PSV and Flare

L&T- CHIYODA LIMITED PROCEDURE FOR PRESSURE SAFETY VALVE CALCULATIONS AND FLARE SYSTEM DESIGN

Date: Feb.15, 2007 Rev: 1

LTC-PB-P0-004 Page 1 of 116

PROCEDURE FOR PRESSURE SAFETY VALVE CALCULATIONS & FLARE SYSTEM DESIGN

1 0 Revision. No.

General Revision First Issue Description

NUT/MPR NPK/KNK/RHD SJR Prepared By

SS Reviewed By

SS

Feb., 15, 2007

MH Approved By

March, 12, 1996 Approved Date

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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 vendor’s 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 and Installation 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 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 reclose after 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 with compressible 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 after operation. 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 static pressure and designed to function by buckling or breaking a pin, which holds a piston or plug in place.

Vacuum Device:

relief

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 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 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 or less than MAWP.

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•

PROCEDURE FOR PRESSURE SAFETY VALVE CALCULATIONS AND FLARE SYSTEM DESIGN

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•

Accumulation is the pressure increase over the MAWP of the vessel allowed during discharge 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 device allowed to achieve rated flow, expressed in pressure units or % of set pressure. It is same as 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 service conditions. 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 of the 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 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 API STD 620, Section 6.

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4.1

PROCEDURE FOR PRESSURE SAFETY VALVE CALCULATIONS AND FLARE SYSTEM DESIGN

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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 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 feature allows 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 springloaded 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 pilot’s design and user’s requirement. Only a balanced 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 it has 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 have pilots 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 normally present and The maximum pressure during relief does not exceed the code-allowed limits for accumulation 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. 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 to exceed 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. For compressible 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 the built-up backpressure does not exceed the allowable limits.

•

In addition, the flare header system must be designed in order to ensure that the superimposed 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 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 is typically 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

Nonfire Cases First Valve Additional valve(s) Fire Cases First Valve Additional valve(s) Supplemental valve

Single Valve Installations Maximum Maximum Set pressure Accumulated % pressure %

Multiple Valve Installations Maximum Set Maximum pressure % Accumulated pressure %

100 -

110 -

100 105

116 116

100 -

121 -

100 105

121 121

-

-

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 (Operating Contingencies) Characteristic Valve Set Pressure Less than MAWP Protected vessel MAWP, psig Maximum accumulated pressure, psig Valve set pressure, psig Allowable overpressure, psi Relieving pressure, P1, psia Valve Set Pressure Equal to MAWP Protected vessel MAWP, psig Maximum accumulated pressure, psig Valve set pressure, psig Allowable overpressure, psi Relieving pressure, P1, psia

Value 100.0 110.0 90.0 20.0 124.7

100.0 110.0 100.0 10.0 124.7

Example: Determination of Relieving Pressure for a Multiple-Valve Installation (Operating Contingencies) Characteristic First Valve (Set Pressure Equal to MAWP) Protected vessel MAWP, psig Maximum accumulated pressure, psig Valve set pressure, psig Allowable overpressure, psi Relieving pressure, P1, psia Additional Valve (Set Pressure Equal to 105% of MAWP) Protected vessel MAWP, psig Maximum accumulated pressure, psig Valve set pressure, psig Allowable overpressure, psi Relieving pressure, P1, psia

Value 100.0 116.0 100.0 16.0 130.7

100.0 116.0 105.0 11.0 130.7

Example: Determination of Relieving Pressure for a Single-Valve Installation (Fire Contingencies) Characteristic Valve Set Pressure Less than MAWP Protected vessel MAWP, psig Maximum accumulated pressure, psig Valve set pressure, psig Allowable overpressure, psi Relieving pressure, P1, psia

Value 100.0 121.0 90.0 31.0 135.7

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Valve Set Pressure Equal to MAWP Protected vessel MAWP, psig Maximum accumulated pressure, psig Valve set pressure, psig Allowable overpressure, psi Relieving pressure, P1, psia

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100.0 121.0 100.0 21.0 135.7

Example: Determination of Relieving Pressure for a Multiple-Valve Installation (Fire Contingencies) Characteristic First Valve (Set Pressure Equal to MAWP) Protected vessel MAWP, psig Maximum accumulated pressure, psig Valve set pressure, psig Allowable overpressure, psi Relieving pressure, P1, psia Additional Valve (Set Pressure Equal to 105% MAWP) Protected vessel MAWP, psig Maximum accumulated pressure, psig Valve set pressure, psig Allowable overpressure, psi Relieving pressure, P1, psia

Value 100.0 121.0 100.0 21.0 135.7

100.0 121.0 105.0 16.0 135.7

For steam Boilers: ♦

As per ASME Boiler and Pressure Vessel Code, Section-I, Set pressure and Accumulation limits

First Valve Additional valve

Single Valve Installations Multiple Valve Installations Maximum Maximum Maximum Maximum Set Accumulated Set pressure Accumulated pressure % pressure % % pressure % (As per ASME PG(As per ASME PG72 & PG-67.5) 72 & PG-67.5) 100 103 ** 100 103 ** 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 a boiler 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, operational error, 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 remain in 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. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14.

