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TRANSCRIPT
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Rev: 1
PROCEDURE FOR PRESSURE
SAFETY VALVE CALCULATIONS
AND FLARE SYSTEM DESIGNPage 1 of 116
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PROCEDURE FOR
PRESSURE SAFETY VALVE CALCULATIONS
&
FLARE SYSTEM DESIGN
1General
RevisionNUT/MPR NPK/KNK/RHD SS Feb., 15, 2007
0 First Issue SJR SS MH March, 12, 1996
Revision.No.
Description Prepared By Reviewed By ApprovedBy
ApprovedDate
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AND FLARE SYSTEM DESIGNPage 2 of 116
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CONTENTS
1 SCOPE ..................................................................................................................................... 5
2 CODES AND PRACTICES................................................................................................... 5
3 DEFINITION OF TERMS..................................................................................................... 6
3.1 Pressure Relief Device ............................................................................................................ 6
3.2 System pressures ..................................................................................................................... 6
3.3 Device Pressures...................................................................................................................... 7
3.4 Relieving conditions ................................................................................................................ 7
4 PRESSURE RELIEF VALVES............................................................................................. 7
4.1 Types of Pressure Relief Valves............................................................................................. 8
4.2 Back Pressure.......................................................................................................................... 9
5 SET PRESSURE, ACCUMULATION LIMITS AND RELIEVING PRESSURE........ 11
6 OVERPRESSURE................................................................................................................ 14
6.1 Over Pressure Criteria ......................................................................................................... 14
6.2 Principal Causes.................................................................................................................... 15
7 PSV RELIEF LOAD CALCULATIONS AND PHILOSOPHY...................................... 15
7.1 External Fire.......................................................................................................................... 15
7.2 Blocked / Closed Outlets (Exit block).................................................................................. 21
7.3 Cooling or Column Reflux or Pump around failure.......................................................... 21
7.4 Tube Rupture / Plate & Frame Heat Exchanger Failure.................................................. 22
7.5 Control Valve failure............................................................................................................ 25
7.6 Hydraulic / Thermal Expansion .......................................................................................... 28
7.7 Power Failure (Steam or Electric)....................................................................................... 29
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7.8 Instrument Air Failure......................................................................................................... 30
7.9 Air Cooled Exchanger failure.............................................................................................. 30
7.10 Cooling Water failure ........................................................................................................... 31
7.11 Abnormal Heat Input ........................................................................................................... 31
7.12 Check Valve Mal-operation ................................................................................................. 31
7.13 Loss of Heat in Series fractionation system........................................................................ 32
7.14 Liquid Overfill....................................................................................................................... 32
8 SIZING FOR PRESSURE RELIEF VALVE .................................................................... 35
8.1 Sizing for Vapor or gas relief............................................................................................... 35
8.2 Sizing for Steam Relief ......................................................................................................... 37
8.3 Sizing for Liquid Relief ........................................................................................................ 37
9 DESIGN OF PIPING UPSTREAM OF RELIEF DEVICE ............................................. 39
10 DETERMINATION OF FLARE DESIGN CAPACITY.................................................. 40
11 SIZING OF FLARE HEADER ........................................................................................... 42
12 DESIGN OF PIPING DOWNSTREAM OF RELIEF DEVICE...................................... 44
13 FLARE STACK SIZING ..................................................................................................... 45
13.1 Flare Stack Diameter ............................................................................................................ 45
13.2 Flare Stack Height ................................................................................................................ 45
14 DESIGN OF FLARE KNOCKOUT DRUM...................................................................... 47
14.1 Horizontal Knockout Drum................................................................................................. 47
14.2 Vertical Knockout Drum...................................................................................................... 48
15 DESIGN OF SEALS IN FLARE SYSTEM........................................................................ 49
15.1 Sealing of the Flare Stack..................................................................................................... 49
15.2 Sealing of Piping Headers .................................................................................................... 49
16 PURGING OF FLARE HEADER AND FLARE TIP....................................................... 52
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16.1 Procedure for Calculating Flare Header Purge................................................................. 52
16.2 Procedure for Calculating Flare Tip Purge........................................................................ 52
17 P&I DIAGRAM FOR FLARE SYSTEM........................................................................... 52
18 ANNEXURES........................................................................................................................ 53
18.1 Annexure-1 [Tables, Figures (as per API-520/521)].......................................................... 53
18.2 Annexure-2 (Environment factor data) .............................................................................. 68
18.3 Annexure-3 (Vapor pressure and Heat of vaporization of pure single component
paraffin hydrocarbon liquids) ................................................................................. 70
18.4 Annexure-4 (Sizing for Two-phase Liquid/Vapor Relief)................................................. 71
18.5 Annexure-5 (Examples for Calculation of Relief load) ..................................................... 83
18.6 Annexure-6 (Typical Flare Load Summary sheet) .......................................................... 109
18.7 Annexure-7 (Flare Header / PSV outlet line sizing) ........................................................ 110
18.8 Annexure-8 (Flare stack, Figure-A, B) ............................................................................. 112
18.9 Annexure-9 (Flare knock out drum, Figure-C) ............................................................... 114
18.10 Annexure-10 (Seal drum, Figure-D) ................................................................................. 114
18.11 Annexure-11 (Typical flare system P&I Diagram).......................................................... 115
18.12 Format for Relief load calculation sheets ......................................................................... 116
19 OTHER REFERENCES .................................................................................................... 116
19.1 Handbook by Crosby.......................................................................................................... 116
19.2 Questions and Answers for API-520 / 521 ........................................................................ 116
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1.0 SCOPE
This document covers the standard design procedure to perform PSV sizing calculations. The
safety of personnel and the protection of equipment due to overpressure are the basis for the
design, sizing, and selection of pressure relieving systems. All systems and pressure relief
devices shall meet the applicable codes, industry standards and practices as well as related
owner/PMC job instructions.
The objective is to apply a systematic examination to all modes of operations and engineering
intentions to the mechanical integrity of the equipment and piping systems based on all
credible incidents. Provisions shall be made to contain or safely relieve any excessive pressures
in the system. These provisions shall include utilization of the applicable standards as listed in
further sections.The equipment and piping systems shall be designed, fabricated, tested, and assembled in
accordance with project specifications and shall be subject to the vendors quality assurance
and control procedures, including third party inspection.
The practices outlined in this document shall be followed, for all Process unit areas including
related Utilities, Offsite, licensor and non-licensor packages. Also this manual presents the
standard design procedure of a flare system.
2.0 CODES AND PRACTICES
API RP 520 Part I and II : Recommended Practice for the Sizing, Selection andInstallation of Pressure-Relieving Devices in Refineries.
API RP 521: Guide for Pressure-Relieving and Depressuring systems. API STD 526: Flanged Steel Pressure-Relief valves. API STD 527: Commercial Seat Tightness of Safety Relief Valves with Metal to Metal
Seats
API STD 2000: Venting Atmospheric and Low-pressure Storage Tanks (Nonrefrigerated and refrigerated)
ASME Boiler and Pressure Vessel Code, Sec I, Power Boiler ASME Boiler and Pressure Vessel Code, Sec VI, Recommended Rules for Care and
Operation of Heating Boilers ASME Boiler and Pressure Vessel, Sec VIII, Pressure Vessels, including Appendix ANSI/ASME B31.3, Chemical Plant and Petroleum Refinery Piping ANSI/ASME Power Piping B31.
Wherever the code differs and/or conflicts, the more appropriate practice shall apply in
agreement with Client/PMC/Owner.
