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

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

L&T- CHIYODA LIMITED Date: Feb.15, 2007 Rev: 1

PROCEDURE FOR PRESSURE SAFETY VALVE CALCULATIONS AND FLARE SYSTEM DESIGN


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





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





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





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.





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.



•



•

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.



4.1



Types of Pressure Relief Valves

4.1.1 Conventional pressure relief valve It is a spring loaded pressure relief valve whose operational characteristics are directly affected by changes in the backpressure. (Refer Annexure-1, Figure-2) The operation of a conventional spring loaded pressure relief valve is based on a force balance (Refer Annexure-1, Figure-19). The spring load is preset to equal the force exerted on 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





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





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.





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





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




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


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.





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).





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.





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.





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"





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





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





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





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



condensing

3

Fan Failure (AFC failure)

4

Louver closure

5

Top-tower reflux failure Pump around circuit

6



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.





(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)



Y =


r

⎛ 2 ⎞ ⎜⎜ ⎟ ⎝ k ⎠

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

⎞ ⎟ ⎟ ⎟⎟ ⎠


………………...…(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.



7.5



Control Valve failure

Refer ANNEXURE- 5, Section-18.5.5 (Examples for Calculation of Relief). Automatic control devices are generally actuated directly from the process or indirectly from a process variable (cascaded), e.g., pressure, flow, liquid level, or temperature. When the transmission signal or operating medium fails, the control device will assume either a fully open or fully closed position according to its basic design (the fail-safe position), although some devices can be designed to remain stationary in the last controlled position. When examining a process system for overpressure potential, it shall be assumed that any one automatic control valve could be either open or closed, regardless of its specified fail-safe action under loss of its transmission signal or operating medium. When the control valve size (flow coefficient, Cv) is known it shall be assumed that this 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





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)




4.


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



7.6



Hydraulic / Thermal Expansion

Refer ANNEXURE- 5, Section-18.5.6 (Examples for Calculation of Relief). Thermal expansion is the increase in liquid volume caused by an increase in temperature. 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





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.





(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).





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





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





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





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.





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




8.1.2


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




8.2


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)




Where, : A : V Kd : Kw

:

Kc

:

Kv

:


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





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.





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





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).




∑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:





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.





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 <=

70% of set pressure; use pilot-operated relief valves

Velocities in sub headers / PSV outlet lines may be higher, up to Mach no. 0.7. The provision of small branches and instrument connections on flare relief systems shall be avoided, because they are vulnerable to acoustically induced vibration.





13.0 FLARE STACK SIZING The sizing of a flare stack requires the determination of flare stack diameter and flare stack height.

13.1 Flare Stack Diameter Flare stack diameter is generally sized on a velocity basis, although pressure drop should be checked. It may be desirable to permit a velocity of unto 0.5 Mach for a peak, shortterm, infrequent flow, with 0.2 Mach maintained for the more normal and frequent conditions. The formula relating Mach No. to flare tip diameter is as follows :

Mach ..no . = Where

W k M P d

-

11 .61 × W 100 × P × d 2

T k×M

.………………………(Eq.30)

Flow rate of gas, kg/s Cp./Cv Molecular weight of gas Flowing pressure at the flare tip in kg/cm2a Flare tip diameter, metre

13.2 Flare Stack Height Flare stack height is generally based on radiant heat intensity generated by the flame. (a) Thermal radiation calculations must be done to avoid dangerous exposure to personnel, equipment and the surrounding area (tree, grass). The following formula is used for finding the intensity of radiation.

K = Where

K

ε

Qr R

εQ r 4π R 2

.…………………………………………….(Eq.31)

- Intensity of radiation, kW/m2 - Emmisivity - Heat release due to combustion, kW - Distance from the midpoint of the flame to the object being considered, Metre

A list of vendor recommended emissivity values for the most frequently flared gases is as follows: Carbon Monoxide 0.075 Hydrogen 0.075 Hydrogen Sulfide 0.07 Ammonia 0.07