External Fire Exit Block Or Blocked Outlet Cooling Or Column Reflux Failure Or Pump around failure Tube Rupture Control Valve Failure Hydraulic / Thermal Expansion Power Failure Instrument Air Failure Loss of fan in air cooled exchangers Cooling water failure Abnormal heat input to reboiler. Check Valve mal-operation Loss of Heat in series fractionation system 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 vessel should 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 be taken 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 pressure relief 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 each of 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 fire exposure, 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.

=

W

Q L

…………………………………………………………….……..(Eq.01)

Where adequate drainage and firefighting equipment exist;

Q = 21000

× F × A

0 . 82

; For British unit……………………..(Eq.02)

Q = 27140

× F × A

0 . 82

; For Metric unit…………….……….(Eq.03)

Where adequate drainage and firefighting equipment do not exist;

Q = 34500

× F × A

0 . 82

; For British unit…………….……….(Eq.04)

Q = 61000

× F × A

0 . 82

; For Metric unit………………………(Eq.05)

Where; W Q

: :

F A L

: : :

British unit Relieving Capacity lb/h Total heat absorption (input) to the Btu/h wetted surface Environmental Factor (#1) Total wetted surface (#2) ft2 Latent heat (#3) Btu/lb

Metric unit kg/h kcal/h m2 kcal/kg

In calculating the total wetted surface of the equipment, the expanded volume of the liquid in the 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 condensing load 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 fire could 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 calculations If 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 λ equals the latent heat of vaporization at relieving conditions. 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, the latent 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 and physical 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, λ. NOTE THAT, IN GENERAL, THIS VALUE WILL NOT EQUAL THE LATENT HEAT OF VAPORIZATION, NOR WILL IT EQUAL THE DIFFERENCE IN VAPOR AND LIQUID SPECIFIC 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 λ 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:

W = 0 . 1406 ×

⎛ A ' (T W − T 1 )1 . 25 M × P1 × ⎜⎜ 1 . 1506 T1 ⎝

⎞ ⎟ ⎟ ⎠

……….(Eq.06)

Where; W : M : P1 : A’ : TW :

lb/hr lb/lbmole psia (lb/in2 A) ft2 °R

T1

°R

Relieving Capacity Molecular Weight of Gas Relieving pressure (=set pr.+allow. Over press.+atm. Press.) Exposed surface area 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. : Gas temperature, absolute, in °R, at the upstream relieving pressure, determined from the relationship,

⎛ P1 T 1 = ⎜⎜ ⎝ Pn

⎞ ⎟⎟ T ⎠

n

Where, Pn : Normal operating gas pressure, psia (lb/in2 A) Tn : Normal operating gas temp. in °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 Maximum liquid pump-in rate

7.3

Vapor relief Total incoming steam and vapor generated therein at relieving conditions

that

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 produce different 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 fractionator’s 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

2

Partial

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. The relief requirement is the difference between the incoming and

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condensing

3

Fan Failure (AFC failure)

4

Louver closure

5

Top-tower reflux failure Pump around circuit

6

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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 new conditions. 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. Louver closure on air-cooled condensers is considered to be total failure of the coolant with the resultant capacity established in point 1 & 2. Total incoming steam and vapor plus that generated therein at relieving conditions less vapor condensed by side stream reflux. The relief requirement is the vaporization rate caused by an amount of 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 -150°F (-101°C). (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:

W = 0 . 7 A 2 × (P1 − P2 ) × ρ 1 2.

……………………...(Eq.07)

Critical vapor flow: P2 < 0.5 x P1

⎛ 2 ⎞ W = 0 . 7 A P1 × ρ 1 × k ⎜ ⎟ k 1 + ⎝ ⎠

⎛ k +1 ⎞ ⎜ ⎟ ⎝ k −1 ⎠

……….…(Eq.08)

In case k = 1.4 (conservative), then

W = 0 . 7 × 0 . 685 × A 3.

