gravity knockout drums shall be based on the method recommended in
API RP 521. A knockout drum shall be sized to separate droplets 450 µm (180 mil) and greater at
maximum relief load and at reduced flow rates. The drum shall be large enough to allow
disentrainment above the liquid present in the drum. The maximum liquid level in the drum shall be
set at 229 mm (9 in) above the heating coils (see Figure 2) or the level corresponding to condensation
and carryover from 20 minutes of flaring at maximum emergency relief load conditions, whichever is
greater. Each case assumes that no pumps are running. The minimum level shall be just above the
top of the coils.
9.3.1 Instrumentation. The following instruments are the minimum requirements for knockout drums:
a. Temperature indicator mounted below the low-liquid level
b. Pressure gauge
c. Independent high-level alarm with annunciation in the control room
d. Level gauge
e. Level switches to start/stop the pumps
f. Low-low-level switch to close the control valve to prevent vapor from entering the liquid disposal
system
g. Independent low-low-level alarm with annunciation in a constantly manned location (i. e. control
room)
9.3.2 Pumps. Knockout drums shall be provided with heating coils to vaporize condensables.
a. The drums shall be provided with automatic liquid level controlled pumps (see Figure 2)
b. A two-pump system, with different types of drivers for each pump, shall be provided. An alternate
driver arrangement requires SABIC approval
c. Each pump shall be sized to empty a half-full knockout drum within two hours and shall have a
minimum capacity of 95 liters/min (25 US gpm)
(i) Pump discharge piping shall be designed for simultaneous operation of both pumps
(ii) A separate water drain on a boot underneath the knockout drum may be used, if required (see
Figure 2)
(iii) It may be more economical to supply small onsite liquid knockout drums in each unit and have
the main flare knockout drum handle only condensation that occurs in the main flare header
d. Liquid knockout drums shall be provided at all system low points (for example, at road crossings)
9.4 Flashback Protection
9.4.1 Protection shall be provided against flashback from the flare tip into the flare stack and into the
pressure relief system. The preferred method of protection is by the use of a small, continuous gas purge in
conjunction with a buoyancy seal or kinetic seal. Flame arrestors are not acceptable. They are subject to
fouling and may permit seepage of air back to the flare header, resulting in a flammable mixture and, if
pyrophoric iron is present, possible ignition. The following common methods of flashback protection (purge
gas, buoyancy seals, kinetic seals, water seals and diversion water seals) are discussed below:
a. Purge Gas. The recommended method of connecting the purge gas supply to the flare is shown
in Figure 1. The following equation shall be used as an initial estimate of the purge gas rate required
for an open pipe flare.
When purge gas is used in conjunction with a buoyancy seal or kinetic seal, a smaller amount of gas is
needed.
Purge requirements for proprietary flare tips shall be established with the supplier.
Plugged vents for purging of the pressure relief system prior to startup shall be installed as shown in
Figure 1. After startup, a small stream of continuous purge gas need only be injected into the main header
at the point farthest from the flare. A flow meter with a low-flow alarm shall be installed at the purge gas
injection point.
A larger amount of purge gas is usually required after a hot release to prevent air from entering the system
when the system gas inventory cools and contracts. This additional gas injection shall be on automatic
temperature and pressure control (see Figures 3 and 4). The rate of gas injection may be estimated as
follows:
Calculate the average gas temperature in the flare system under flowing conditions.
Assume that weather conditions do not change before or after a hot release.
The reduction in the flare system gas volume as a result of cooling can be calculated from the difference
between the average flowing temperature and the ambient temperature.
Inert gas purge capability shall be included in calculating the purge gas requirements, in order to empty the
flare headers, stack and tip in the event of a flare shutdown.
b. Buoyancy Seal (Mol Seal). This gas sealing device uses the density difference between air and
gas to prevent air from flowing back into the flare header. It is installed on the flare stack just below the
flare tip. The design includes a drain to grade level with a suitable seal for removal of trapped
condensables. The mol seal shall have a handhole near the drain line to permit cleaning when the
seal or the drain line is plugged. The bottom of the mol seal and the entire drain line shall be
electrically traced and insulated or steam traced and insulated in areas where temperatures fall below
2 C (35 F). If the knockout drum is immediately below the flare stack, the drain line can be run
directly to it. Valves on these drain lines shall be spring loaded so they remain closed unless held
open.
c. Kinetic Seals. All major flare manufacturers make proprietary seals for their own flares (John
Zink’s Airrestor, National Air Oil (NAO) Fluidic Seal, Kaldair’s Diode Seal). All of these seals use the
upward velocity of the purge gas to reverse the flow of oxygen that penetrates the tip. These seals
have several advantages over other seals (cheaper, less weight, less pressure drop), but they cannot
be used effectively where the flow of purge gas could be interrupted. Kinetic seals will permit air
ingress into the system immediately after purge flow ceases, whereas mol and water seals will be
prevent air ingress for several hours after the purge gas supply is lost.