Methane 0.1 Propane 0.11 Butane 0.12 Ethylene 0.12 Propylene 0.13 The maximum value of emmisivity of any gas is 0.13 (as per GPSA) The radiation levels commonly used for designs are: Personnel, short time exposure: 1500 Btu/hr-ft2 (or) 4.732 kW/m2 Personnel, continuous exposure: 500 Btu/hr-ft2 (or) 1.58 kW/m2 Solar radiation adds to the calculated flame radiation and is dependent upon specific atmospheric conditions and site locations. A typical design range is 250 to 330 Btu/hr-ft2 (0.79-1.04 kW/m2). (b) To calculate the intensity of radiation at different locations, it is necessary to determine the length of the flame and its angle in relation to the stack (Refer Annexure-8, Figure-A). A convenient expression to estimate length of flame Lf is shown below:

(

L f = 1 . 201 Q r × 10

−6

)

0 . 474

.……………….(Eq.32)

Where Qr Lf

- Heat release due to combustion kW - Length of flame in metre

The center of the flame is assumed to be located at a distance equal to 1/3 the length of the flame from the tip. The angle of the flame results from the vectorial addition of the velocity of the wind and the gas exit velocity.

θ = tan

−1

VW .……………………………………………….…(Eq.33) V ex

Where Vw - Wind velocity m/s Vex - Exit gas velocity m/s The co-ordinates of the flame center with respect to the tip are:

XC =

Lf 3

sin θ

&

YC =

Lf 3

cos θ

.…..…….(Eq.34)

The distance from any point on the ground level to the center of the flame is:

R=

( X − XC )2 + (HS + YC )2 .………………………….……(Eq.35)

At the stack base i.e. X = Xc





R 2 = (H S + YC ) .……………………………………………..(Eq.36) R = H S + YC …………………………………………………..…(Eq.37) 2

Where X Hs

- Sterile radius, metre - Height of the stack, metre

Flare stack height can be estimated based on the above equations. 14.0 DESIGN OF FLARE KNOCKOUT DRUM A knockout drum is usually provided near the flare base, and serves to recover liquid hydrocarbons, prevent liquid slugs, and remove large (300 - 600 micron) liquid particles. All flare lines should be sloped toward the knockout drum to permit the liquid to drain into the drum for removal. The design procedure is given below: Calculate the dropout velocity of a particle in a stream by using the following equations.

U d = 1 . 15

g × d p × (ρ L − ρ V

ρV × C

)

…………………..……(Eq.38)

Where Ud g dp

ρL ρv

C

-

Dropout velocity, m/s Acceleration due to gravity, 9.8 m/s2 Particle diameter, metre Density of liquid at operating conditions, kg/m3 Density of the vapor at operating conditions, kg/m3 Drag coefficient (Refer Annexure-8, Figure-B)

The economics of vessel design should be considered in selecting a drum size and may influence the choice between a horizontal and vertical drum. When large liquid is expected and vapour flow is high, a horizontal drum is often more economical. 14.1 Horizontal Knockout Drum STEP-1 A horizontal vessel with an inside diameter D, and a cylindrical length L should be assumed. This gives the following total cross-sectional area “At”.

At =

πD 4

2

………………………………………….………(Eq.39)

STEP-2 Based on the liquid hold up “t” min., calculate the cross sectional area of the liquid segment “AL”.

AL =

QL × t ………………………………………………(Eq.40) L

Where





- Liquid rate, in m3/min

QL

STEP-3 Calculate the cross sectional area remaining for the vapor flow by

AV = A t − A L ……………………………………………(Eq.41) STEP-4 Calculate the total diameter using the following equation.

D = h L + hV

(Refer Annexure-9, Figure-C)……….(Eq.42)

Where hL hV

- Depth of all liquid accumulation, in metre. - Vertical space for the vapor flow, in metre.

