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L T- CHIYODA LIMITEDDate: Feb.15, 2007 LTC-PB-P0-004

Rev: 1

PROCEDURE FOR PRESSURESAFETY VALVE CALCULATIONS

AND FLARE SYSTEM DESIGN Page 1 of 116

L&T -CHIYODA PERSONNEL ONLY L&T- CHIYODA PERSONNEL ONLY L&T- CHIYODA PERSONNEL ONLY

PROCEDURE FOR

PRESSURE SAFETY VALVE CALCULATIONS

&

FLARE SYSTEM DESIGN

1 GeneralRevision NUT/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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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 componentparaffin 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. Thesafety of personnel and the protection of equipment due to overpressure are the basis for thedesign, sizing, and selection of pressure relieving systems. All systems and pressure reliefdevices shall meet the applicable codes, industry standards and practices as well as relatedowner/PMC job instructions.

The objective is to apply a systematic examination to all modes of operations and engineeringintentions to the mechanical integrity of the equipment and piping systems based on allcredible incidents. Provisions shall be made to contain or safely relieve any excessive pressuresin 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 inaccordance with project specifications and shall be subject to the vendors quality assuranceand control procedures, including third party inspection.

The practices outlined in this document shall be followed, for all Process unit areas includingrelated Utilities, Offsite, licensor and non-licensor packages. Also this manual presents thestandard 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 (Non

refrigerated 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 inagreement 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 ofspecified design value. The device may be a pressure relief valve, a non-reclosing pressurerelief device or a vacuum relief valve.

Pressure Relief Valve:A pressure relief devicedesigned to open and relieve

excess pressure and to recloseafter normal conditions have been restored.a) . Relief valve : Valve opensnormally in proportion to the

pressure increase over theopening pressure. Used

primarily with incompressiblefluids.b) . Safety valve : Characterized

by rapid opening or pop action.

Normally used withcompressible fluids.c). Safety Relief valve : May beused as either a safety or reliefvalve depending on theapplication.

Non-reclosing pressurerelief device:A pressure relief device

which remains open afteroperation.a) . Rupture disk device :Actuated by staticdifferential pressure

between the inlet &outlet of the device anddesigned to function by

bursting of a rupturedisk.a) . Pin-actuated device :

Actuated by static pressure and designed tofunction by buckling or

breaking a pin, whichholds a piston or plug in

place.

Vacuum reliefDevice:

3.2 System pressures

(Refer Annexure-1, Figure-1) Maximum operating pressure is the maximum pressure expected during normal system

operation. Maximum allowable working pressure (MAWP) is the maximum permissible gauge pressure at the designated coincident temperature. This pressure is determined by thevessel design rules for each element of vessel using actual nominal thickness, exclusiveof any other allowances such as corrosion etc. The MAWP is normally greater than thedesign pressure but must be equal to design pressure when design rules are used only tocalculate the minimum thickness for each element and calculations are not made todetermine 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 the

minimum 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 ordesign 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 ofthe protective equipment. If the MAWP is not defined, the design pressure would beapplicable 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 device

that 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 relief

device at the time the device is required to operate. It is the result of pressure in thedischarge 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 resultsfrom outside pressure sources, external heat input or exothermic reactions. This sectionsummarizes 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 orfor 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 526and 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 ASMECode shall apply. The ASME Code shall be the minimum acceptable where local codes donot 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 affected by 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 theclosed disc by the inlet fluid when the system pressure is at the set pressure of the valve. Whenthe 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 discovercomes 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 theclosing pressure. The difference between the set pressure and the closing pressure is blowdown.

4.1.2 Balanced pressure relief valve

It is a spring-loaded pressure relief valve that incorporates a bellows or other means forminimizing the effect of backpressure on the operational characteristics of the valve. (ReferAnnexure-1, Figure-3)