P1 × ρ 1

………….….(Eq.09)

Non critical vapor flow W = 0.7 × 0.685 × A P1 × ρ1

W = 0 .7 × Y × A

2 ( P1 − P2 ) ρ 1

……….…(Eq.10)

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Y =

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r

⎛ 2 ⎞ ⎜⎜ ⎟ ⎝ k ⎠

⎛ k −1 ⎞ ⎛ ⎜ ⎟ ⎝ k ⎠ ⎜ ⎛ k ⎞⎜ 1 − r ⎜ ⎟ ⎝ k − 1 ⎠ ⎜⎜ 1 − r ⎝

⎞ ⎟ ⎟ ⎟⎟ ⎠

LTC-PB-P0-004 Page 24 of 116

………………...…(Eq.11)

In case k = 1.4 (conservative), then

Y =

r

1 . 43

⎛ 1 − r 0 . 286 × 3 . 5 ⎜⎜ ⎝ 1− r

⎞ ⎟⎟ ⎠

……….…………(Eq.12)

Where, W : Mass flow rate A : 1. For STHE: Cross sectional area of one side of ruptured tube x 2 2. For PLHE: (**) P1 : Absolute upstream pressure based on maximum operating pressure P2 : Absolute downstream pressure (PSV set pressure) : P2 / P1 r k : Ratio of specific heat, Cp/Cv  : Density at upstream pressure

kg/s m2 pa a pa a 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

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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 size valve 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 or system. (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 control valve. 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 installed Cv 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). P1

P2 x 1.5

Where, P1: Upstream pressure of control valve, kg/cm2 A P2: Downstream pressure of control valve, kg/cm2 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:

W = 27 . 3 × C VE 2.

Critical vapor flow:

ρ L × (P1 − P2 ) ……….…….(Eq.13)

P2 < 0.5 x P1

M T1

W = 56 . 9 × C VE × P1

3.

……….……………..(Eq.14)

Non critical vapor flow:

W = 311 × C VE

W = 65 . 7 × C VE

ρN T1

(P

M T1

− P2

2

1

(P

1

2

2

)

− P2

……….………(Eq.15)

2

)

……….….(Eq. 16)

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Critical Steam Flow:

W

5.

=

11 . 76 × C 1 + (0 . 00126

VE

× P1 × T SH

) ……….…………(Eq.17)

Non critical steam flow:

W

Where, : W CVE : P1

:

P2

:

M T1

: : : : :

L

TSH

=

13 . 51 × C 1 +

VE

(0 . 00126

P1

2

× T

− P2 SH

2

)

Mass flow rate Control valve flow co-efficient, Or Refer ANNEXURE-5, Ssection 18.5.5 for CVE value table Or Refer (***) Pressure at control valve inlet based on the normal operating pressure Pressure at control valve outlet that is equal to PSV relieving pressure Molecular weight Temperature at control valve inlet Upstream vapor density at normal conditions (= M/22.4141) Liquid density Steam degree of superheat (= Superheated temp. – Saturated temp.)

.……..(Eq.18)

kg/hr kg/cm2 A kg/cm2 A kg / kgmole K kg/Nm3 kg/m3 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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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. Most common 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. ¾” X 1” (NPS ¾ X NPS 1) relief valve is commonly used. Two general applications for which thermal relieving devices larger than ¾” X 1” (NPS ¾ X NPS 1) relief valve might be required are 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 against thermal expansion of the trapped liquids can be approximated using the following formula:

V =

B×H 500 × G × C

V =

B× H 997 × G × C

;

For British unit .…………………(Eq.19)

;

For Metric unit .………………(Eq.20)

Where, British unit Relieving rate Gpm Cubical expansion co-efficient (#1) for the liquid at 1/ °F the expected temperature Total heat transfer rate. For heat exchangers, this can Btu/hr be taken as maximum exchanger duty during operation. Specific gravity referred to water = 1.0 at 60 °F. Compressibility of liquid is usually ignored. Specific heat of trapped fluid Btu/lb °F

V B

: :

H

:

G

:

C

:

#1

Typical values of cubical expansion coefficient for hydrocarbon liquids and water at 60 °F Gravity of liquid (°API) Value (per °F) 3 – 34.9 0.0004 35 – 50.9 0.0005 51 – 63.9 0.0006 64 – 78.9 0.0007 79 – 88.9 0.0008 89 – 93.9 0.00085 94 – 100 and lighter 0.0009 Water 0.0001

Metric unit m3/hr 1/ °C kcal/hr

kcal/kg °C

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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 substation servicing 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 and perhaps 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 prevent overpressure 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&ID’s 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 turbinedriven 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 be either 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 the utility systems supplying or controlling the pump drivers. Relief load calculation can be done based on the following conditions: Total Condenser Partial Condenser

: :

Total normal incoming vapor 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 basis of 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 highpressure 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 for piping 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 caseby-case basis, a pressure relief device may not required if reverse flow from the highpressure source does not exceed the maximum allowable accumulated pressure of the vessels. (3) For piping or pressure vessels not covered under 1 and 2 above, a pressure relief device may be required to protect against potential overpressure caused by reverse flow through a failed check valve. The following scenarios shall be considered: Scenario No.