STEP-5 Calculate the liquid drop out time, in seconds

hV U d

θ =

…………………………………………………………….…(Eq.43)

STEP-6 Calculate the velocity of the vapor, in m/s

U

V

=

QV AV

……………………………………………………………(Eq.44)

QV

- Volumetric flow rate of vapor, in m3/s

Where STEP-7 Calculate the drum length, in metre

L min = U

L = L min

× θ ……………………………….…………(Eq.45) + N 1 + N 2 + 0 . 3 ……………………(Eq.46)

V

Where N1 N2

- Feed (inlet) nozzle diameter, in metre - Vapor outlet nozzle diameter, in metre

STEP-8 “L” must be less than or equal to the above assumed cylindrical length; otherwise, the calculation must be repeated with a newly assumed cylindrical length. 14.2 Vertical Knockout Drum STEP-1 If vertical vessel is considered, the vapor velocity is equal to the dropout velocity and the drum diameter is determined as follows:

At =

QV U d

………………………………………………………..……(Eq.47)




At × 4

D =


………………………………………………….…(Eq.48)

π

STEP-2 Based on the liquid hold up “t” min., calculate the height of the liquid segment hl, in metre.

hL =

Q

L

× t

At

……………………………………………………..…(Eq.49)

Where QL - Liquid rate, in m3/min STEP-3 Height of the drum (in metre) can be determined as follows:

H

min

= hL + N 1 + N

2

+1

…………………..…………(Eq. 50)

Where hL N1 N2

- Height of liquid segment, in metre. - Feed (inlet) nozzle diameter, in metre. - Vapor outlet nozzle diameter, in metre.

15.0 DESIGN OF SEALS IN FLARE SYSTEM To prevent air from entering into the flare system and forming explosive mixture prior to the ignition point, it is necessary to seal the flare system. Sealing of a flare system involves two aspects: (i) Sealing of the flare stack (ii) Sealing of piping headers

15.1 Sealing of the Flare Stack This is also known as gas seal. This is a vendor-designed system. An effective stack seal is one able to minimize air passage into the system while using low purge flow. As the gas seal is a vendor specific item, the process designer has to specify the type of purge gas available for the gas seal, point of injection of purge gas and quantity of purge gas.

15.2 Sealing of Piping Headers The sealing of the piping headers up to the flare stack base is generally accomplished by means of a liquid seal drum at the bottom of the flare stack. The most commonly found seal is shown in Fig-4. A vacuum seal leg is dipped into a vertical seal drum filled with water. Whenever a vacuum condition occurs the liquid level in the seal leg will rise and break the vacuum thus preventing the ingress of air. The process design of seal drum will include sizing the seal leg, depth of water seal and dimensions of seal drum.





DESIGN METHOD: The design method followed herewith is based on the recommended practice given by API RP 521. (a) Height of Seal Leg The height of seal leg is calculated by a pressure balance at the stack bottom (Ref Annexure-10, Figure-D).

X + P1 = X + Y + P2 ..…………………………………………(Eq. 51) Y = P1 − P2 ..……………………………………………………..(Eq.52) Where P1 P2 Y X

- Pressure at stack, in Metre - Min. pressure expected at header, in Metre - Height of seal/vacuum leg from top of liquid surface (Minimum of 2.0 m as per Lummus spec.) - Water seal depth (normally 2 ft or 0.6 m)

(b) Diameter of seal drum (i) Seal volume for vacuum break: Total vertical height of seal pipe

h = Y + X + d ..…………………..……………………………(Eq.53) Where d

- ID of seal pipe

Volume of pipe (V

)=

πd 2h 4

..…………………………….………(Eq.54)

A minimum of “V” m3 should be maintained for seal. Diameter of seal drum

π (D 2 − d 2 out )X 4

=V

..……………………………..……(Eq.55)

From the above equation, diameter of seal drum “D” can be calculated. To accommodate for liquid volume in horizontal pipe run up to nozzle projection and for any other factors use 20% over design. (ii) Seal volume with non vacuum conditions in flare stack :





As per API,

D = 2 × d ..………………………………………………………(Eq.56) Where D d

- Seal drum diameter - Seal pipe diameter

(c) Height of seal drum The height of the vapor space “HV” in a vertical drum should be approximately 0.51.0 times the diameter “D” to provide disengaging space for entrained seal liquid. A minimum dimension of 3 feet (1 metre) is suggested in API RP 521. Tan/Tan height of seal drum =

H V + X + 0.5 * ..………………………(Eq.57)