When a superimposed backpressure is applied to the outlet of a spring-loaded pressure reliefvalve, a pressure force is applied to the valve disc which is additive to the spring force. Thisadded force increases the pressure at which an unbalanced pressure relief valve will open. Ifthe superimposed backpressure is variable then the pressure at which the valve will open willvary (Refer Annexure-1, Figure-22) . In a balanced-bellows pressure relief valve, a bellows isattached to the disc holder with a pressure area A B, approximately equal to the seating area ofthe disc, A N, (Refer Annexure-1, Figure-23) . This isolates an area on the disc, approximatelyequal to the disc seat area, from the backpressure. With the addition of a bellows, therefore, theset 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 toohigh for conventional pressure relief valve. Balanced pressure relief valves may also be used asa means to isolate the guide, spring, bonnet and other top works parts within the valve from therelieving 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 withand 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 floatingunbalanced 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 tothe same inlet operating pressure. Because of the larger area on the top of the piston, the netforce 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 pressureis higher than the percentage shown in Annexure-1, Figure-1. At the set pressure, the pilotvents 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 overpressureincident, 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 inthe 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 a balanced type of pilot, where set pressure is unaffected by backpressure, should be installedwith 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. Regardlessof whether the valve is vented directly to atmosphere or the discharge is piped to a collectionsystem, 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, instabilityor a combination of all three.Backpressure, which is present at the outlet of pressure relief valve when it is required tooperate, is defined as superimposed backpressure. This backpressure can be constant if thevalve outlet is connected to a process vessel or system, which is held at a constant pressure. Inmost cases, however the superimposed backpressure will be variable as a result of changingconditions existing in the discharge system.

Backpressure, which develops in the discharge system after the pressure relief valve opens, isdefined as built-up backpressure. Built-up backpressure occurs due to pressure drop in thedischarge 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 valveacts to hold the valve disc closed with a force additive to the spring force. The actual springsetting can be reduced by an amount equal to the superimposed backpressure to compensate forthis.

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 have pilots which are vented to atmosphere or are balanced to maintain set pressure in the presenceof 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, ifamount of variable superimposed backpressure is small, a conventional valve could be used

provided:

The set pressure has been compensated for any superimposed back pressure normally present 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 outlet piping. 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. Thisinstability may occur as flutter or chatter. Chatter refers to the abnormally rapid reciprocatingmotion of the pressure relief valve disc where the disc contacts the pressure relief valve seatduring 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 seatduring cycling.

In a conventional pressure relief valve application, built-up back pressure should not exceed10% 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 forconventional pressure relief valves or where the superimposed back pressure varies widelycompared 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. Thespecific 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 theunbalanced portion of the disc. This force may result in a reduction in lift and an associatedreduction in flow capacity. Capacity correction factors, called back pressure correction factors,are provided by manufacturer to account for reduction in this flow. Typical backpressurecorrection factors may be found for compressible fluid service in figure-30 and forincompressible 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 shouldbe used.


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4.2.3 Effects of back pressure and header design on pressure relief valve sizing andselection

The pressure relief valve discharge line and flare header must be designed so that the built-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 perapplicable code.

For a balanced pressure relief valve, superimposed backpressure will not affect the set pressure 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 InstallationsMaximum

Set pressure%

Maximum

Accumulated pressure %

Maximum Set

pressure %

Maximum

Accumulated pressure %Nonfire CasesFirst Valve 100 110 100 116Additionalvalve(s)

- - 105 116

Fire CasesFirst Valve 100 121 100 121Additionalvalve(s)

- - 105 121

Supplementalvalve

- - 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 ValueValve Set Pressure Less than MAWP

Protected vessel MAWP, psig 100.0Maximum accumulated pressure, psig 110.0Valve set pressure, psig 90.0Allowable overpressure, psi 20.0Relieving pressure, P 1, psia 124.7

Valve Set Pressure Equal to MAWPProtected vessel MAWP, psig 100.0Maximum accumulated pressure, psig 110.0Valve set pressure, psig 100.0Allowable overpressure, psi 10.0Relieving pressure, P 1, 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 100.0Maximum accumulated pressure, psig 116.0Valve set pressure, psig 100.0Allowable overpressure, psi 16.0Relieving pressure, P 1, psia 130.7

Additional Valve (Set Pressure Equal to 105% of MAWP)Protected vessel MAWP, psig 100.0Maximum accumulated pressure, psig 116.0Valve set pressure, psig 105.0Allowable overpressure, psi 11.0Relieving pressure, P 1, psia 130.7

Example: Determination of Relieving Pressure for a Single-Valve Installation (FireContingencies)

Characteristic ValueValve Set Pressure Less than MAWP

Protected vessel MAWP, psig 100.0Maximum accumulated pressure, psig 121.0

Valve set pressure, psig 90.0Allowable overpressure, psi 31.0Relieving pressure, P 1, psia 135.7