d. Water Seal. A diversion water seal is used to divert large releases from the operating flare to the
emergency flare. When used, the water seal shall be installed in accordance with Figures 3 or 4 and
Figure 5. In cold climates a water seal may freeze, resulting in blockage of the flare system. A water
seal will prevent air ingress into the pressure relief system, but will not prevent air ingress into the
flare stack after purge flow ceases. A low-temperature alarm shall be installed on the water seal and
its standpipe in freezing climates. A detonation water seal shall be used in services where oxygen
could be present in the header, for example, in Ethylene Oxide service.
Figure 5
Water Seal Drum
9.5 Flare Stacks and Tips
A restricted access zone shall be established around the flare stack in order to control the location of
equipment and access of personnel. The restricted access zone shall be determined based on the
radiation levels listed in the table below.
Tabl e II
Allowable Radiant Heat Intensities in W/m2(Btu/hr/ft2) Excluding Solar Radiation
(1)
Appropriate clothing is clothing for example, coveralls, long sleeved shirts, pants, hard hat
which can shield all body areas except for the face and hands from exposure to flare
radiant heat.
The flare stack diameter shall be equal to or greater than the flare header diameter.
Flare stack height, which is usually determined by allowable radiant heat intensities at grade, shall be
calculated in accordance with the procedure given in Appendix D. Flare stack height can also be governed
by expected dispersion.
The minimum diameter for pipe tips shall be calculated in accordance with the procedure given in
Appendix D.
Requirements for flare tip repair or replacement are as follows:
a. When tip repair or replacement is necessary, the operating flare can be isolated from the
emergency flare header by closing and blinding the valve that is provided. Discharge of vapors from
normal operations can then be temporarily diverted to the emergency flare for smokeless burning.
Immediate repair or replacement of the operating flare tip can proceed without shutting down the
process unit.
b. Multiple flares are another means of providing for onstream flare tip replacement. Two flares of
50 percent capacity will allow flare tip replacement with the process unit throughput decreased by
approximately 50 percent, provided that the two flares are:
(i) Properly spaced to meet allowable radiant heat intensities at grade (see Table D-1)
(ii) Equipped with diversion water seals
(iii) Spaced to meet allowable radiant heat intensities for personnel who are replacing the flare tip
c. Similarly, two flares of 100 percent capacity will allow flare tip replacement without decreasing
any process unit throughput. In either case, one flare shall be used as an operating flare for
smokeless burning of normal operating releases. Diversion seals on multiple flares will allow either
flare to be used as an operating flare.
9.6 Pilots and Igniters
All flares shall be provided with continuously operating or pulsating pilots to prevent flameout and to
ensure that all releases to the flare are burned. The following guidelines shall be used in determining the
number of pilots to be used for each flare:
Flame-front and self-inspirated igniter/pilot gas pressures shall be regulated at 103 kPa gauge (15 psig).
Piping shall be sized to allow flow at approximately 3.5 std m³/h (125 scf/h) per pilot. Typical pilot
installations are shown in Figures 3 and 4. Combination igniter/pilot gas pressure shall be regulated at 69
kPa gauge (10 psig). Product sweet gas, high-pressure trap gas or bottled propane shall be used for pilot
gas.
9.6.1 Pilot Monitoring System. A pilot monitoring system shall be provided.
a. The system shall be arranged to alarm in the control room on loss of flame.
b. Pilot monitoring shall be by thermocouples or flame ionization monitoring.
c. Thermocouples shall be mounted on the pilots to alarm on loss of the pilot flame.
d. Thermocouples shall be positioned so that they are in the reducing part of the pilot flame.
e. Thermocouple components shall be Chromel-Alumel in Inconel sheaths.
f. Flame ionization monitors shall be installed per the manufacturer’s specifications.
9.6.2 Piping
a. Pilot gas piping may be copper tubing to a point 3 m (10 ft) below a combination igniter/pilot. The
remainder of the piping and the igniter/pilot shall be fabricated entirely of Type 309 or Type 310
stainless steel.
b. Piping to other types of pilot heads shall be carbon steel to a point 3 m (10 ft) below the pilot.
Pilot heads and piping shall be constructed of Type 309 or Type 310 stainless steel to a point 3 m (10
ft) below the pilot.