* Height of seal liquid below submerged inlet pipe assumed as 0.4- 0.5 m





16.0 PURGING OF FLARE HEADER AND FLARE TIP 16.1 Procedure for Calculating Flare Header Purge A large amount of purge gas is usually required after a hot release to prevent air from entering the system when the system gas inventory cools and condenses. This additional gas injection should be on automatic temperature and pressure control and the rate of gas injection may be estimated as follows: (a) Examine the process calculations of all the relief valves and isolate the relief condition which has a potential for maximum percentage of condensation (b) Calculate the maximum condensation on the basis of calculation of heat loss through the flare header and latent heat of condensation. (c) Convert condensation rate obtained in step (b) to kgmole/hr. (d) Purge gas flow (PGR1)

= 2 x Rate of condensation (kgmole/hr)

16.2 Procedure for Calculating Flare Tip Purge (a) Use purge gas velocity of 0.03 m/s for the flare tip. (b) For the flare tip diameter, calculate the volumetric flow rate of purge gas at flare tip conditions.

Purge gas rate (PGR2) =

πd 4

2

× 0 . 03 × 3600

m3/hr..……………(Eq.58)

Where d

- Flare tip diameter, in Metre

17.0 P&I DIAGRAM FOR FLARE SYSTEM The important features of P&I diagram of flare stack are as follows: (a)

Continuous Purge Gas Supply: To ensure that the flare system does not experience a vacuum condition continuous purge gas through a pressure control valve controlling the flare header pressure should be provided. An alarm for low flare header pressure and purge failure should be provided.

(b)

The flare header should drain by gravity towards the flare knock out drum. Thus the flare header should slop continuously towards the flare knockout drum and no pockets are allowed.





(c)

The flare knockout drum should be provided with pressure and temperature indications.

(d)

A seal should be maintained in the flare stack base to prevent flame backup and ingress of oxygen. There should be continuous supply of make up water to the seal. The overflow nozzles in the seal drum which discharges the condensed hydrocarbons and water should be located high enough to allow the flow to take place towards the flare knockout drum.

(e)

When flame monitoring is specified, the status of each thermocouple installed on the pilots shall be monitored by temperature trip amplifiers located in the panel enclosure.

Refer Annexure-11 (Typical flare system P&I Diagram) 18.0 ANNEXURES 18.1 Annexure-1 [Tables, Figures (as per API-520/521)] Tables Sr. No. 1 2 3 4

TABLE NO.

DESCRIPTION

Table-8 Table-9

Values of coefficient C (API-520, page-50) Superheat correction Factors, KSH (API 520, page-51)

Figures Sr. No. 1

FIGURE NO.

DESCRIPTION

FIGURE-1

2 3 4 5 6

FIGURE-2 FIGURE-3 FIGURE-6 FIGURE-19 FIGURE-22

7

FIGURE-23

8

FIGURE-30

9

FIGURE-31

10

FIGURE-32

Pressure level relationships for pressure relief valves (API-520, page-3) Conventional Pressure relief valve (API-520, page-6) Balanced-bellows pressure relief valve (API-520, page-7) Pilot operated valve (API-520, page-11) Pressure Relief Valve Operation – Vapor / Gas service Typical effects of superimposed back pressure on the opening pressure of Conventional Pressure relief valves Typical effects of superimposed back pressure on the set pressure of Balanced Pressure relief valves Backpressure correction factor Kb for balanced bellows pressure relief valve (vapors and gases) (API-520, page-37) Capacity correction factor, Kw Due to back pressure on Balanced-Bellows pressure relief valves in liquid service. (API 520, page 38) Curve for evaluating coefficient C in the flow equation from the specific heat ratio, assuming ideal gas behavior (API 520, page 44)



11 12

FIGURE-34 FIGURE-36



Values of F2 for sub critical flow (API 520, page-48) Capacity correction factor, Kv, Due to viscosity (API 520, page 54)

Table-8





Table-9





Figure-1





Figure-2





Figure-3





Figure-6, 7





Figure-19





Figure-22





Figure-23





Figure-30





Figure-31





Figure-32





Figure-34





Figure-36



18.2



Annexure-2 (Environment factor data)







18.3



Annexure-3 (Vapor pressure and Heat of vaporization of pure single component paraffin hydrocarbon liquids)