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Valve Set Pressure Equal to MAWPProtected vessel MAWP, psig 100.0

Maximum accumulated pressure, psig 121.0Valve set pressure, psig 100.0Allowable overpressure, psi 21.0Relieving pressure, P 1, psia 135.7

Example: Determination of Relieving Pressure for a Multiple-Valve Installation (FireContingencies)

Characteristic Value First Valve (Set Pressure Equal to MAWP)

Protected vessel MAWP, psig 100.0

Maximum accumulated pressure, psig 121.0Valve set pressure, psig 100.0Allowable overpressure, psi 21.0Relieving pressure, P 1, psia 135.7

Additional Valve (Set Pressure Equal to 105% MAWP)Protected vessel MAWP, psig 100.0Maximum accumulated pressure, psig 121.0Valve set pressure, psig 105.0Allowable overpressure, psi 16.0Relieving pressure, P 1, 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 InstallationsMaximumSet

pressure %

MaximumAccumulated

pressure %(As per ASME PG-72 & PG-67.5)

MaximumSet pressure

%

MaximumAccumulated

pressure %(As per ASME PG-72 & PG-67.5)

First Valve 100 103 ** 100 103 **Additionalvalve

- - 103 103 **

** Maximum up to 106% of MAWP (as per ASME PG-67.2). However, normally safetyvalves 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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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 againstoverpressure 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 asingle fire, a processing area may be divided into a number of smaller single fire risk areas byincreased spacing. A single fire risk area is defined as a group of equipment items that issurrounded 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 thevapor relief load, it is assumed that all (and only) the equipment contained within a single firerisk 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 theanalysis of the vapor collection system (if any) based on fire exposure.

Overpressure protection from fire exposure for heat exchangers: In general, heat exchangers donot need a separate pressure relief device for protection against fire exposure since they areusually protected by pressure relief devices in interconnected equipment or have an openescape path to atmosphere through cooling water return lines. This is true even if the heatexchanger has a manual block valve between it and the pressure relief device since it is notexpected that operators will close this valve during a fire incident. However, in situationswhere 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 theseexchangers are expected to be occasionally isolated from the system. In this case, one of twooptions is available to provide protection: installing a pressure relief device or relying onoperating procedures. If the operating procedure option is used, this operating procedure mustdirect the operators to drain all liquid from the exchanger immediately upon isolating it fromthe system, and maintaining the exchanger dry" and unpressurized during the period of time itis isolated from the pressure relief device that would normally provide protection. To increasethe 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 belowmentioned 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 definedsystem.

LQ

W = ... (Eq.01)

Where adequate drainage and firefighting equipment exist; 82.021000 A F Q = ; For British unit .. (Eq.02) 82.027140 A F Q = ; For Metric unit .. (Eq.03)

Where adequate drainage and firefighting equipment do not exist;

82.034500 A F Q = ; For British unit ..( Eq.04) 82.061000 A F Q = ; For Metric unit ( Eq.05)

Where;British unit Metric unit

W : Relieving Capacity lb/h kg/hQ : Total heat absorption (input) to the

wetted surfaceBtu/h kcal/h

F : Environmental Factor (#1) - - A : Total wetted surface (#2) ft 2 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 liquidas 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 withdesign pressure of 15 psig (100 kPa) or lower see API 2000 for recommended heat absorptiondue to fire

(#1) Environmental Factor

Refer to Annexure-2

(#2) Wetted Surface Exposed to FireThe wetted surface area used to calculate heat absorption for a practical fire situation isnormally 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 variablelevel 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, isused.

2. Vertical Drums - The wetted vessel surface within 25 ft (7.62 m) above grade, based onhigh liquid level, is used.

3. Fractionators and Other Towers - An equivalent tower dumped" level is calculated byadding 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 (7.62m) 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 tothe 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 itsinterconnecting piping should be included in the wetted surface of exposed vessels in a firerisk area. The surface area of piping, other than that for reboiler, is not normally includedin the wetted surface area.

6. Storage tanks - Maximum inventory level up to the height of 25 ft (7.62 m) (portions ofthe wetted area in contact with foundation or ground are normally excluded). For tanks of15-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 directlyabove 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 bedestroyed within the first few minutes of fire exposure.