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3.0 DEFINITION OF TERMS
3.1 Pressure Relief Device
Actuated by inlet static pressure to prevent a rise of internal fluid pressure in excess of
specified design value. The device may be a pressure relief valve, a non-reclosing pressure
relief device or a vacuum relief valve.
Pressure Relief Valve:A pressure relief device
designed to open and relieve
excess pressure and to recloseafter normal conditions have
been restored.
a). Relief valve: Valve opens
normally in proportion to the
pressure increase over the
opening pressure. Used
primarily with incompressible
fluids.
b). Safety valve: Characterized
by rapid opening or pop action.
Normally used withcompressible fluids.
c). Safety Relief valve: May be
used as either a safety or relief
valve depending on the
application.
Non-reclosing pressure
relief device:A pressure relief device
which remains open afteroperation.
a). Rupture disk device:
Actuated by static
differential pressure
between the inlet &
outlet of the device and
designed to function by
bursting of a rupture
disk.
a). Pin-actuated device:
Actuated by staticpressure and designed to
function by buckling or
breaking a pin, which
holds a piston or plug in
place.
Vacuum relief
Device:
3.2 System pressures
(Refer Annexure-1, Figure-1)
Maximum operating pressureis the maximum pressure expected during normal system
operation. Maximum allowable working pressure (MAWP) is the maximum permissible gaugepressure at the designated coincident temperature. This pressure is determined by the
vessel design rules for each element of vessel using actual nominal thickness, exclusive
of any other allowances such as corrosion etc. The MAWP is normally greater than the
design pressure but must be equal to design pressure when design rules are used only to
calculate the minimum thickness for each element and calculations are not made to
determine the value of MAWP. The MAWP is the basis for the pressure setting of the
pressure relief devices.
Design pressure of the vessel along with design temperature is used to determine theminimum permissible thickness of each vessel element. This pressure may be used in
place of MAWP where MAWP has not been established. Design pressure is equal to orless than MAWP.
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Accumulation is the pressure increase over the MAWP of the vessel allowed duringdischarge through pressure relief device, expressed in pressure units or % of MAWP or
design pressure.
Overpressure is the pressure increase over the set pressure of the relieving deviceallowed to achieve rated flow, expressed in pressure units or % of set pressure. It is sameas accumulation when the relieving device is set to open at MAWP of the vessel.
3.3 Device Pressures
Set pressure is the inlet gauge pressure at which the device is set to open under serviceconditions. In general, the set pressure of single installed PSV is equal to the MAWP of
the protective equipment. If the MAWP is not defined, the design pressure would be
applicable for the set pressure.
Backpressure is the pressure that exists at the outlet of pressure relief device as a result ofthe pressure in the discharge system. It is the sum of the superimposed and built-up
backpressures.
Built-up Backpressure is the increase in pressure at the outlet of pressure relief devicethat develops as a result of flow after the pressure relief device or devices open.
Superimposed backpressure is the static pressure that exists at the outlet of pressure reliefdevice at the time the device is required to operate. It is the result of pressure in the
discharge system coming from other source and may be constant or variable.
3.4 Relieving conditions
The term relieving conditions is used to indicate the inlet pressure and temperature on a
pressure relief device during an overpressure condition.
4.0 PRESSURE RELIEF VALVES
Pressure relief devices are required for all equipment subject to overpressure that results
from outside pressure sources, external heat input or exothermic reactions. This section
summarizes the design approach to the sizing and selection of pressure relief devices to
protect equipment against overpressure from operating and fire contingencies.
All pressure relief devices shall be stamped with the ASME Code Symbol for Section I or
for Section VIII application as required.
All pressure relief valves shall be bench tested to verify the set pressure prior to final
installations, except those requiring in situ testing for ASME Section I applications.Acceptable types of pressure relief devices include spring-loaded pressure relief valves,
pilot-operated pressure relief valves, rupture disks and rupture pins.
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.
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.
Weight-loaded pressure relief valves shall not be used without OWNER / PMC approval.
Venting and breathing equipment for low-pressure, aboveground storage tanks at less than
1.03 bar gauge (15 psig) shall be sized as specified by API STD 2000, Sections 1-3 or APISTD 620, Section 6.
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4.1 Types of Pressure Relief Valves
4.1.1 Conventional pressure relief valve
It is a spring loaded pressure relief valve whose operational characteristics are directly affectedby changes in the backpressure. (Refer Annexure-1, Figure-2)
The operation of a conventional spring loaded pressure relief valve is based on a force balance
(Refer Annexure-1, Figure-19). The spring load is preset to equal the force exerted on the
closed disc by the inlet fluid when the system pressure is at the set pressure of the valve. When
the inlet pressure is below the set pressure, the disc remains seated on the nozzle in the closed
position. When the inlet pressure exceeds set pressure, the pressure force on the disc
overcomes the spring force and the valve opens. When inlet pressure is reduced to a level
below the set pressure, the valve re-closes. The pressure at which the valve re-seats is the
closing pressure. The difference between the set pressure and the closing pressure is blow
down.
4.1.2 Balanced pressure relief valve
It is a spring-loaded pressure relief valve that incorporates a bellows or other means for
minimizing the effect of backpressure on the operational characteristics of the valve. (Refer
Annexure-1, Figure-3)
When a superimposed backpressure is applied to the outlet of a spring-loaded pressure relief
valve, a pressure force is applied to the valve disc which is additive to the spring force. This
added force increases the pressure at which an unbalanced pressure relief valve will open. If
the superimposed backpressure is variable then the pressure at which the valve will open will
vary (Refer Annexure-1, Figure-22).In a balanced-bellows pressure relief valve, a bellows is
attached to the disc holder with a pressure area AB, approximately equal to the seating area of
the disc, AN, (Refer Annexure-1, Figure-23). This isolates an area on the disc, approximately
equal to the disc seat area, from the backpressure. With the addition of a bellows, therefore, the
set pressure of the pressure relief valve will remain constant in spite of variations in back
pressure. It is important to remember that the bonnet of a balanced pressure relief valve must
be vented to the atmosphere at all times for the bellows to perform properly.
When the superimposed backpressure is constant, the spring load can be reduced to
compensate for the effect of backpressure on set pressure and a balanced valve is not required.Balanced pressure relief valves should be considered where the built up backpressure is too
high for conventional pressure relief valve. Balanced pressure relief valves may also be used as
a means to isolate the guide, spring, bonnet and other top works parts within the valve from the
relieving fluid.
4.1.3 Pilot operated pressure relief valve
It is a pressure relief valve in which the major relieving device or main valve is combined with
and controlled by a self-actuated auxiliary pressure relief valve (pilot). (Refer Annexure-1,
Figure-6)
A pilot operated relief valve consists of the main valve, which normally encloses a floating
unbalanced piston assembly, and an external pilot. The piston is designed to have a larger area
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on the top than on the bottom. Up to the set pressure, the top and bottom areas are exposed to
the same inlet operating pressure. Because of the larger area on the top of the piston, the net
force holds the piston tightly against the main valve nozzle. As the operating pressure
increases, the net seating force increases and tends to make the valve tighter. This featureallows most pilot operated valves to be used where the maximum expected operating pressure
is higher than the percentage shown in Annexure-1, Figure-1. At the set pressure, the pilot
vents the pressure from the top of the piston; the resulting net force is now upward causing the
piston to lift, and process flow is established through the main valve. After the overpressure
incident, the pilot will close the vent from the top of the piston; thereby re-establishing
pressure, and the net force will cause the piston to reseat.