18.4



Annexure-4 (Sizing for Two-phase Liquid/Vapor Relief)
















































18.5


Annexure-5 (Examples for Calculation of Relief load) 18.5.1 External Fire Single Component System

Wetted Surface Area

Pset = 3.5 barg

3200 mm BTM EL 4100 mm

25 feet ( 7620 mm )

Data Input Data Design Pressure / Set pressure Accumulation Relieving Temperature Relieving Pressure Back Pressure Latent Heat @ relieving condition Cp / Cv @ 60 'F, ATM MW of Vapor/Gas Type of vessel Inside Dia Liquid Level for fire case Vessel Length Environmental Factor

Symbol Pset a Tr Pr Pb L k M D H X F

Value 3.50 21 154.0 4.2

Unit barg % o

C

barg

2.06

barA

502.4 1.33 18.02 Vertical 4.50 3.20 7.35 1.0

kcal / kg (-)

Kg/Kmol (-) m m m

Relief load (W) Calculation Q Formulae W = ----L Q = 37140 * F * A0.82 Wetted area (A1) = Cylindrical surface area + Bottom head area (Non skirted vessel) Cylindrical surface area = Π x D x H Bottom head area = 1.084 * D2 2

Wetted area Other Wetted Area (Piping) Total Wetted Area ( A1+A2)

A1 = A2 = A =

67.18993 6.718993 73.9

m 2 m

Total heat absorption (In-Put)

Q=

1265241

Kcal / hr

Relieving capacity

W=

2518.394

Kg / hr

m

2





Multi-component System

200 mm

25 feet ( 7620 mm )

3900 mm BTM EL 6500 mm

Data Input Data

Symbol Pset a Tr

Value

Relieving Pressure

Pr

92.0

Back Pressure

Pb L k M

7.60

barA

305 1.15 29.60 Vertical 6.50 3.70 33.91 1.0

kcal / kg (-)

Design Pressure / Set pressure Accumulation Relieving Temperature

Latent Heat @ relieving condition Cp / Cv @ 60 'F, ATM MW of Vapor/Gas Type of vessel Inside Dia Liquid Level for fire case Vessel Length (TL-TL) Environmental Factor

D H X F

76.00 21

Unit barg % o

278.0

C

barg

Kg/Kmol (-) m m m

Relief load (W) Calculation Q Formulae W = ----L Q = 37140 * F * A0.82 Wetted area (A1) = Cylindrical surface area + Bottom head area (Non skirted vessel) Cylindrical surface area = Π x D x H Bottom head area

2

= 1.084 * D

= =

Wetted area Other Wetted Area (Piping) Total Wetted Area ( A1+A2) Total heat absorption (In-Put) Relieving capacity

75.5553 m2 45.799 m2 A1 = 121.35 A2 = 12.14 A = 133.5 Q= 2054514 W= 6736.112

m2 m2 m2

Kcal / hr Kg / hr

Simulation Approach 3

QH

Simulation Outputs 1

Simulation Inputs Relieving Pressure Flow Composition Vapor wt. Fraction

2

Relieving Temperature Molecular Weight Cp/Cv Z factor Flow rate (Y) kg/hr

VF = 5%

Latent heat = QH/Y




Unwetted Surface Area ( Gas Expansion )


Pset=10.4 barg

25 feet ( 7620 mm )

Data Input Data

Symbol Pset a Pr

Design pressure / Set Pressure Accumulation Relieving Pressure

Value 150.90

Unit psig

21

%

197.3

psia

Vessel Wall Temperature

TW

1560

deg R

Normal Operating Gas Pressure

Pn

87.07

psia

Normal Operating GasTemperature

Tn M

567.27

deg R

19.60 Verticle 1.50 6.00

lb/lbmole

MW of Vapor/Gas Type of vessel Inside Dia Vessel Length (TL - TL)

D L

(-) ft ft

Relief load (W) Calculation Formula

⎛ A' (TW − Tr )1.25 ⎞ ⎟ W = 0.1406 M × Pr ⎜⎜ 1.1506 ⎟ Tr ⎝ ⎠

Gas Temperature Tr = (P1/Pn) x Tn

=

Unwetted Surface area (A')