The following types of air-cooled exchangers need not be considered in the calculation of reliefloads due to fire:

Gas cooling services. There will be no vapor generation due to fire and the tubes are likely tofail 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 wettedarea 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 betaken as zero for forced draft units (the tubes would be shielded from radiant heat exposure bythe fan hood) and as the projected area (length times width) of the tube bundle for induceddraft 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 specificenthalpies 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 willalways occur at the start of the fire, when the wetted surface, A, and consequently, the heatinput, 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 and physical properties of the vapor and liquid in equilibrium with each other change continuouslyas the vaporization proceeds. The peak relief load may or may not coincide with the start ofthe fire. In general, such systems require a time-dependent analysis to determine the requiredrelief area and the corresponding relief rate. The following approach is suggested: Assumethat all vapor and liquid inflows into and outflows from the vessel (other than the fire reliefload) have stopped.

Using the composition of the residual liquid inventory in the vessel, perform a bubble pointflash at the accumulated pressure. In doing this flash, the flow rate of the feed stream to theflash 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 ofmass 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 ofvapor 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 latentheat of vaporization, especially in the case of wide boiling mixtures. The reason is that asignificant portion of the heat absorbed goes into raising the temperature of the system (mostof which is residual liquid at this point) to the equilibrium temperature of the flash (i.e. sensibleheat).

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 orsuper-critical fluid. The following formula should be applied:

( )

= 1506.1

1

25.11

1'

1406.0T

T T A P M W W .( Eq.06)

Where;W : Relieving Capacity lb/hr M : Molecular Weight of Gas lb/lbmole P 1 : Relieving pressure (=set pr.+allow. Over press.+atm. Press.) psia (lb/in

2 A) A : Exposed surface area ft 2 T W : Vessel wall temperature

The recommended maximum vessel wall temp. for the usual carbonsteel plate material is 1100 F (593.33 C). Where vessels arefabricated from alloy materials, the value for T W should be changedto more appropriate recommended maximum.

R

T 1 : Gas temperature, absolute, in R, at the upstream relieving pressure,determined from the relationship,

nn

T P

P T

= 11 Where,Pn : Normal operating gas pressure, psia (lb/in 2 A)Tn : Normal operating gas temp. in R

R

Relieving temperature for wetted & un-wetted surface are often above the design temperatureof the equipment being protected. If, however, the elevated temperature is likely to causevessel 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)


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 beconsidered.The quantity of material to be relieved should be determined at conditions thatcorrespond to the set pressure plus overpressure instead of at normal operatingconditions.The effect of friction drop in the connecting line between the source of overpressure and thesystem being protected should also be considered in determining the capacity requirement.

Base for relief capacity (blocked outlet):Liquid relief Vapor reliefMaximum 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


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 valvesized for total tower overhead will be adequate for this condition, but each case must beexamined in relation to the particular components and system involved.

Pump around Flow Failure - The relief requirement is in the vapor condensed by the pumparound circuit evaluated at the relieving pressure and temperature. Pinch out" of steam heatersmay be considered, if appropriate. When pump around duty is high, or the feed to thefractionators is highly superheated, loss of a pump around may cause a significant reduction intower cooling and result in dry-out of the tower. Therefore, the potential for dry-out should beevaluated. 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 fordetermining relieving rates.

1 Total condensing The relief requirement is the total incoming vapor rate to thecondenser, recalculated at temperature that corresponds to the newvapor composition at relieving pressure and the heat input

prevailing at the time of relief.The surge capacity of the overhead accumulator at the normal liquidlevel is generally limited to less than 10 minutes. If cooling failureexceeds 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 rateshall 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 partialcondensing capacity of 20% to 30% of normal duty is often usedunless the effects at relieving conditions are determined to besignificantly different.

4 Louver closure Louver closure on air-cooled condensers is considered to be totalfailure of the coolant with the resultant capacity established in point1 & 2.

5 Top-tower refluxfailure

Total incoming steam and vapor plus that generated therein atrelieving 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 latentheat of vaporization would correspond to the latent heat underrelieving conditions.

7 Side streamreflux failure

Difference between vapor entering and leaving section at relievingconditions.

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 sidecould 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 thedesign pressure of the high-pressure side, no need to calculate the relieving rate due to tuberupture.