The lift of the main valve piston or diaphragm, unlike a conventional or balanced spring-
loaded valve, is not affected by built-up backpressure. This allows for even higher pressures in
the relief discharge manifolds. The pilot vent can be either directly exhausted to atmosphere or
to the main valve outlet depending upon the pilots design and users requirement. Only abalanced type of pilot, where set pressure is unaffected by backpressure, should be installed
with its exhaust connected to a location with varying pressure (such as to main valve outlet).
Slight variations in back pressure may be acceptable for unbalanced pilots.
4.2 Back Pressure
Pressure existing at the outlet of a pressure relief valve is defined as backpressure. Regardless
of whether the valve is vented directly to atmosphere or the discharge is piped to a collection
system, the backpressure may affect the operation of the pressure relief valve. Effects due to
backpressure may include variations in opening pressure, reduction in flow capacity, instability
or a combination of all three.
Backpressure, which is present at the outlet of pressure relief valve when it is required to
operate, is defined as superimposed backpressure. This backpressure can be constant if the
valve outlet is connected to a process vessel or system, which is held at a constant pressure. In
most cases, however the superimposed backpressure will be variable as a result of changing
conditions existing in the discharge system.
Backpressure, which develops in the discharge system after the pressure relief valve opens, is
defined as built-up backpressure. Built-up backpressure occurs due to pressure drop in the
discharge system as a result of flow from the pressure relief valve.
The magnitude of the backpressure, which exists at the outlet of a pressure relief valve, after ithas opened, is the total of the superimposed and built-up backpressure.
4.2.1 Effects of superimposed back pressure on pressure relief valve opening
Superimposed backpressure at the outlet of a conventional spring loaded pressure relief valve
acts to hold the valve disc closed with a force additive to the spring force. The actual spring
setting can be reduced by an amount equal to the superimposed backpressure to compensate for
this.
Balanced pressure relief valves utilize a bellow or piston to minimize or eliminate the effect of
superimposed backpressure on set pressure. Many pilot operated pressure relief valves havepilots which are vented to atmosphere or are balanced to maintain set pressure in the presence
of variable superimposed back pressure. Balanced spring loaded or pilot operated pressure
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relief valves should be considered if the superimposed backpressure is variable. However, if
amount of variable superimposed backpressure is small, a conventional valve could be used
provided:
The set pressure has been compensated for any superimposed back pressure normallypresent and
The maximum pressure during relief does not exceed the code-allowed limits foraccumulation in the equipment being protected.
4.2.2 Effects of back pressure on pressure relief valve operation and flow capacity
Conventional Pressure Relief Valves:
Conventional pressure relief valves show unsatisfactory performance when excessive
backpressure develops during a relief incident, due to the flow through the valve and outletpiping. The backpressure tends to reduce the lifting force, which is holding the valve open.
Excessive built-up backpressure can cause the valve to operate in an unstable manner. This
instability may occur as flutter or chatter. Chatter refers to the abnormally rapid reciprocating
motion of the pressure relief valve disc where the disc contacts the pressure relief valve seat
during cycling. This type of operation may cause damage to the valve and interconnecting
piping. Flutter is similar to chatter except that the disc does not come in to contact with the seat
during cycling.
In a conventional pressure relief valve application, built-up back pressure should not exceed
10% of the set pressure at 10% allowable overpressure. When the back pressure is expected toexceed these specified limits, a balanced or pilot operated pressure relief valve should be
specified.
Balanced Pressure Relief Valves:
A balanced pressure relief valve should be used where the built-up backpressure is too high for
conventional pressure relief valves or where the superimposed back pressure varies widely
compared to the set pressure. Balanced valves can typically be applied where the total back
pressure (superimposed + built-up) does not exceed approx. 50% of the set pressure. The
specific manufacturer should be consulted concerning the backpressure limitation of a
particular valve design.
With a balanced valve, high backpressure will tend to produce a closing force on the
unbalanced portion of the disc. This force may result in a reduction in lift and an associated
reduction in flow capacity. Capacity correction factors, called back pressure correction factors,
are provided by manufacturer to account for reduction in this flow. Typical backpressure
correction factors may be found for compressible fluid service in figure-30 and for
incompressible fluid (liquid) service in figure-31.
Pilot-Operated Pressure Relief Valves:
For pilot-operated pressure relief valves, the valve lift is not affected by back pressure. Forcompressible fluids at critical flow conditions, a back pressure correction factor of 1.0 should
be used.
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4.2.3 Effects of back pressure and header design on pressure relief valve sizing and
selection
The pressure relief valve discharge line and flare header must be designed so that thebuilt-up backpressure does not exceed the allowable limits.
In addition, the flare header system must be designed in order to ensure that thesuperimposed backpressure caused by venting or relief from another source will not
prevent relief valve from opening at a pressure adequate to protect equipment as per
applicable code.
For a balanced pressure relief valve, superimposed backpressure will not affect the setpressure of the relief valve. However total backpressure may affect the capacity of the
relief valve. Sizing a balanced relief valve is a two step process:- The relief valve is sized using a preliminary backpressure correction factor, Kb.
- Once a preliminary valve size and capacity is determined, the discharge line and
header size can be determined based on pressure drop calculations.
- The final size, capacity, backpressure and backpressure correction factor can then
be calculated.
For a pilot operated pressure relief valve, neither the set pressure nor the capacity istypically affected by backpressure for compressible fluids at critical flow conditions.
Tail pipe and flare header sizing are typically based on other considerations.
5.0 SET PRESSURE, ACCUMULATION LIMITS AND RELIEVING PRESSURE
Contingency Single Valve Installations Multiple Valve Installations
Maximum
Set pressure%
Maximum
Accumulatedpressure %
Maximum Set
pressure %
Maximum
Accumulatedpressure %
Nonfire Cases
First Valve 100 110 100 116
Additional
valve(s)
- - 105 116
Fire Cases
First Valve 100 121 100 121
Additional
valve(s)
- - 105 121
Supplemental
valve
- - 110 121
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All values are % of MAWP. The maximum accumulated pressure equals to the relieving
pressure of PSV.
Example: Determination of Relieving Pressure for a Single-Valve Installation (OperatingContingencies)
Characteristic Value
Valve Set Pressure Less than MAWP
Protected vessel MAWP, psig 100.0
Maximum accumulated pressure, psig 110.0
Valve set pressure, psig 90.0
Allowable overpressure, psi 20.0
Relieving pressure, P1, psia 124.7
Valve Set Pressure Equal to MAWPProtected vessel MAWP, psig 100.0
Maximum accumulated pressure, psig 110.0
Valve set pressure, psig 100.0
Allowable overpressure, psi 10.0
Relieving pressure, P1, psia 124.7
Example: Determination of Relieving Pressure for a Multiple-Valve Installation
(Operating Contingencies)
Characteristic Value
First Valve (Set Pressure Equal to MAWP)Protected vessel MAWP, psig 100.0
Maximum accumulated pressure, psig 116.0
Valve set pressure, psig 100.0
Allowable overpressure, psi 16.0
Relieving pressure, P1, psia 130.7
Additional Valve (Set Pressure Equal to 105% of MAWP)
Protected vessel MAWP, psig 100.0
Maximum accumulated pressure, psig 116.0
Valve set pressure, psig 105.0
Allowable overpressure, psi 11.0Relieving pressure, P1, psia 130.7
Example: Determination of Relieving Pressure for a Single-Valve Installation (Fire
Contingencies)
Characteristic Value
Valve Set Pressure Less than MAWP
Protected vessel MAWP, psig 100.0
Maximum accumulated pressure, psig 121.0
Valve set pressure, psig 90.0Allowable overpressure, psi 31.0
Relieving pressure, P1, psia 135.7
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Valve Set Pressure Equal to MAWP
Protected vessel MAWP, psig 100.0
Maximum accumulated pressure, psig 121.0Valve set pressure, psig 100.0
Allowable overpressure, psi 21.0
Relieving pressure, P1, psia 135.7
Example: Determination of Relieving Pressure for a Multiple-Valve Installation (Fire
Contingencies)
Characteristic Value
First Valve (Set Pressure Equal to MAWP)
Protected vessel MAWP, psig 100.0
Maximum accumulated pressure, psig 121.0Valve set pressure, psig 100.0
Allowable overpressure, psi 21.0
Relieving pressure, P1, psia 135.7
Additional Valve (Set Pressure Equal to 105% MAWP)
Protected vessel MAWP, psig 100.0
Maximum accumulated pressure, psig 121.0
Valve set pressure, psig 105.0
Allowable overpressure, psi 16.0
Relieving pressure, P1, psia 135.7
For steam Boilers:
As per ASME Boiler and Pressure Vessel Code, Section-I,
Set pressure and Accumulation limits
Single Valve Installations Multiple Valve Installations
Maximum
Set
pressure %
Maximum
Accumulated
pressure %(As per ASME PG-
72 & PG-67.5)
Maximum
Set pressure
%
Maximum
Accumulated
pressure %(As per ASME PG-
72 & PG-67.5)
First Valve 100 103 ** 100 103 **
Additional
valve
- - 103 103 **
** Maximum up to 106% of MAWP (as per ASME PG-67.2). However, normally safety
valves shall be designed to attain full lift at a pressure no greater than 3% above their set
pressure (As per ASME PG-72).