Number of Check Potential Overpressure Scenario Valves in Series

1

1

Partial failure of check valve. Assume failed check valve behaves as a restriction orifice with a diameter equal to 1/3 the nominal diameter of the check valve. Use this basis for reverse flow of liquid, 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 a diameter equal to 1/3 the nominal diameter of the check valve. Each of the remaining check valves in series is assumed to behave as a restriction orifice with a diameter equal 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 second column and the bottoms from the second feeds into the third, it is possible for the loss of heat input to a column to overpressure the following column. Loss of heat results in some of the light ends remaining with the bottoms and being transferred to the next column as feed. Under this circumstance, the overhead load of the second column would consist of its normal vapor load, plus the light ends from the first column. If the second column does not have the condensing capacity for the additional vapor load, excessive pressure could occur. 7.14 Liquid Overfill Refer ANNEXURE- 5, Section-18.5.11 (Examples for Calculation of Relief). 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 plant upset. 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 failing open) while liquid outflows continue at the nominal turndown rates (typically, 50% of design). For this case, the possible overfill may be limited by the upstream vessel’s inventory. In determining the required relief capacity of the pressure relief device, credit may be taken for flow 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 on a steam collection header without any intervening control valves, a failure of the level control valve in the full open position will eventually cause the drum to overfill, but credit may be taken 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 rate without exceeding the drum MAWP, then the pressure relief device should be sized for the difference 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 control valve between the steam drum and the steam collection header, the capacity credit that may be taken will depend on the response of the control valve to the upset and its capacity under these conditions. 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 twophase flow, the pressure relief device must be designed to relieve the vapor plus liquid, minus the flow available through remaining normally open outlets, unless a dedicated pressure relief device 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 by liquid overfill by the use of a pressure relief device may not be practical, and/or may be insufficient to ensure the integrity of the equipment. For example, an existing disposal system may lack the capacity to absorb the relief load, or the vessel support structure may not be capable of supporting the weight of a liquid filled vessel without risk of structural failure. In such cases, the use of a High Integrity Protective System (HIPS) on all incoming feeds, including start up oil, to protect against liquid overfill may be considered as an alternative (or in addition) to a pressure relief device. The dynamics of the HIPS must be evaluated to ensure that the set pressure of the pressure relief device will not be exceeded and that surge pressures associated with the rapid closure of the isolation valves are considered in the design of upstream and downstream piping systems. The use of a HIPS to eliminate the liquid overfill contingency does not eliminate the need for a

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pressure relief device to protect the vessel against other potential overpressure contingencies such as fire, utility failure or operating failure. In addition, the possibility of leakage across the HIPS isolation valves must be considered in determining the required relief capacity of the pressure relief device protecting the vessel. To account for possible isolation valve leakage, the pressure relief device should have sufficient capacity to handle at least 10% of the relief load that would arise from liquid overfill without exceeding the allowable accumulation. For exceptional cases where the structural supports for a vessel are not designed for the weight of the vessel full of liquid and leakage cannot be tolerated, the use of double isolation valves with an intervening bleeder discharging to the flare (all actuated by the HIPS) should be considered. The provision of a safety critical LHA as described in the preceding paragraphs is not necessary if either of the following conditions is met: The pressure relief valve protecting the vessel from other contingencies has sufficient capacity to handle the liquid overfill contingency without exceeding the Code allowable accumulation AND the pressure relief valve discharges to a closed system, OR There is no credible scenario that could lead to liquid overfill. For example, the maximum pressure that can be developed by the feed system is lower than the set pressure of the pressure relief valve protecting the vessel (plus static head, if applicable). When liquid overfill is a credible overpressure scenario, the design pressure of all the equipment affected by the overfill condition shall be set sufficiently high to account for any liquid static head attributable to the overfill condition. As an example, consider a reboiled distillation column that is protected against overpressure due to liquid overfill by a pressure relief device located at the top of the column. In this case, the design pressure of the reboiler should be at least equal to the set pressure of the pressure relief device plus any liquid static head developed between the pressure relief device inlet and the top of the reboiler as a result of the overfill scenario. Another example involves an overhead receiver associated with a distillation column. Consider a hypothetical scenario in which the receiver is overfilled due to loss of the product and/or reflux pumps. If the pressure relief device protecting the receiver is located on the tower overhead, the level in the overhead system will continue to rise up to the condenser inlet. At this point the level will not increase further since there will no further condensation. Instead the lack of a disposal route for the overhead vapor will cause the tower pressure relief valves to open. Therefore, as a minimum the tower pressure relief valves must be designed for the full overhead flow rate. In addition, the design pressure of the overhead receiver must take into account the maximum fill level that will be reached during the contingency. For this example, the drum design pressure should be at least as high as the set pressure of the pressure relief valve(s) protecting the tower plus the liquid static head between the top of the drum and the top of the flooded condenser.