9.6.3 Pilot Ignition. A means of remotely igniting the pilots, which in turn will light the flare gas, shall be
provided. Three systems commonly used are combination igniter/pilots, flame-front generators and
self-inspirated systems.
a. Combination Igniter/Pilots: New combination ignition system/pilots are available for flares of all
types. Automatic re-ignition using integral flame ionization monitoring allows this unit to be used with
propane or intermittent fuels for example, scrubbed well-gas. Gas supplies may be operated manually or controlled automatically when an electric solenoid valve is used with the system. If electric
power is interrupted, the system shall automatically cycle to ignite when the power is restored.
(i) Pilot gas shall be transported via minimum 6 mm (
1
/
in) diameter tubing into the igniter/pilot tip.
(ii) A maximum of 10 igniter/pilots may be controlled with a single control panel. The igniter/pilots
4
may be used in a vertical or horizontal position.
b. Flame-Front Generators: In the flame-front generator, the size of the ignition piping from the
ignition control panel to the flare pilot shall be NPS 1 (NPS = Nominal Pipe Size, inches), with no
change in size anywhere along its route. The ignition control panel shall be located away from the flare
in a safe, accessible location that is free from high radiation levels and free from the hazard of liquid
carryover.
(i) The ignition panel requires compressed air at 103 kPa gauge (15 psig), fuel gas at 103 kPa
gauge (15 psig) and electricity at 110–440 volts AC. The air and gas are mixed at the panel and swept
through the NPS 1 pipe to the flare pilot. When the ignition line is filled with a combustible mixture, the
mixture is spark ignited to generate a flame front that travels through the NPS 1 piping to the pilot.
c. Self-Inspirated Systems: In the self-inspirated ignition system, an eductor is mounted in the
igniter piping near the base of the flare. Fuel gas is piped to the eductor and air is inspirated with the
fuel. The pipeline running from the eductor to the pilot is NPS 2 and shall not exceed 37 m (120 ft) in
length. Directly above the eductor is a cross with a sparking device mounted inside. When the NPS 2
line is filled with a combustible mixture, the sparking device is actuated. The eductor and sparking
device shall be shielded from the radiation of the flare and from any possible liquid carryover. Ignition
heads shall be constructed of Type 309 or Type 310 stainless steel.
9.7 Combustion Assistance (Steam/Air Systems)
a. In most installations, smokeless flaring is required for small discharges of purge gas, relief valve
leakage that occurs during normal operations and discharges that are encountered during unit startup
and shutdown. Smokeless flaring is not required for pressure relief of short duration during a serious
emergency, for example, power failure. Environmental regulatory agencies dictate the degree of
smokeless operation required. However, the operating flare is usually designed for “smokeless”
burning of approximately 10–30 percent of its maximum emergency discharge rate.
b. Providing steam for the smokeless burning of gases from large compressors that have shut down
may not be feasible. Agreement that a compressor shutdown is an emergency and, therefore, does
not require smokeless burning shall be obtained from the local air quality control authorities.
c. Smokeless flaring is usually accomplished by injecting steam into the vapor at the flare tip. The
vendor shall be consulted to determine steam rate. The data shown in Figure 6 can be used to
estimate steam loads and to size steam lines. Numerous acceptable proprietary injection schemes are
commercially available to reduce steam use. Steam control valves shall be located as close as
possible to the flare stack to minimize lag time.
d. When the gases that are being flared contain unsaturated hydrocarbons, the steam requirements
may be substantially higher (see API RP 521).
e. Steam injection to the flare may be controlled either manually or automatically. A thermal sensing
control located in a flare header is not acceptable.
f. SABIC noise requirements and local noise requirements shall be met for discharges up to the
maximum smokeless burning rate. Noise abatement is not usually required for the less frequent
emergency rates greater than the smokeless burning rate.
g. Provision shall be made for injection of air or water into the steam lines to permit flow to the
nozzles when the steam supply is down. Steam keeps the lines, ring and nozzles cool. Damage will
result if the flare is burning without steam flow.
h. Smokeless flaring can also be achieved by injection of high-pressure gas or air into the relief gas
stream. Special multipoint or high-velocity flares can also burn smokelessly. Where the steam capacity is inadequate to allow smokeless burning, particularly when unsaturates are being burned, suppliers
shall be required to submit alternate bids for steam-assisted pipe flares.
i. Air assist technology is also available to allow smokeless flaring without the use of steam. Air
assist designs are available from several vendors.
Figure 6
Dispersant Chart for Smokeless Flaring
9.8 Alternative Flare Design
a. An enclosed ground flare (for example, a Kaldair Concealed Flare, John Zink ZTOF or one of
NAO’s NPAC series or equivalent) may be used in place of the operating flare discussed in Section 9.