All values are % of MAWP. The maximum accumulated pressure equals to the relieving
pressure of PSV.
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Number of PSVs
Each boiler shall have at least one safety valve / safety relief valve and if it has more than
500 ft2(47 m2) of bare tube water heating surface, or if an electric boiler has a power input
more than 1100 kW, it shall have two or more safety valve / safety relief valves. For aboiler with combined bare tube and extended water-heating surface exceeding 500 ft2(47
m2), two or more safety valve / safety relief valves are required only if the design steam
generating capacity of the boiler exceeds 4000 lb/hr (1800 kg/hr).
6.0 OVERPRESSURE
6.1 Over Pressure Criteria
All equipment and piping systems must be protected when the internal or external pressure can
exceed the design condition of the system due to an emergency, upset condition, operationalerror, instrument malfunction or fire. Pressure relieving devices are installed to ensure that a
system or any of its components are not subjected to pressures that exceed the code-allowable
pressure accumulation. Any circumstance that reasonably constitutes an overpressure type
hazard under the prevailing conditions shall be analyzed and evaluated.
Assumptions
- It is assumed that trained operators will staff the plant.
- In evaluating a given emergency condition, certain assumptions must be made
concerning equipment not affected by the emergency in order that relief rate may be
determined.
- The simultaneous occurrence of two or more conditions which could result in
overpressure will not be considered if the causes are unrelated, i.e., if no process,
mechanical, or electrical commonality exists among the causes.
- The opening and closing action of control valves and the automatic start-up of
equipment will not be considered as a substitute for pressure relieving devices for
equipment protection because power supply to these items in an emergency is not
considered reliable. As a general rule, final overpressure protection is to be provided
by means of a mechanical pressure-relieving device.
- Equipment not affected by a utility failure being evaluated will be considered to remainin operation while control functions and other systems will be assumed to operate as
designed.
- Flow rates through the equipment and other conditions during the emergency will be
assumed to be at the normal rates except where the particular primary emergency case
under consideration would alter the flow.
- In case of fire, the flow is assumed to have stopped and been contained within a defined
system.
- The possibility of an operator inadvertently opening or closing any one valve or taking
any incorrect action in the wrong sequence or at the wrong time will be considered.
(However, block valves, electric switches, and other equipment items that are locked or
car sealed in the correct position will not be considered involved in any cases of
operator error).
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6.2 Principal Causes
The following lists some common principal causes of overpressure, which shall be analyzed to
determine the individual relieving flow rates for pressure relieving devices. Also, clarification
of the failure and overpressure protection device is provided where applicable.
The list is not intended to be all-inclusive but is intended to serve as a guide.
1. External Fire
2. Exit Block Or Blocked Outlet
3. Cooling Or Column Reflux Failure Or Pump around failure
4. Tube Rupture
5. Control Valve Failure
6. Hydraulic / Thermal Expansion7. Power Failure
8. Instrument Air Failure
9. Loss of fan in air cooled exchangers
10. Cooling water failure
11. Abnormal heat input to reboiler.
12. Check Valve mal-operation
13. Loss of Heat in series fractionation system
14. Liquid Overfill
7.0 PSV RELIEF LOAD CALCULATIONS AND PHILOSOPHY
7.1 External Fire
Assume that all fluid flow to the equipment has stopped, and that the liquid level inside the
equipment is at the top of its normal working range.
In calculating fire loads from individual vessels, assume that vapor is generated by fire
exposure and heat transfer to contained liquids at operating conditions. The calculation
procedure is as mentioned below.
For determining pressure relief device capacity for several interconnected vessels, each vesselshould be calculated separately, rather than determining the heat input on the basis of the
summation of the total wetted surfaces of all vessels. Vapors generated by normal process heat
input are not considered. No credit is taken for any escape path for fire load vapors other than
through the pressure relief device (which may be a common relief valve for more than one
connected vessel), nor is credit allowed for reduction in the fire load by the continued
functioning of condensers or coolers.
Equipment, which normally operates dry, must be evaluated for the expansion of vapor or
supercritical fluid due to fire. A procedure is as mentioned under section for unwetted area
calculations.
The insulation system for an equipment item shall be considered individually. Credit may betaken for equipment insulation in reducing the required relief load if project specifications
concerning fireproofing insulation are met.
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See calculation procedure for details.
For vessels filled with both a liquid and a solid (such as molecular sieves or catalysts), the
behavior of the vessel contents normally precludes the cooling effect of liquid boiling. Hence
fireproofing and depressurizing should be considered as alternatives to protection by pressurerelief devices, unless provision of pressure relief is required by local regulations.
Piping and piping components are generally not considered to require protection against
overpressure due to fire exposure, consistent with requirements of ASME B31.3.
To determine the total vapor capacity to be relieved when several vessels are exposed to a
single fire, a processing area may be divided into a number of smaller single fire risk areas by
increased spacing. A single fire risk area is defined as a group of equipment items that is
surrounded on all sides by clear access ways that are at least 6 metre wide. The space under
pipe racks is considered an access way if it is at least 6 metre wide. For the estimation of the
vapor relief load, it is assumed that all (and only) the equipment contained within a single fire
risk area is exposed to the same fire. The largest of the vapor relief loads calculated from eachof the individual fire risk areas into which the plant is subdivided is used as the basis for the
analysis of the vapor collection system (if any) based on fire exposure.
Overpressure protection from fire exposure for heat exchangers: In general, heat exchangers do
not need a separate pressure relief device for protection against fire exposure since they are
usually protected by pressure relief devices in interconnected equipment or have an open
escape path to atmosphere through cooling water return lines. This is true even if the heat
exchanger has a manual block valve between it and the pressure relief device since it is not
expected that operators will close this valve during a fire incident. However, in situations
where a fail-close control valve or an automatically actuated emergency isolation valve could
isolate the heat exchanger from the pressure relief device providing protection against fireexposure, a separate pressure relief device to protect the exchanger may be required.