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8.0 SIZING FOR PRESSURE RELIEF VALVE 8.1 Sizing for Vapor or gas relief Critical flow pressure (PCF): Critical flow rate is that corresponding to the limiting velocity, the velocity of sound in the flowing fluid at that location. The critical flow pressure (PCF) in absolute unit is calculated by following formula,

⎛ 2 ⎞ PCF = PR ⎜ ⎟ k 1 + ⎝ ⎠

⎛ k ⎞ ⎜ ⎟ ⎝ k −1 ⎠

.………………………………(Eq.21)

Where, PCF : Critical flow nozzle pressure, in psia PR : Upstream relieving pressure, in psia k : Specific heat ratio, Cp/Cv 8.1.1 Sizing for critical flow: If PSV back pressure

PCF ; flow is Critical ,

The orifice area is calculated by the formula,

A= A W C

Kd PR Kb

Kc

T Z M

W C × K d × PR × K b × K c

T×Z M

Where, : Required effective discharge area : Required relieving rate : Coefficient due to k (= Cp/Cv) of the gas or vapor at relieving conditions. This can be obtained from Annexure-1, Figure-32 or Annexure-1, Table-8. Where k cannot be determined, it is suggested that a value of C equal to 315 be used. : Effective coefficient of discharge = 0.975, when PSV is installed with or without Rupture disk : Relieving pressure (= ser press. + over press. + atm. Press.) : Capacity correction factor due to back pressure. (Refer Annexure-1, figure-30) The back pressure correction factor applies to balanced bellows valves only. For conventional and pilot operated valves use a value for Kb = 1. : Combination correction factor, = 1.0 when rupture disk is not installed = 0.9 when rupture disk is installed in combination with PSV : Relieving temperature : Compressibility factor at relieving conditions : Mol. Wt of vapor or gas at relieving conditions

.…..(Eq.22)

in2 lb/hr

lbm

lbmole × R lb f × hr

psia -

-

°R (= °F + 460) lb/lbmole

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Sizing for sub-critical flow: If PSV back pressure

PCF ; flow is Sub-Critical ,

The orifice area (for conventional and pilot operated valves) is calculated by the formula,

A=

W 735 × F2 × K d × K c

Z ×T M × PR (PR − PB ) ……(Eq.23)

For balanced pressure relief valves equation for critical flow should be used. Where, : Required effective discharge area in2 A lb/hr W : Required relieving rate F2 : Coefficient of sub-critical flow. Refer Annexure-01, figure-34 or use the following equation,

F2 =

Kd

:

Kc

:

Z T M PR

: : : :

PB

:

r

⎛2⎞ ⎜ ⎟ ⎝k ⎠

⎛ k −1 ⎞ ⎛ ⎜ ⎟ ⎝ k ⎠ ⎜ ⎛ k ⎞ 1− r ⎜ ⎟⎜ − k 1 ⎝ ⎠⎜ 1 − r ⎝

⎞ ⎟ ⎟ ⎟ ⎠

Where, k = sp. Heat ratio, Cp/Cv r = ratio of back press. to relieving pressure; PB/PR Effective coefficient of discharge = 0.975, when PSV is installed with or without Rupture disk Combination correction factor, = 1.0 when rupture disk is not installed = 0.9 when rupture disk is installed in combination with PSV Compressibility factor at relieving conditions Relieving temperature Mol. Wt of vapor or gas at relieving conditions Relieving pressure (= ser press. + over press. + Atm. Press.) Back pressure

-

°R=(°F+460) lb/lbmole psia psia

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Sizing for Steam Relief Pressure relief devices in steam service that operate at critical flow conditions may be sized using equation,

A= Where, A W PR Kd

: : : :

Kb

:

Kc

:

KN

:

W 51 .5 × PR × K d × K b × K c × K N × K SH

Required effective discharge area Required relieving rate Relieving pressure (= ser press. + over press. + atm. Press.) Effective coefficient of discharge = 0.975, when PSV is installed with or without Rupture disk Capacity correction factor due to backpressure. (Refer Annexure1, figure-30) The backpressure correction factor applies to balanced bellows valves only. For conventional and pilot operated valves use a value for Kb = 1.0. Combination correction factor, = 1.0 when rupture disk is not installed = 0.9 when rupture disk is installed in combination with PSV Correction factor for Napier Equation, = 1 where PR =