Tube failure shall be considered a potential source of overpressure for the low-pressure side ofheat 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 thetubes 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 requiredfor the specified material or a detailed equipment strategy has been developed, documentedand reviewed by experienced equipment specialists (both mechanical and metallurgical).The equipment strategy must specifically recognize the application of the 6mm corrosionhole concept (see below) and, consider all potential Equipment Degradation Modes. Inaddition, inspection data with similar designs, process conditions and metallurgy shouldconfirm 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 tubesheets (for example pitting from salt deposits, corrosion from acidic condensates or stresscorrosion cracking).

(7) An appropriate tube inspection program will be developed for the exchanger bundle inconsultation with Materials Engineering specialists.

All these heat exchanger types shall be evaluated for potential overpressure in the event ofleakage 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 singletube 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 tubeopening is the difference between the maximum operating pressure of the high-pressure sideand 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 asingle orifice equation with a discharge co-efficient of 0.7. For liquids that do not flash whenthey pass through the opening or vapors, this formula shall be applied.

1. Liquid flow and conventional (conservative) equation for vapor flow:

( ) 12127.0 = P P AW ...( Eq.07) 2. Critical vapor flow:

+

+=

1

1

11 12

7.0k

k

k k P AW

.( Eq.08)

In case k = 1.4 (conservative), then

11685.07.0 = P AW ..( Eq.09) 3. Non critical vapor flow 11685.07.0 = P AW

121 )(27.0 P P AY W = .( Eq.10)

P 2 < 0.5 x P 1


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=

r

r

k

k r Y

k k

k

1

1

1

12

...( Eq.11)

In case k = 1.4 (conservative), then

=r

r r Y

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 x 2

2. For PLHE: (**)m2

P 1 : Absolute upstream pressure based on maximum operating pressure pa a

P 2 : Absolute downstream pressure (PSV set pressure) pa ar : P 2 / P 1 -k : Ratio of specific heat, Cp/Cv -

: Density at upstream pressure kg/m 3

(**) 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 inAPI RP 521.

2) Gasket Failure Mode (Rectangular opening)The potential leak should be quantified as the flow through orifice in the same way we woulddo it for a shell and tube exchanger (assuming flow from the high pressure side set pressure tothe low pressure side relief pressure). The size of the orifice should be calculated as thehydraulic equivalent of a rectangular opening 0.0625 (1/16) inch wide, with a length equal tothe diameter of the relevant inlet or outlet (semi-cylindrical) flow header on the exchanger. TheCrane fluid flow handbook has equations for calculating the "hydraulic radius" for a circularopening 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 indetermining 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 thetransmission signal or operating medium fails, the control device will assume either a fullyopen or fully closed position according to its basic design (the fail-safe position), althoughsome 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 oneautomatic control valve could be either open or closed, regardless of its specified fail-safeaction 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 becalculated based on the installed Cv. If the required relief area for any pressure relief device isdependent 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 beincreased 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 theanalysis 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 ahigh-pressure source into a lower pressure system, followed by loss of liquid level in theupstream vessel and flow of high-pressure vapor. No credit is allowed for the response ofthe level controller, which under normal conditions would close the control valve uponloss of liquid level, since this scenario could be caused by the level controller failure. Ifdetailed 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 eventshould 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 asystem.

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 scenariosshall be analyzed:

(f) The control valve fails wide open with its bypass valve partly open. To calculate therelieving 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 thecontrol 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 passingthrough the valve(s).

Where,P1: Upstream pressure of control valve, kg/cm

2 A

P2: Downstream pressure of control valve, kg/cm 2 A

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 P P C W LVE = ..( Eq.13)

2. Critical vapor flow:

119.56 T

M P C W VE =

...(Eq.14)

3. Non critical vapor flow:

( )22211

311 P P T

C W N VE =

.( Eq.15)

( )22211

7.65 P P T M

C W VE = ..( Eq. 16)

P 1 P 2 x 1.5

P 2 < 0.5 x P 1


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4. Critical Steam Flow:

( )SH VE

T P C

W +

= 00126.0176.11 1

.( Eq.17)

5. Non critical steam flow:

( )SH VE

T

P P C W

+

=00126.01

51.13 222

1

...( Eq.18)

Where,W : Mass flow rate kg/hrC VE : Control valve flow co-efficient, Or

Refer ANNEXURE-5, Ssection 18.5.5 for C VE value table OrRefer (***)

-

P 1 : Pressure at control valve inlet based on the normal operating pressure

kg/cm 2 A

P 2 : Pressure at control valve outlet that is equal to PSV relieving pressure

kg/cm 2 A

M : Molecular weight kg / kgmoleT 1 : Temperature at control valve inlet K

: Upstream vapor density at normal conditions (= M/22.4141) kg/Nm 3 L : Liquid density kg/m 3

T SH : Steam degree of superheat (= Superheated temp. Saturatedtemp.)