Fire exposure protection for heat exchangers that are provided with blocks and bypasses to
permit cleaning while the rest of the unit is operating, present a special situation. Again,
interconnected equipment usually provides the required overpressure protection but these
exchangers are expected to be occasionally isolated from the system. In this case, one of two
options is available to provide protection: installing a pressure relief device or relying on
operating procedures. If the operating procedure option is used, this operating procedure must
direct the operators to drain all liquid from the exchanger immediately upon isolating it from
the system, and maintaining the exchanger dry" and unpressurized during the period of time it
is isolated from the pressure relief device that would normally provide protection. To increase
the probability that this operating procedure is followed, a caution sign to that effect shall be
permanently placed at the block valves of all exchangers equipped with a bypass.
Fire exposure overpressure protection for air-cooled exchangers is discussed in below
mentioned calculation procedure.
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CALCULATION PROCEDURE FOR EXTERNAL FIRE SCENARIO:
Refer ANNEXURE-5, Section-18.5.1 (Examples for Calculation of Relief).
1. For Wetted Surface:
The following formula should be applied. The process flows from / to the system would
be stopped and the protective equipment is assumed to be contained within defined
system.
L
QW = ...(Eq.01)
Where adequate drainage and firefighting equipment exist;82.021000 AFQ = ; For British unit..(Eq.02)
82.027140 AFQ = ; For Metric unit..(Eq.03)
Where adequate drainage and firefighting equipment do not exist;
82.034500 AFQ = ; For British unit..(Eq.04)
82.061000 AFQ = ; For Metric unit(Eq.05)
Where;
British unit Metric unit
W : Relieving Capacity lb/h kg/h
Q : Total heat absorption (input) to the
wetted surface
Btu/h kcal/h
F : Environmental Factor (#1) - -
A : Total wetted surface (#2) ft2 m2
L : Latent heat (#3) Btu/lb kcal/kg
In calculating the total wetted surface of the equipment, the expanded volume of the liquid inthe vessel should be used. The expanded volume includes the thermal expansion of the liquid
as it is heated from its initial temperature to its boiling point at the accumulated vessel
pressure.
These equations apply to process vessels and pressurized storage. For storage vessels with
design pressure of 15 psig (100 kPa) or lower see API 2000 for recommended heat absorption
due to fire
(#1) Environmental Factor
Refer to Annexure-2
(#2) Wetted Surface Exposed to Fire
The wetted surface area used to calculate heat absorption for a practical fire situation is
normally taken to be the total wetted surface within 25 ft (7.62 m) above grade. Grade"
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usually refers to ground level, but any other level at which a major fire could be sustained,
such as a solid platform, should also be considered. In the case of vessels containing a variable
level of liquid, the high level is considered. Specific interpretations of A to be used for various
vessels are as follows:1. Horizontal Drums
The wetted vessel surface within 25 ft (7.62 m) above grade, based on high liquid level, is
used.
2. Vertical Drums - The wetted vessel surface within 25 ft (7.62 m) above grade, based on
high liquid level, is used.
3. Fractionators and Other Towers - An equivalent tower dumped" level is calculated by
adding the liquid holdup on the trays to the liquid at high liquid level hold up at the tower
bottom. The surface that is wetted by this equivalent level and which is within 25 ft (7.62
m) above grade is used. Level in the reboiler is to be included, if reboiler is an integral
part of the column
4. Storage Spheres - The total surface exposed within 25 ft (7.62 m) above grade, or up to
the elevation of the centerline whichever is greater, is used.
5. Shell and Tube Heat Exchangers and Piping - The surface area of a tower reboiler and its
interconnecting piping should be included in the wetted surface of exposed vessels in a fire
risk area. The surface area of piping, other than that for reboiler, is not normally included
in the wetted surface area.
6. Storage tanks - Maximum inventory level up to the height of 25 ft (7.62 m) (portions of
the wetted area in contact with foundation or ground are normally excluded). For tanks of
15-psig operating pressure or less; see API STD 2000.
7. Air Cooled Exchangers:
Refer to API RP 521 sect. 3.15.7
Or
Only that portion of the bare surface on air-cooled exchangers located within the fire zone area
being evaluated needs to be considered in the calculation of fire loads. Air fins located directly
above pipe racks are also normally excluded since they are shielded from radiation by the
piping. The bare area is used instead of the finned area because most types of fins would be
destroyed within the first few minutes of fire exposure.
The following types of air-cooled exchangers need not be considered in the calculation of relief
loads due to fire:
Gas cooling services. There will be no vapor generation due to fire and the tubes are likely to
fail due to overheating.
Air-cooled partial or total condensers that meet the following criteria:
a. The tubes are sloped so that they are self-draining.
b. There is no control valve or pump connected directly to the condenser liquid outlet.
For these services, condensation will stop in the event of a fire, and any residual condensate
will drain freely to the downstream receiver. However, in this case, the normal condensingload for the air-cooled condenser must be added to the calculated fire load from other sources,
unless it can be established that the source of condensing vapors would stop in the event of a
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fire.
For air-cooled condensers that do not meet the above criteria, and for liquid coolers, the wetted
area used to calculate the relief load should be the bare area of the tubes located within the fire
zone area and within 25 feet (7.5m) above grade (or any other surface at which a major firecould be sustained, such as a solid platform). For tubes located higher than 25 feet (7.5m)
above grade (or other surface at which a major fire could be sustained), the wetted area shall be
taken as zero for forced draft units (the tubes would be shielded from radiant heat exposure by
the fan hood) and as the projected area (length times width) of the tube bundle for induced
draft units.
8. Piping:
It may be appropriate to add a percentage of the vessel area to account for vapor generation in
piping associated with the vessel under consideration.
(#3) Latent Heat calculationsIf relieving pressure is beyond critical pressure, use 50 Btu/lb as latent heat.
Single Component Systems:
Refer to Annexure-3 (Vapor pressure and Heat of vaporization for pure single component
paraffin hydrocarbon liquids)
Or
For single component systems, the term equals the latent heat of vaporization at relievingconditions. It may be determined from a flash calculation as the difference in the specific
enthalpies o f the vapor and liquid phases in equilibrium with each other, or it may be obtained
from API RP 521, Appendix A, Figure A-1 or other literature sources. For such systems, thelatent heat, the vaporization temperature, and the physical properties of the liquid and vapor
phases in equilibrium remain constant as the vaporization proceeds. The peak relief load will
always occur at the start of the fire, when the wetted surface, A, and consequently, the heat
input, Q, are both at a maximum.
Multi-component Systems:Refer to Annexure-3 (Vapor pressure and Heat of vaporization for pure single component
paraffin hydrocarbon liquids)
Or
For multi-component systems, the vaporization of the liquid initially in the vessel at the start of
the fire proceeds as a batch distillation in which the temperature, vapor flow rate andphysical properties of the vapor and liquid in equilibrium with each other change continuously
as the vaporization proceeds. The peak relief load may or may not coincide with the start of
the fire. In general, such systems require a time-dependent analysis to determine the required
relief area and the corresponding relief rate. The following approach is suggested: Assume
that all vapor and liquid inflows into and outflows from the vessel (other than the fire relief
load) have stopped.
Using the composition of the residual liquid inventory in the vessel, perform a bubble point
flash at the accumulated pressure. In doing this flash, the flow rate of the feed stream to the
flash can be set at any arbitrary value. For convenience, it is suggested that the mass flow rate
be set numerically equal to the mass inventory of liquid initially in the vessel or 1000 units of
mass flow rate (lb/h or kg/s).