=

Cylindrical surface area Head area Other unwetted Area (Piping) Total unwetted surface area (A')

= = = =

Relieving capacity, W

=

1285.4 oR Cylindrical surface area + Head area (Non skirted vessel) + Piping surface area Π x D x L = 28.274 ft2 2 4.878 2.168 x D = ft2 2 3.315 ft 36.468 ft2 94.326 lb / hr 42.786 Kg / hr





18.5.2 Exit Block Or Blocked Outlet Inadvertant Closing of Outlet (E.g. Control Valve )

Wv

Control Valve Close

Wv

Relief Load: Relieving rate can be determined from material balance i.e highest value from all the cases and the properties should be determined by simulation at relieving conditions.

Simulation Approach

1

Simulation Inputs Normal Operating Temperature Normal Operating Pressure Composition

2

Input Relieving Pressure

Simulation Outputs Relieving Temperature Relieving properties





18.5.3 Column Reflux Or Pump around failure

Normal operation

At relieving condition V=73283 Kg/hr

V=133945 Kg/hr

V=206825 Kg/hr

V=59815Kg/hr L= 74130 Kg/hr

V=147506 Kg/hr L=59319 Kg/hr

V=73664 Kg/hr

V=73573 Kg/hr V=73421 Kg/hr L= 60524 Kg/hr

V=29595 Kg/hr L=2025623 Kg/hr

V=146947 Kg/hr L=59878 Kg/hr V=177230 Kg/hr

L=60372 Kg/hr

Data Input Data

Symbol Pset a Pr

Value

Unit

3.50

barg

Relieving Temperature

Tr

10

Back Pressure

Pb

2.06

barA

Back Pressure Factor

Kb k Z M

1.00

(-)

1.35 0.97 24.40

(-) (-)

Design Pressure / Set Pressure Accumulation Relieving Pressure

Cp / Cv @ 60 'F, ATM Compressibility Factor @ Relieving MW of Vapor/Gas

16

%

5.07

barA 0

Multiple PRV

C

Relief load (W) Calculation Assumptions 1 Normal feed rate to column 2 Normal reboiler heat duty and vapor load to column 3 Vapor to feed stage considered same as outlet from reboiler (during normal operation) 4 Normal heat duty removal from the exchangers.

Relieving load will be the excess flow leaving the reflux drum top outlet. i.e 73283 Kg/hr. Simulation Approach 1

Simulation Inputs Relief Pressure Composition Vapor fraction

Simulation Outputs Relieving Temperature Relieving properties





Pset=3.5 barg

D.P = 3.5 barg

Process Gas Out

Process Gas In

BFW In

Data Input Data Design Pressure of High Pressure side Design Pressure of Low Pressure side Set Pressure Absolute upstream pressure based on maximum operating pressure Accumulation Relieving Pressure

Symbol

Value 7 3.5

Pset

3.50

Unit barg barg barg

P1

5.10

barA

a Pr

10

%

4.86

barA

Relieving Temperature

Tr

120

Back Pressure

Pb

2.06

Tube O.D Tube Thickness Tube I.D

Do t Di

38.10

mm

3.40

mm

Density of High Pressure Side

ρ

0

451325

Pa A

510000

Pa A

C

barA

31.30

mm

943.30

Kg/m3

Relief load (W) Calculation When design pressure of the low pressure side is equal to or greater than 10/13 the design pressure of the high pressure side no need to calculate relieving rate due to tube rupture.

(Design pressure of low pressure side) >= 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





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 <= 6.2 <= Critical Vapor Flow Cv for Critical Vapor Flow Cv =

=

0.5 x P 1 13.3

mn 56.9 x P 1 x (M/T 1)0.5 27.903

For 80% opening of the valve Cv value = 34.878 From Cv selection table (3"globe valve single seat body) Selected Cv value = 47 Cv selected = Control Valve Cv + Bypass Valve Cv ( i.e 50 % of Control Valve) = 47 + (47/2) Cv selected = 70.5 Critical flow rate through a failure opened control valve is calculated as follows m

= =

56.9 x Cv x P 1 x (M/T 1)0.5 25871.4

Kg/hr

Gas flowing through vessel outlet at normal condition

(m 1)