KSH

:

……(Eq.24) in2 lb/hr psia -

-

-

1500 psia

0.1906 x PR - 1000 0.2292 x PR - 1061

where PR 1500 psia and 3200 psia

Superheat steam correction factor (Refer Annexure-1, Table-9). For saturated steam at any pressure KSH = 1

In accordance with the requirements of the ASME Boiler & Pressure vessel code, section I Power Boiler, accumulated pressure shall be limited to 106% of the MAWP, and the relieving capacity of 110% of calculated value is required. 8.3 Sizing for Liquid Relief Valves in the liquid service that are designed in accordance with ASME code which require a capacity certification may be sized using the equation,

A=

V 38 × K d × K w × K c × K v

G PR − PB

….(Eq.25)

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Where, : A : V Kd : Kw

:

Kc

:

Kv

:

LTC-PB-P0-004 Page 38 of 116

Required effective discharge area Volumetric Flow rate Rated co-efficient of discharge = 0.65, when PSV is installed with or without Rupture disk in combination Correction factor due to backpressure. If the backpressure is atmospheric, use a value for Kw of 1.0. The backpressure correction factor applies to balanced bellow valves only (Refer Annexure-1, figure-31). Conventional and pilot operated valves require no special correction. Combination correction factor, = 1.0 when rupture disk is not installed = 0.9 when rupture disk is installed in combination with PSV Correction factor due to viscosity as determined from Annexure1, Figure-36 or from the following equation,

⎛ 2.878 342 .75 ⎞ ⎟ ⎜ K V = ⎜ 0.9935 + + 0 .5 1 .5 ⎟ (N Re ) (N Re ) ⎠ ⎝ G

:

PR PB

: :

in2 U.S. gpm -

-

-

−1

Where NRe = Reynold’s number. Refer equation mentioned below to determine the value of NRe. Specific gravity of the liquid at the flowing temperature referred to water at standard conditions Relieving pressure (= ser press. + over press.) psig Back pressure psig

When a relief valve is sized for viscous liquid service, it should first be sized as if it were for a nonviscous type application (i.e. Kv = 1.0) so that a preliminary required discharge area, A, can be obtained. From API STD 526 standard orifice sizes, the next orifice size larger than A should be used in determining the Reynold’s number (NRe), from following equation,

N Where, : R : Q : G

µ A

: :

Re

=

V × 2800 × G

µ

A

.………………………….(Eq.26)

Reynold’s Number Flow rate at flowing temperature U.S. gpm Specific gravity of the liquid at the flowing temperature referred to water at standard conditions Absolute viscosity at flowing temperature cP Effective discharge area in2

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After the Reynold’s number (NRe), is determined, the factor Kv is obtained and correct the preliminary required discharge area. If the corrected area exceeds the chosen standard orifice area, the above calculation should be repeated using the next larger standard orifice size. 9.0 DESIGN OF PIPING UPSTREAM OF RELIEF DEVICE Piping upstream of a relief device should be designed with as few restrictions to flow as possible and should not be pocketed. The flow area through all pipe and fittings between a pressure vessel and its relief valve shall be at least the same as that of the valve inlet (e.g. isolation valves shall be full bore). Depending on the actual relief valve capacity, the pressure drop of the inlet piping and fittings shall not exceed 3% of the valve set pressure (this is to avoid chatter, which will result in significant seat damage and loss of capacity). Exceptions to this requirement are only allowed in the case of a pilot-operated valve with a suitably arranged remote pilot connection close to the source of overpressure. Refer Figure-4 & 5. The above is especially applicable to relief valves handling gas or vapor. Relief valves in pure liquid service require special attention, since in this case chatter may also be caused by the acceleration of the (non expandable) liquid in the inlet piping: a change in pressure amounting to more than 3% of the set pressure will readily occur and cause valve chatter. In this case the likelihood of chatter can be limited by installing a relief valve with a special liquid trim (linear flow characteristic) thereby avoiding the need to take the relief valve capacity to determine the pressure drop of the inlet piping. When two or more relief valves (spares not counted) are fitted on one connection, the crosssectional area of this connection shall be at least equal to the combined inlet areas of the valves, and the above pressure drop requirement shall apply for the combined flow of the valves. Relief valves on cold process streams shall have an uninsulated inlet line of sufficient length to prevent icing of the relief valve, in particular the disk and spring. Alternatively, heat tracing may be required. Special attention shall be paid in this respect to valves, which discharge into the atmosphere, i.e. in those having open outlets, which may become blocked with ice. To avoid the need for special high temperature materials, relief valves on hot process streams may be installed using an uninsulated length of inlet line, creating a cold dead ended leg between the process stream and the relief valve. However, consideration should be given to vapor condensation, deposit formation and solidification, which would affect operation of the relief valve.