Flash the liquid from the preceding flash at constant pressure and the weight percent vaporized
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equal to 1% to 5%. Divide the heat duty calculated for this flash by the mass flow rate of
vapor generated. The result is the heat absorbed per unit mass of vapor generated, . NOTETHAT, IN GENERAL, THIS VALUE WILL NOT EQUAL THE LATENT HEAT OF
VAPORIZATION, NOR WILL IT EQUAL THE DIFFERENCE IN VAPOR AND LIQUIDSPECIFIC ENTHALPIES. In fact, the value thus calculated will generally exceed the latent
heat of vaporization, especially in the case of wide boiling mixtures. The reason is that a
significant portion of the heat absorbed goes into raising the temperature of the system (most
of which is residual liquid at this point) to the equilibrium temperature of the flash (i.e. sensible
heat).
Using the value of calculated from Step 3; calculate the relief vapor rate, W
2. For Un-wetted Surface:Un-wetted wall vessels are those in which the internal walls are exposed to a gas, vapor or
super-critical fluid. The following formula should be applied:
( )
=
1506.1
1
25.1
11
'1406.0
T
TTAPMW W .(Eq.06)
Where;
W : Relieving Capacity lb/hr
M : Molecular Weight of Gas lb/lbmole
P1 : Relieving pressure (=set pr.+allow. Over press.+atm. Press.) psia (lb/in2A)
A : Exposed surface area ft2
TW : Vessel wall temperature
The recommended maximum vessel wall temp. for the usual carbon
steel plate material is 1100 F (593.33 C). Where vessels are
fabricated from alloy materials, the value for TW should be changed
to more appropriate recommended maximum.
R
T1 : Gas temperature, absolute, in R, at the upstream relieving pressure,
determined from the relationship,
n
n
T
P
PT
= 11
Where,
Pn: Normal operating gas pressure, psia (lb/in2A)
Tn: Normal operating gas temp. in R
R
Relieving temperature for wetted & un-wetted surface are often above the design temperature
of the equipment being protected. If, however, the elevated temperature is likely to cause
vessel rupture, additional protective measures should be considered such as:
Cooling the surface of a vessel with water Depressuring systems
Earth-covered storage
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7.2 Blocked / Closed Outlets (Exit block)
Refer ANNEXURE-5, Section-18.5.2(Examples for Calculation of Relief).
The capacity of the relief device must be at least as great as the capacity of the sources of
pressure. If all outlets are not blocked, the capacity of the unblocked outlets may properly be
considered.
The quantity of material to be relieved should be determined at conditions that
correspond to the set pressure plus overpressure instead of at normal operating
conditions.The effect of friction drop in the connecting line between the source of overpressure and the
system being protected should also be considered in determining the capacity requirement.
Base for relief capacity (blocked outlet):
Liquid relief Vapor relief
Maximum liquid pump-in rate Total incoming steam and vapor that
generated therein at relieving conditions
7.3 Cooling or Column Reflux or Pump around failure
Refer ANNEXURE-5, Section-18.5.3(Examples for Calculation of Relief).
Reflux Flow Failure - In some cases, failure of reflux (e.g., pump shutdown or valve closure)
will cause flooding of the condenser, which is equivalent to the pressure relief valve capacity
required for total loss of coolant. Compositional changes caused by loss of reflux may producedifferent vapor properties, which affect the relieving capacity. Usually, a pressure relief valve
sized for total tower overhead will be adequate for this condition, but each case must be
examined in relation to the particular components and system involved.
Pump around Flow Failure - The relief requirement is in the vapor condensed by the pump
around circuit evaluated at the relieving pressure and temperature. Pinch out" of steam heaters
may be considered, if appropriate. When pump around duty is high, or the feed to the
fractionators is highly superheated, loss of a pump around may cause a significant reduction in
tower cooling and result in dry-out of the tower. Therefore, the potential for dry-out should be
evaluated. The relief load due to fractionators dry-out is usually the sum of the entire vapor
feeds entering the fractionator plus any stripping steam or reboiler vapor (where applicable).Because of the difficulty in calculating detailed heat and material balances at relieving
pressure, the simplified bases described in following table have generally been accepted for
determining relieving rates.
1 Total condensing The relief requirement is the total incoming vapor rate to the
condenser, recalculated at temperature that corresponds to the new
vapor composition at relieving pressure and the heat input
prevailing at the time of relief.
The surge capacity of the overhead accumulator at the normal liquid
level is generally limited to less than 10 minutes. If cooling failure
exceeds this time, reflux is lost, and the overhead composition,temperature and vapor rate may change significantly.
2 Partial The relief requirement is the difference between the incoming and
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condensing outgoing vapor rate at relieving conditions. The incoming vapor rate
shall be calculated on the same basis as total condensing.
If the composition or rate of the reflux is changed, the incoming
vapor rate to the condenser should be determined for the newconditions.
3 Fan Failure (AFC
failure)
Because of natural convection effects, credit for a partial
condensing capacity of 20% to 30% of normal duty is often used
unless the effects at relieving conditions are determined to be
significantly different.
4 Louver closure Louver closure on air-cooled condensers is considered to be total
failure of the coolant with the resultant capacity established in point
1 & 2.
5 Top-tower reflux
failure
Total incoming steam and vapor plus that generated therein at
relieving conditions less vapor condensed by side stream reflux.
6 Pump aroundcircuit
The relief requirement is the vaporization rate caused by an amountof heat equal to that removed in the pump around circuit. The latent
heat of vaporization would correspond to the latent heat under
relieving conditions.
7 Side stream
reflux failure
Difference between vapor entering and leaving section at relieving
conditions.
7.4 Tube Rupture / Plate & Frame Heat Exchanger Failure
Refer ANNEXURE- 5, Section-18.5.4(Examples for Calculation of Relief).
Regarding the heat exchangers, there are some failure modes where the lower pressure side
could be exposed to fluid from the high-pressure side.
When design pressure of the low-pressure side is equal to or greater than ten-thirteenth the
design pressure of the high-pressure side, no need to calculate the relieving rate due to tube
rupture.
Tube failure shall be considered a potential source of overpressure for the low-pressure side of
heat exchangers except for the following heat exchanger types:
(a) Tubular reactors and waste heat boilers with tubes 1.5 in. (38 mm) and larger in diameter,
in which the tubes have wall thickness equivalent to process piping, and in which the
tubes are welded to the tube sheet.,
(b) Double-pipe exchangers except those with multiple tubes.
(c) Shell and tube exchangers that meet ALL of the following criteria:
(1) Tube vibration is not likely based on a rigorous tube vibration analysis.
(2) Tube wall thickness is at least one standard gauge thicker than the minimum required
for the specified material or a detailed equipment strategy has been developed, documented
and reviewed by experienced equipment specialists (both mechanical and metallurgical).
The equipment strategy must specifically recognize the application of the 6mm corrosion
hole concept (see below) and, consider all potential Equipment Degradation Modes. In
addition, inspection data with similar designs, process conditions and metallurgy should
confirm that no degradation has been found.
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(3) The tubes are not subject to erosion.
(4) The tubes will operate at temperatures warmer than -150F (-101C).
(5) The tubes are not subject to fatigue or creep.
(6) The process fluid will not cause aggressive corrosion or degradation of tubes and tube
sheets (for example pitting from salt deposits, corrosion from acidic condensates or stress
corrosion cracking).
(7) An appropriate tube inspection program will be developed for the exchanger bundle in
consultation with Materials Engineering specialists.
All these heat exchanger types shall be evaluated for potential overpressure in the event of
leakage through a 0.25in. (6mm) Hole due to corrosion.