=

9492 Kg/hr





Cv Selection Table for Control Valve









18.5.4 Hydraulic / Thermal Expansion

Pset= 10 barg

CWR

CWS

Data Input Data

Symbol

Value

Unit

Design Condition : Pressure(Tube side)

10

barg

Pressure(Shell side)

16.7

barg

Temperature

T

48

Pressure(Tube side)

Pr

12.5

Temperature

Tr

48

Pset

10

o

C

Relieving Condition :

Set pressure Cubical Expansion Co-efficient Total Heat transfer rate Specific Gravity Specific Heat of trapped Fluid

B H G C

barg o

C barg

o C 0.0001 20094582.98 Kcal/hr 1 (-) Kcal/KgoC 1

Relief Load (W) Calculation A 3/4" X 1 " relief valve is commonly used for thermal expansion.

Relieving Rate (V) =

BxH 997 x G x C

3 = 2.015505 m /hr = 2015.505 Kg/hr





18.5.5 Air Fin Cooler / Condenser failure

Normal operation


V=133945 Kg/hr

V=133945 Kg/hr

V=59815Kg/hr L= 74130 Kg/hr

V=133945 Kg/hr

V=73573 Kg/hr

V=73573 Kg/hr V=133242Kg/hr L= 703 Kg/hr

V=73421 Kg/hr L= 60524 Kg/hr

L= 703 Kg/hr L=60372 Kg/hr

Data Input Data Design/Set Pressure Operating Pressure Accumulation

Symbol Pset a Pr

Relieving pressure

Value

Unit

3.50

barg

0.77 10

barg %

3.85

barg

Relief Load (W) Calculation Assumptions 1) Normal feed rate to column 2) Normal reboiler heat duty and vapor load to column 3) Vapor to feed stage considered same as outlet from reboiler (during normal operation) 4) Normal heat duty removal from the exchangers. From Figure. Air fin cooler inlet

= Air fin cooler outlet at failure = 133945 Kg/hr

Water cooled condensor outlet vapor flow rate Relieving Rate

= =

= 133242 Kg/hr

Condensor outlet flow rate(Vapor) - Reflux drum outlet flow rate (Vapor) 59669 Kg/hr





Calculation of fluid properties at relieving conditions The fluid properties at relieving conditions can be calculated by using simulation

2

Feed

Overhead Vapor

1

3

Bottom

Input for simulation (Stream-1) Data Symbol FF Flowrate of feed (Note-1) Composition of feed (Based on mixture of Note1) Pr Relieving pressure Vapor fraction y

Value 207518

Unit kg/hr

3.85 1

barg

Note-1 Feed =

Quantity of Vapor condensed in failed exchanger during normal operation (74130 kg/hr)

Output of simulation (Stream-2) Data Relieving temperature Molecular weight of relieving fluid Compressibility factor of relieving fluid Cp/Cv of relieving fluid

+

Symbol Tr M Z -----

Quantity of noncondensable vapors(73573 kg/hr )

Value 87.8 66.71738 0.919243 1.093393

Unit o C -------------

These output of simulation (Relieving temperature & Fluid properties) can be used as input for PSV sizing calculations





18.5.6 Cooling Water failure

Normal operation


V=133945 Kg/hr

V=133945 Kg/hr

V=59815Kg/hr L= 74130 Kg/hr

V=133945 Kg/hr

V=73573 Kg/hr

V=73573 Kg/hr V=74130 Kg/hr L= 59815 Kg/hr

V=73421 Kg/hr L= 60524 Kg/hr

L=60372 Kg/hr

Data Input Data Design/Set Pressure

Symbol Pset

Operating Pressure Accumulation

a Pr

Relieving pressure

Value

Unit

3.50

barg

0.77 10

barg %

3.85

barA

Relief Load (W) Calculation Assumptions 1) Normal feed rate to column 2) Normal reboiler heat duty and vapor load to column 3) Vapor to feed stageconsidered same as outlet from reboiler (during normal operation) 4) Normal heat duty removal from the exchangers. From Figure. Vapors at water-cooled exchanger inlet

Relief load (W)