K

(***)Alternate method for calculation of Cv (During initial stage before the control valve isselected):

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 bypassconfiguration 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 X150% (50% is by bypass valve open)].

Note:100% CV is process required CV value200% CV is Max CV value300% CV is Max CV + bypass valve open


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7.6 Hydraulic / Thermal Expansion

Refer ANNEXURE- 5, Section-18.5.6 (Examples for Calculation of Relief).Thermal expansion is the increase in liquid volume caused by an increase in temperature. Mostcommon causes are the following:1. Piping or vessels are blocked-in while they are filled with cold liquid and are subsequently

heated by heat tracing, coils, ambient heat gain or fire.2. An exchanger is blocked-in on the cold side with flow in the hot side.3. Piping or vessels are blocked-in while they are filled with liquid at near ambient

temperatures and are heated by direct solar radiation. X 1 (NPS X NPS 1) relief valve is commonly used. Two general applications for whichthermal relieving devices larger than X 1 (NPS X NPS 1) relief valve might be requiredare long pipelines of large diameter in uninsulated aboveground installations and large vessels

or exchangers operating liquid-full.

For liquid full systems, expansion rates for the sizing of relief devices that protect againstthermal expansion of the trapped liquids can be approximated using the following formula:

C G H B

V

=500

.( Eq.19)

C G

H BV

=997

.( Eq.20)

Where,British unit Metric unit

V : Relieving rate Gpm m 3/hr B : Cubical expansion co-efficient (#1) for the liquid at

the expected temperature1/ F 1/ C

H : Total heat transfer rate. For heat exchangers, this can be taken as maximum exchanger duty duringoperation.

Btu/hr kcal/hr

G : Specific gravity referred to water = 1.0 at 60 F.Compressibility of liquid is usually ignored.

- -

C : Specific heat of trapped fluid Btu/lb F kcal/kg C

Typical values of cubical expansion coefficient forhydrocarbon liquids and water at 60 FGravity of liquid (API) Value (per F)3 34.9 0.000435 50.9 0.000551 63.9 0.000664 78.9 0.000779 88.9 0.0008

89 93.9 0.0008594 100 and lighter 0.0009

#1

Water 0.0001

; For British unit

; For Metric unit


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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 overpressurethat can result from electric power failures:

(a) Individual failure of power supplies to any one item of consuming equipment, such as amotor driver for a pump, fan or compressor.

(b) Total failure of power to all consuming equipment in a process unit supplied by a unitsubstation.

(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 ahierarchy of bus bars. With such an arrangement, a design contingency such as a groundfault 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 groundfault in the bus bar. Thus, the impact it will have on the equipment will be affected by thedesign of the substation and the protective equipment provided. Some substations are designedwith normally closed circuit breakers isolating adjacent bus bars, when these are fed from thesame 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 and

perhaps causing the complete substation to fail. The basic philosophy is to assume thatnormally closed circuit breakers will function. For example, if the substation is designed suchthat 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 equipmentconnected to the bus bar having the ground fault. If in the example above, the substation weredesigned 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 lossof 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 powerdelivery. 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 receivingits power at the time of failure. Therefore, the combination of equipment losing power fromany single bus bar fault that results in the highest release rate shall be used as the design basisfor this contingency. Alternatively, the design specification may specify the arrangement ofequipment 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 releasefor 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 andinstrument 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 beconsidered 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 todetermine the extent of failure. For example, consider a cooling water circulating systemconsisting of two parallel pumps in continuous operation, with drivers having different andunrelated sources of power. If one of the two energy sources should fail, credit may be takenfor continued operation of the unaffected pump, provided that the operating pump would nottrip 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 havetwo 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 beconsidered 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 plantoperations.