If a pressure relief device is required to protect the low-pressure side, the relief rate is defined
by the maximum flow through the two open ends resulting from a guillotine cut of a single
tube at the tube sheet. In calculating this maximum flow rate, it is assumed that the normal
process flow into the low-pressure side has stopped and the pressure difference across the tube
opening is the difference between the maximum operating pressure of the high-pressure side
and the design (set) and/or relieving pressure of the low-pressure side.
Flow rate capacity from both side of a ruptured tube is defined as follows. It is based on a
single orifice equation with a discharge co-efficient of 0.7. For liquids that do not flash when
they pass through the opening or vapors, this formula shall be applied.
1. Liquid flow and conventional (conservative) equation for vapor flow:
( ) 12127.0 = PPAW ...(Eq.07)
2. Critical vapor flow:
+
+
=1
1
111
27.0
k
k
kkPAW
.(Eq.08)
In case k = 1.4 (conservative), then
11685.07.0 = PAW ..(Eq.09)
3. Non critical vapor flow 11685.07.0 = PAW
121 )(27.0 PPAYW = .(Eq.10)
P2 < 0.5 x P1
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=
r
r
k
krY
k
k
k
1
1
1
1
2
...(Eq.11)
In case k = 1.4 (conservative), then
=
r
rrY
1
15.3
286.043.1
.(Eq.12)
Where,
W : Mass flow rate kg/s
A : 1. For STHE: Cross sectional area of one side of ruptured tube x2
2. For PLHE: (**)
m2
P1 : Absolute upstream pressure based on maximum operating pressure pa a
P2 : Absolute downstream pressure (PSV set pressure) pa ar : P2/ P1 -
k : Ratio of specific heat, Cp/Cv -
: Density at upstream pressure kg/m3
(**) Plate and Frame Heat Exchanger failure case:
The following two types of failure modes are recommended based on experience(s) in past
projects
1) Failure mode of a 6 mm "pinhole" from one side to the other, which is referenced in
API RP 521.
2) Gasket Failure Mode (Rectangular opening)
The potential leak should be quantified as the flow through orifice in the same way we would
do it for a shell and tube exchanger (assuming flow from the high pressure side set pressure to
the low pressure side relief pressure). The size of the orifice should be calculated as the
hydraulic equivalent of a rectangular opening 0.0625 (1/16) inch wide, with a length equal to
the diameter of the relevant inlet or outlet (semi-cylindrical) flow header on the exchanger. The
Crane fluid flow handbook has equations for calculating the "hydraulic radius" for a circular
opening equivalent to a flow path of arbitrary cross-section. This method has the advantage of
being based on vendor input, and is consistent with the most industry practice.
For two phase flashing fluids, the flow models developed by DIERS and others shall be used in
determining the relieving rate through the failure.
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7.5 Control Valve failure
Refer ANNEXURE- 5, Section-18.5.5(Examples for Calculation of Relief).
Automatic control devices are generally actuated directly from the process or indirectly from a
process variable (cascaded), e.g., pressure, flow, liquid level, or temperature. When the
transmission signal or operating medium fails, the control device will assume either a fully
open or fully closed position according to its basic design (the fail-safe position), although
some devices can be designed to remain stationary in the last controlled position.
When examining a process system for overpressure potential, it shall be assumed that any one
automatic control valve could be either open or closed, regardless of its specified fail-safe
action under loss of its transmission signal or operating medium.
When the control valve size (flow coefficient, Cv) is known it shall be assumed that this sizevalve is installed, and the maximum flow rate through the fully open control valve shall be
calculated based on the installed Cv. If the required relief area for any pressure relief device is
dependent on, or may be affected by, the maximum flow rate through a control valve, a
permanent sign shall be attached to the control valve stating that the installed Cv shall not be
increased without confirming the capacity of any pressure relief device that may be impacted
by the proposed change.
As a minimum, the following individual control valve failures shall be considered in the
analysis of control systems for determination of pressure relief requirements:
(a) Failure in the closed position of a control valve in an outlet stream from a vessel orsystem.
(b) Failure in the wide-open position of a control valve admitting fluid (liquid or vapor/gas)
from a high-pressure source into a lower pressure system.
(c) Failure in the wide open position of a control valve which normally passes liquid from a
high-pressure source into a lower pressure system, followed by loss of liquid level in the
upstream vessel and flow of high-pressure vapor. No credit is allowed for the response of
the level controller, which under normal conditions would close the control valve upon
loss of liquid level, since this scenario could be caused by the level controller failure. If
detailed analysis indicates that flow through the wide-open control valve is mixed phase,
then this should be considered when determining the maximum flow through the controlvalve. High pressure may also be generated in the piping system as a result of liquid slugs
being pushed by the vapor; hence the potential for excessive pressure from this event
should also be evaluated.
(d) Failure in the closed position of a control valve in a stream removing heat from a system.
(e) Failure in the open position of a control valve in a stream providing energy (heat) to a
system.
When a control valve is equipped with a bypass, the installed flow coefficient (Cv) of the
bypass valve shall not exceed that of the control valve. The following additional scenarios
shall be analyzed:
(f) The control valve fails wide open with its bypass valve partly open. To calculate the
relieving rate for this case, the flow rate through the partly open bypass valve is calculated
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using a Cv for the partially open bypass valve equal to 50% of the installed Cv of the
control valve in its wide-open position, regardless of the actual size of the bypass valve.
(g) The bypass valve is wide open with the control valve closed or blocked-in. The relieving
rate for this case is the flow rate through the wide-open bypass valve using the installedCv of the bypass valve in its fully open position.
For the control valve or its by pass valve that gives high differential pressure as described
below, the capacity of downstream PSV must be at least as great as the capacity passing
through the valve(s).
Where,
P1: Upstream pressure of control valve, kg/cm2A
P2: Downstream pressure of control valve, kg/cm2A
Flow rate through a Failure opened control valve is calculated as follows:
1. Liquid flow and conventional (conservative) equation for vapor or steam flow:
( )213.27 PPCW LVE = ..(Eq.13)
2. Critical vapor flow:
1
19.56T
MPCW VE =
...(Eq.14)
3. Non critical vapor flow:
( )22211
311 PPT
CW NVE =
.(Eq.15)
( )22211
7.65 PPT
MCW VE = ..(Eq. 16)
P1 P2 x1.5
P2 < 0.5 x P1
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4. Critical Steam Flow:
( )SHVE
T
PC
W +
= 00126.01
76.11 1.(Eq.17)
5. Non critical steam flow:
( )SH
VE
T
PPCW
+
=
00126.01
51.132
2
2
1
...(Eq.18)
Where,
W : Mass flow rate kg/hr
CVE : Control valve flow co-efficient, Or
Refer ANNEXURE-5, Ssection 18.5.5for CVEvalue table Or
Refer (***)
-
P1 : Pressure at control valve inlet based on the normal operating
pressure
kg/cm2A
P2 : Pressure at control valve outlet that is equal to PSV relieving
pressure
kg/cm2A
M : Molecular weight kg / kgmole
T1 : Temperature at control valve inlet K
: Upstream vapor density at normal conditions (= M/22.4141) kg/Nm3
L : Liquid density kg/m3
TSH : Steam degree of superheat (= Superheated temp. Saturated
temp.)
K
(***)
Alternate method for calculation of Cv (During initial stage before the control valve is
selected):
1. At first, please calculate process required CV value for corresponding control valve.2. Use 200 % of calculated required CV value for PSV calculation for no bypass
configuration across control valve.
3. Use 300% of calculated required CV value for PSV calculation with bypass valve
(same size as that of main control valve) configuration [take as 200% is max CV X
150% (50% is by bypass valve open)].