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Figure-4&5

10.0 DETERMINATION OF FLARE DESIGN CAPACITY The first requirement in the design of a flare system is a detailed analysis of all possible situations involving fluids discharged from pressure relief or emergency depressurizing devices, or both to determine the maximum load condition. This section presents guidelines on the method of calculations for maximum flare load for design of a flare system. STEP-1 Identify all the equipments (pressure vessels, heat exchangers, compressors etc.) and lines that needs to be protected against overpressure and whose safety valve discharge is connected to flare header. STEP-2 Make a listing of all the safety valves with Tag nos. and service that are required to protect equipments and lines identified in STEP-1 STEP-3 Study all the process systems and piece of equipments individually and make separate evaluations for each relief valve for all applicable contingencies. The contingencies as mentioned in section 6.2 should be considered while calculating the relieving capacities of safety valves. STEP-4 Check for Vapor depressurizing source from the P&ID’s. Vapor depressurizing systems are auxiliary facilities that provide means for rapidly reducing the pressure in equipment by release of vapors. Depressurizing streams are frequently introduced into the same

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headers servicing pressure relief valves. If a common flare header is used, the loads caused by depressurizing must be added to the loads of various pressure relief valves, which might be expected to discharge simultaneously. STEP-5 Prepare a “Flare Load Summary table“ for the purpose of process system analysis. Typical Flare Load Summary table is enclosed in Annexure -6. Flare Load summary should include all the safety valves in the plant connected to a common flare header and all the possible causes of over pressurization with corresponding relieving rates, phase, molecular weight, temperature, pressure etc. STEP-6 The contingency, which contributes to the maximum flare load, should be considered for the flare system design. This requires careful consideration of potential occurrences that could affect several vessels or systems and cause them to relieve simultaneously. The maximum load is not necessarily the largest mass flow rate at any time but rather it is the flow that will impose the highest-pressure drop in the system. Thus, the temperature and molecular weight of the vapors must be known. Since, the simultaneous occurrence of two or more unrelated contingencies is unlikely, unrelated contingencies should not be used as a basis for determining the maximum system load (e.g. it is extremely remote to have a power failure and fire at the same time). Hence, the basis for maximum load should be either of following items: 1. Individual failure (Single contingency contributing the maximum load) 2. Emergency depressurization 3. Group failure (from any of below mentioned contingencies contributing to the maximum cumulative load) 1) Fire Envelope Potential fire areas shall be identified and clearly shown on a plot plan. The fire areas / envelopes shall be numbered and each number shall be used for calculating PSV outlet / Flare header sizing. Typical fire area (fire zone) of 2500 – 5000 ft2 should be assumed, depending on the drainage of the plot. The height of the flame to be considered shall be 25 ft (7.62 m) from grade or a platform on which liquid can accumulate (concrete platform). 2) Cooling water failure 3) General Power failure (Total or Partial) NOTE (for Group failure cases): a. General recommendation from member to author the API safety valve standard: To size the lateral piping from the relief valve to main flare header for the relief valve rated capacity, and then size the flare header based upon evaluation of the expected simultaneous loads from the sources connected to the header. These loads are the calculated relief loads from the equipment, not the valve capacities. b. Estimate the properties of gases in the headers from the following mixture relationships (i indicates the ith component).

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PROCEDURE FOR PRESSURE SAFETY VALVE CALCULATIONS AND FLARE SYSTEM DESIGN

∑W ⎛W ⎞ ∑ ⎜⎝ M ⎟⎠

Page 42 of 116

i

M =

T =

LTC-PB-P0-004

.……………………………………….…….(Eq.27) i

∑ (W × T ) ∑W

i

.…………………………………………(Eq.28)

i

µ =

∑ (X µ ∑ (X i

i

Where, Wi Ti Xi µi Mi

i

Mi Mi

)

) .………….……………….…(Eq.29)

- Weight of component i in total stream - Temperature of component i in total stream - Weight fraction of component i in total stream - Viscosity of component i in total stream - Molecular weight of component I in total stream

11.0 SIZING OF FLARE HEADER

Individual discharge from PSV to sub-header

Sub-headers in each section of the plant to Main Flare Header

Main flare header leading to KOD

KOD to Flare stack

The major criteria governing the sizing of headers are backpressure and gas velocity. Flare header size large enough to prevent excessive backpressure on the plant safety valves and to limit gas velocity and noise to acceptable levels. The procedure for sizing of flare header is outlined below:

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a. Start at the flare tip, where outlet pressure is atmospheric and estimate the pressure drop across the flare tip for the relief design flow. Typical tip drop is 2.0 psi as per API-521 (This may be checked with manufacturer data). Pressure drop through seals must also be included. b. In certain cases, B/L pressures are provided in the ITB documents (design basis). Hence, the start point would be at the B/L. c. Determine the appropriate relief contingencies (Section 10, Step 6) yielding maximum loads d. Calculate the relevant fluid properties in case of Group failure contingencies. e. Assume a measured size for flare header / sub header / PSV outlet line. f. Estimate the equivalent pipe lengths between Flare tip Or B/L position and different sections in the system for the above identified governing cases (Section 10, Step 6) and estimate losses through fitting, expansion and contraction losses. g. Limit the Mach no. of 0.2 (as per API-521) at the flare header. h. Calculate the inlet pressure for each section of the line by adding the calculated pressure drop for that section to the known outlet pressure. i. Continue calculations, working towards the relief valve. j. Check calculated backpressure at the relief valve against the maximum allowable backpressure (MABP). The calculated backpressure should be less than the MABP. k. Limit the MABP to about 10% of the set pressure for conventional relief valves and 40% of the set pressure for balanced -bellows relief valves (This may be checked with manufacturer data) l. The design shall also ensure that if two or more depressuring valves in any process system are opened simultaneously, flow from the high-pressure system will not back up into the low-pressure system sufficiently to overpressure it or hinder its operation. m. Adjust header size until the calculated backpressure does not exceed the MABP for each valve in the system (for the above identified Governing cases). In-house developed MS-EXCEL based program (Flare.xls) for the above header sizing procedure can be used for calculations. Refer Annexure-7 for typical flare header design calculations / PSV outlet line sizing.

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Specific Criteria for sizing the flare header (Based on experience(s) in domestic projects) Pressure at the B/L of the individual plant: 1.5-kg/cm2 g Back pressure allowable at the PSV discharge: 1.7-kg/cm2 g

12.0 DESIGN OF PIPING DOWNSTREAM OF RELIEF DEVICE The discharge piping installation must provide for proper pressure relief device performance and adequate drainage. Consideration should be given to the type of discharge system used, the backpressure on the pressure relief device, and the set-pressure relationship of the pressure relief devices in the system. Auto-refrigeration during discharge can cool the outlet of the pressure relief device and the discharge piping to the point that brittle fracture can occur. Materials must be selected which are compatible with the expected temperature. Once the maximum design load on each header, sub-header, and lateral has been ascertained it is possible to size the downstream piping system. By starting from the tip of the flare or vent stack where the pressure is atmospheric or critical, and adding each calculated pressure drop, the built-up back pressure downstream of each relief or depressuring device can be determined. Adjustments in the assumed line sizes may then be made in order to ensure that the operation of the relief or depressuring device is not hindered. If the required piping becomes excessively large, particularly in systems where low backpressures are allowed, it may be preferable to replace non-balanced spring-loaded relief valves with balanced bellows types, thus increasing the maximum allowablepressure and so meeting the following relief valve selection criteria: i) Variable back pressure <

10% of set pressure; use non balanced spring loaded relief valves;

ii) Variable back pressure <

21% of set pressure for fire cases and applying equipment following ASME VIII; use non balanced spring loaded relief valves;

iii) Variable back pressure <

50% of set pressure; use balanced-bellows springloaded relief valves;

iv) Variable backpressure = 10/13 x ( Design Pressure of High Pressure side) 3.5 >= 10/13 x 7 3.5 >= 5.385 Condition is not satisfying , so we have to follow tube repture case C/s area of tube (A) =

Relieving Rtae

Π Di /4 = A = 2

(W)

= = =

2

769.45 mm 2 0.000769 m

2 x 0.7 x A x (2(P1-Pset) x 11.33374 Kg/s 40801.45 Kg/hr

ρ)0.5

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P set=10.4 barg W = m-m 1

m1

m P1 T1

P2

ρL

Data Input Data Flow rate @ normal operating condition

Symbol mn

Value 10441.2

Unit Kg/hr

Control valve upstream pressure

P1

26.6

barA

2 27.12402 Kg/cm A

Control valve down stream pressure

P2

6.2

barA

2 6.32214 Kg/cm A

Upstream fluid Temperature

T1

40

Upstream fluid density

ρL

18.374

Kg/m3

P set a Pr

10.40

barg

Tr M

62

Design Pressure / Set Pressure Accumulation Relieving Pressure Relieving Temperature MW of Vapor / Gas

0

C

10

%

12.45

barA 0

313

K

C

Kg/kmol

18.40

Relief load (W) Calculation Control Valve Pressure drop =

20.4 bar

Calculation for Cv P2