This type of flare shall be considered when local regulations require nonluminous burning or when
vibration problems exist. Enclosed flares are limited to maximum burning rates of approximately
90,900 kg/h (200,000 lb/h) for each flare and are significantly more expensive than elevated flares.
b. Staged ground flares (see Figure 7) may be used, especially where smokeless flaring of
unsaturated hydrocarbons is desired without steam use. These flares may be partially enclosed or
open and can be located in a burn pit. These flares usually require large site areas.
c. The staging system is critical and shall have a safety bypass around control valves in the event of
loss of actuator power. Rupture pins are the preferred bypass (see Figure 7).
Figure 7
Staged Multi-Tip Flare
Notes:
All valv
es are bypa
ssed by rup
ture di
sks (RD).
1)
System is designed to handle flow from maximum emergency relief with all valv
es
open.
2)
Number of tips and stages shown is for illustration only.
3)
9.8.1 Comparison of Proprietary Flares
Installation of other proprietary flares can result in savings in steam, purge gas and radiation. When bidding
on a job, suppliers shall be encouraged to present alternate bids that indicate the advantages of their
proprietary models compared with pipe flares. Examples of proprietary flares include Birwelco’s Sonajet
and Kaldair’s entire line of Coanda Effect flares or equivalent. Each design has inherent advantages and
disadvantages, as indicated in the following chart:
9.9 Atmospheric Relief Vents
An atmospheric relief vent is a vertical pipe on the outlet of a pressure relief valve, used for atmospheric
discharge of vapor or gas to a safe location. Atmospheric relief vents shall be designed and constructed as
follows:
a. Atmospheric vent pressure drops shall be calculated using the relief loads determined in
Paragraph 9.1.5, where the discharge velocity of the vapor is to be maintained at 152 m/s (500 ft/s) or
higher. The end diameter of the vent pipe shall be reduced for a length equal to three pipe diameters,
if required, to achieve this velocity. Standard concentric reducers shall be used. Discharge velocity
shall not exceed 80 percent of sonic velocity or dispersion modeling shall be performed to ensure
adequate dispersion.
b. A high-level alarm shall be provided if there is a possibility that liquid will flood the vessel
protected by the PSV during an upset condition. The initial warning given by this type of alarm may
allow the operator to prevent a liquid discharge.
c. Atmospheric vent pipes shall be designed and supported to prevent pipe failure caused by
kinetic forces that develop during a discharge. Dynamic forces should be considered for high
pressure relief.
d. A 6 mm (1/4 in) drain shall be provided at the low point in an atmospheric vent to prevent the
collection of condensate, rain or snow in the discharge pipe. The drain shall be protected from
freezing and shall be piped for safe disposal so that the opening will not endanger personnel or, in the
event of fire, impinge on a vessel surface (see Section 9.2.3).
e. Snuffing steam or inert gas connections shall be provided on all atmospheric vent stacks that
handle flammable vapors. Steam or inert gas is required to extinguish fires that may start at the vent
outlet. Snuffing steam connections are not required in gas plants located outside refineries or in offsite
pressure storage vessels, where steam for this purpose is usually not available.
f. Flame arrestors shall not be installed on atmospheric vents. Arrestor elements can become
plugged with atmospheric dust, process products, products of corrosion or ice during cold weather.
g. Atmospheric relief vents shall terminate to satisfy all of the following at a minimum. Toxic
materials that are vented will have the discharge geometry determined by dispersion modeling.
(i) At least 2 m (6 ft) above the highest adjacent structure or tower
(ii) At least 4 m (12 ft) above the highest adjacent platform
(iii) At least 5 m (15 ft) above grade
h. Located at least 15 m (50 ft) or 120 pipe diameters, whichever is greater, away from the nearest
platform, structure or tower when located at an elevation lower than the platform, structure or tower
i. Located at least 30 m (100 ft) or 120 pipe diameters, whichever is greater, away from the tops of
flue gas stacks or other ignition sources, regardless of the atmospheric vent elevation
j. The effects of radiant heat resulting from ignition of the vapors/gases during discharge shall be
considered when locating the atmospheric vent pipe and its termination point
9.10 Vent Stacks
A vent stack is vertical pipe that transfers discharged vapor and/or gas, from a main collection header to a
safe, elevated location for discharge to the atmosphere. Vent stacks shall comply with the requirements of
Section 6.9 and the following:
a. A knockout drum (scrubber) shall be provided where liquids can enter or condense in the relief
system (see Section 9.3). The knockout drum can be manually drained if the drum is sized to handle
the worst case liquid release and appropriate level instrumentation is provided, including a high-level
alarm which annunciates in a constantly manned location. Knockout drums in unattended locations
shall be provided with automatic level control.
b. Flashback protection shall be provided in accordance with Paragraph 9.4.