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 tothe 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 partialor 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 theirlast 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 overpressurethat 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 theoffsite 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 vaporPartial Condenser : Normal condensing rate


7.11 Abnormal Heat Input


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 normalcondensation 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 isinstalled 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


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 overpressurecaused 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 for piping is 133% of the maximum continuous pressure for the specified flange rating at theflange operating temperature.

(2) A pressure relief device is not required to protect a pressure vessel against potentialoverpressure caused by reverse flow if the pressure of the high-pressure source does notexceed 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 thevessels.

(3) For piping or pressure vessels not covered under 1 and 2 above, a pressure relief devicemay be required to protect against potential overpressure caused by reverse flow througha failed check valve. The following scenarios shall be considered:

Scenario No.

Number of CheckValves in Series

Potential Overpressure Scenario

1 1 Partial failure of check valve.

Assume failed check valve behaves as a restrictionorifice with a diameter equal to 1/3 the nominal diameterof the check valve. Use this basis for reverse flow ofliquid, vapor and liquid followed by vapor.

2 2 or more Partial failure of one check valve.

Failed check valve behaves as a restriction orifice with adiameter equal to 1/3 the nominal diameter of the checkvalve. Each of the remaining check valves in series isassumed to behave as a restriction orifice with a diameterequal to 1/10 the nominal diameter of the check valve.

7.13 Loss of Heat in Series fractionation system

In series fractionation, i.e., where the bottoms from the first column feeds into the secondcolumn and the bottoms from the second feeds into the third, it is possible for the loss of heatinput to a column to overpressure the following column. Loss of heat results in some of thelight ends remaining with the bottoms and being transferred to the next column as feed. Underthis circumstance, the overhead load of the second column would consist of its normal vaporload, plus the light ends from the first column. If the second column does not have thecondensing capacity for the additional vapor load, excessive pressure could occur.

7.14 Liquid Overfill


Pressure relief devices are often located in the vapor space of partially liquid filled vessels such


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as towers, distillate drums, refrigeration flash drums, etc., which could overfill during a plantupset. In all cases, if overfill can result in a pressure above the design pressure of the vessel,the pressure relief device must be sized to prevent overpressure due to liquid overfill.

In analyzing liquid overfill, two general scenarios must be considered:(a) Liquid outflows stop while liquid inflows continue at design flow rates.

(b) Liquid inflows increase above design flow rate (for example, due to a control valve failingopen) while liquid outflows continue at the nominal turndown rates (typically, 50% ofdesign). For this case, the possible overfill may be limited by the upstream vesselsinventory.

In determining the required relief capacity of the pressure relief device, credit may be taken forflow through normally open process channels that are not likely to become partially or totally

blocked as a consequence of the overfill. For example, if a steam drum is balanced directly ona steam collection header without any intervening control valves, a failure of the level controlvalve in the full open position will eventually cause the drum to overfill, but credit may betaken up to the capacity of the steam piping to handle the combined flow of incoming water

plus the design steam generation rate. If the steam piping cannot handle the resulting flow ratewithout exceeding the drum MAWP, then the pressure relief device should be sized for thedifference between the incoming flow and the flow rate that can be handled by the steam

piping when the drum is at its accumulated pressure. On the other hand, if there is a controlvalve between the steam drum and the steam collection header, the capacity credit that may betaken will depend on the response of the control valve to the upset and its capacity under theseconditions. Unless the minimum relief capacity available through the control valve can be

predicted with confidence, no credit should be taken for it.

CAUTION: The flow from the pressure relief device because of the overfill contingency may be two phase flow, especially if the inlet flow normally contains vapor. In the event of two- phase flow, the pressure relief device must be designed to relieve the vapor plus liquid, minusthe flow available through remaining normally open outlets, unless a dedicated pressure reliefdevice is installed in the liquid stream to specifically handle the liquid.

Liquid overfill need not be considered as a design contingency for pressure relief device sizing purposes if BOTH of the following are satisfied:

(1) The vessel has a safety critical, independent high level alarm (LHA), and

(2) The vessel vapor space above the independent LHA is equivalent to a 30 minute (or

longer) holdup based on the design liquid inlet rate and a stoppage of the liquid outflow.It is recognized that situations may arise where protection against overpressure caused byliquid overfill by the use of a pressure relief device may not be practical, and/or may beinsufficient to ensure the integrity of the equipment. For example, an existing disposal systemmay lack the capacity to absorb the relief load, or the vessel

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