Note:
100% CV is process required CV value
200% CV is Max CV value
300% CV is Max CV + bypass valve open
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If the blocked-in liquid has a vapor pressure higher than the relief design pressure, then the
pressure relief device should be capable of handling the vapor generation rate.
7.7 Power Failure (Steam or Electric)
(1) Normal Individual and Process Unit Basis for Pressure Relief Sizing Considerations
The following contingencies shall be considered as the basis for evaluating overpressure
that can result from electric power failures:
(a) Individual failure of power supplies to any one item of consuming equipment, such as a
motor driver for a pump, fan or compressor.
(b) Total failure of power to all consuming equipment in a process unit supplied by a unit
substation.
(c) General failure of power to all equipment supplied from any one bus bar in a substationservicing one or more process units. Note that some substation designs include a
hierarchy of bus bars. With such an arrangement, a design contingency such as a ground
fault in a higher-level bus bar will result in loss of all power to the lower level bus bars.
In the case of the bus bar contingency, the basic assumption for this contingency is a ground
fault in the bus bar. Thus, the impact it will have on the equipment will be affected by the
design of the substation and the protective equipment provided. Some substations are designed
with normally closed circuit breakers isolating adjacent bus bars, when these are fed from the
same electrical feeder. When a ground fault occurs in a bus bar, these circuit breakers open,
thus isolating the fault and preventing the ground fault from extending to other bus bars andperhaps causing the complete substation to fail. The basic philosophy is to assume that
normally closed circuit breakers will function. For example, if the substation is designed such
that a single feeder provides power to two bus bars separated by a normally closed circuit
breaker, the design contingency for this design would be the loss of power to the equipment
connected to the bus bar having the ground fault. If in the example above, the substation were
designed without any circuit breaker, then the design contingency would be the loss of both
bus bars.
Other substation designs use normally open circuit breakers that are meant to close upon loss
of a power source to permit continued operation by obtaining power from a different source.
Since this type of protection implies action by a device/instrument in order to preventoverpressure in the equipment, no credit may be taken for the potential continuation of power
delivery. Hence, the contingency of loss of power to a bus and the normally open circuit
breaker failing to close and reestablish power needs is evaluated as a design contingency.
During design it may not be known from which bus bar a piece of equipment will be receiving
its power at the time of failure. Therefore, the combination of equipment losing power from
any single bus bar fault that results in the highest release rate shall be used as the design basis
for this contingency. Alternatively, the design specification may specify the arrangement of
equipment within the available bus bars.
For units in which spared equipment is supplied from different bus bars in the same substation,
loss of any one bus bar will, on average, result in loss of power to one-half of the equipment.Hence, for the design of a closed flare header system, a release equal to one-half of the release
for the worst combination of equipment loss can be assumed as a design contingency.
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(2) Consideration of Plant-wide Power Failure
The following general power failures on a plant-wide scale must be considered.
(a) Failure of purchased power supply to the plant.
(b) Failure of internally generated power supply to the plant.
(c) Total power failure in any one major substation
Total electrical power failure may result in loss of seawater, cooling water, steam and
instrument air if these utilities rely on electrically driven equipment for their availability.
In case of partial failure, equipment that is not affected by the failure of concern will be
considered to remain in operation and the controls will be assumed to operate as designed.
Reference to the electrical one-line diagrams and steam system P&IDs shall be made to
determine the extent of failure. For example, consider a cooling water circulating system
consisting of two parallel pumps in continuous operation, with drivers having different and
unrelated sources of power. If one of the two energy sources should fail, credit may be taken
for continued operation of the unaffected pump, provided that the operating pump would not
trip out due to overloading. Similarly, credit may be taken for partial continued operation of
parallel, normally operating instrument air compressors and electric power generators that have
two unrelated sources of energy to the drivers.
Backup systems which depend upon the action of automatic startup devices (e.g., a turbine-
driven standby spare for a motor-driven cooling water pump, with PLC control) shall not be
considered an acceptable means of preventing a utility failure for normal pressure relief design
purposes, even though their installation may be fully justified by improved reliability of plant
operations.
In cases of fan failure of the air-cooled exchangers, refer to section7.9
7.8 Instrument Air Failure
In case of total instrument air failure, the inventory in the instrument air receiver/header shall
be adequate to allow a safe shutdown without causing overpressure and subsequent release to
the flare header.
The failure position of control valves upon loss of instrument air shall be specified such that
potential hazards, including overpressure, are minimized. It shall be assumed that, upon partial
or total loss of instrument air, all control valves affected by the failure will assume their
specified failure position. Control valves that are specified to initially fail stationary shall beeither assumed to drift to their specified ultimate failure position or assumed to remain at their
last controlling position, whichever condition is more restrictive from an overpressure
protection standpoint.
7.9 Air Cooled Exchanger failure
Loss of air-cooled exchanger capacity may result from fan failure, inadvertent louver closure,
pitch control failure, or variable speed motor driver failure.
Refer Section-18.5.7, ANNEXURE- 5(Examples for Calculation of Relief).
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7.10 Cooling Water failure
(1) Normal Individual and Process Unit Basis for Pressure Relief Sizing Considerations
The following design contingencies shall be considered as the basis for evaluating overpressure
that can result from cooling water failures:
(a) Individual failure of water supply to any one cooler or condenser.
(b) Total failure of any one lateral supplying a process unit that can be isolated from the
offsite main.
(2) Consideration of Plant-wide Failure
The following general cooling water failures shall be considered:
(a) Failure of any section of the offsite cooling water main.
(b) Loss of all the cooling water pumps that would result from any design contingency in theutility systems supplying or controlling the pump drivers.
Relief load calculation can be done based on the following conditions:
Total Condenser : Total normal incoming vapor
Partial Condenser : Normal condensing rate
Refer Section-18.5.8, ANNEXURE- 5(Examples for Calculation of Relief).
7.11 Abnormal Heat Input
Refer Section-18.5.9, ANNEXURE- 5(Examples for Calculation of Relief).
The required capacity is the maximum rate of vapor generation at relieving conditions
(including any non-condensable produced from over-heating) less the rate of normal
condensation or vapor outflow.
In every case potential behavior of the system and each of its components shall be considered.
Some examples are:
Design value should be used for an item such as valve. Built-in overcapacity shall be used for burners, heater etc. Where limit stops are installed on valves, the wide-open capacity, rather than the
capacity at the stop setting, should normally be used. However, if mechanical stop is
installed and is adequately documented, use of the limited capacity may be appropriate.
In Shell & Tube heat exchange equipment, heat input should be calculated on the basisof clean rather than fouled conditions.
7.12 Check Valve Mal-operation
Refer ANNEXURE- 5, Section-18.5.10(Examples for Calculation of Relief).
A check valve is not effective for preventing overpressure by reverse flow from a high-
pressure source. Experience indicates a substantial leakage through check valves.
The following guidelines apply to the evaluation of reverse flow through check valves as a
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potential source of overpressure.
(1) A pressure relief device is not required to protect piping against potential overpressure
caused by reverse flow if the pressure of the high-pressure source does not exceed the
short-term allowable overpressure for piping. The short term allowable overpressure forpiping is 133% of the maximum continuous pressure for the specified flange rating at the
flange operating temperature.
(2) A pressure relief device is not required to protect a pressure vessel against potential
overpressure caused by reverse flow if the pressure of the high-pressure source does not
exceed MAWP of the vessel. With the explicit approval of the OWNER / PMC, on a case-
by-case basis, a pressure relief device may not required if reverse flow from the high-
pressure source does not exceed the maximum allowable accumulated pressure of the
vessels.
(3) For