= =

= Vapor at water-cooled exchanger outlet (cooling water failure) = 74130 Kg/hr of vapor & 59815 kg/hr of liquid

Condensor outlet flow rate(Vapor)-Reflux drum outlet flow rate (Vapor) 557 Kg/hr





18.5.7 Abnormal Heat Input from reboiler In case of more flow of heating fluid (e.g. Inadvertent opening of control valve on heating fluid inlet or outlet line), total heat flow to reboiler may increase which in turn may increase vapor flow rate from reboiler to column. This may lead to over pressure of the Column. In such a scenario, additional vapor flowrate (required relieving flowrate) can be calculated considering either of the following two approaches. This approach should be evaluated on case-to-case basis. Step 1: Calculate heat duty during abnormal heat input to reboiler based on heat exchanger geometry.

Q1 = Uc × A × LMTD Where, • Q1 = Total heat input during abnormal condition • A = Heat transfer area based on thermal rating (m2). • Uc = Clean overall Heat transfer co-efficient based on Thermal rating of reboiler (Kcal/hr.m2.°C) • LMTD = Log. Mean Temp Difference (Re-calculate LMTD considering process side outlet temperature at relieving pressure, °C)

NOTE: If heat duty calculated by Step-1 is less than “normal” heat duty of reboiler, there is no need to consider this relief scenario. No further calculations are required in such a case.

Step 2: Calculate maximum possible heating fluid flow rate based on size (selected Cv, refer Section 7.5) of control valve present on its inlet or outlet line. Calculate possible heat duty based on this flow rate as per following equation.

Q2 = (M HOT ) × (λ HOT ) Where, • Q2 • MHOT • λHOT

= Total heat input based on maximum possible flow rate of hot fluid = Vapor flow rate of hot fluid to reboiler (kg/hr) = Latent heat of hot fluid (Kcal/kg)

Step 3:





Consider the lower of the two values of heat duty (Q1 & Q2 calculated above) as governing heat duty (Q) to find out process vapor flow from reboiler.

Step 4: Calculate vapor flow rate from reboiler to column based on following equation.

M Abnormal =

Q

λ Abnormal

Where, • M Abnormal = Vapor flow rate of process fluid to column during abnormal condition (kg/hr) • λ Abnormal = Latent heat of process fluid (Kcal/kg) Step 5: Calculate required relieving flow rate based on following equation.

W = M Abnormal − M Normal Where, • W = Required relieving rate (kg/hr) • M Normal = Vapor flow rate of process fluid to column during normal operation (kg/hr)





18.5.8 Check valve mal-operation

P1=70.25 Kg/cm2A 1st

2nd

2nd

2nd

Absorber

P4= 19.765 Kg/cm2A

Standby

Data Input Data Downstream pressure of first NRV

Symbol P1

Value 70.25

Unit kg/cm2 A o

Downstream temperature Properties at above mentioned conditions : Molecular weight Cp/Cv Compressibility factor Intermediate pressure (Note-1)

T1

40

M K Z P2

19.47 1.21 0.887 60

Pipe bore

Di

657

(-) (-) (-) kg/cm2 A mm

Symbol P2

Value 60

Unit kg/cm2 A

Downstream temperature Molecular weight Cp/Cv Compressibility factor Intermediate pressure (Note-1)

T2 M K Z P3

35.87 19.47 1.215 0.895 35

Pipe bore

Di

431.8

C (-) (-) (-) kg/cm2 A mm

Symbol P3

Value 35

Unit kg/cm2 A

Downstream temperature Molecular weight Cp/Cv Compressibility factor Relieving pressure

T3 M K Z P4

24.88 19.47 1.239 0.926 19.765

Pipe bore

Di

431.8

Data Intermediate pressure (Note-1) Properties at above mentioned conditions (P2 & T2):

Data Intermediate pressure (Note-1) Properties at above mentioned conditions (P3 & T3):

C

(Note-2) o

(Note-2) o

C (-) (-) (-) kg/cm2 A mm

Note: 1) Downstream pressures are intermediate pressures and are obtained by satisfying the criticality condition [NON-CRITICAL => (P2>Pc)]. 2) The properties such as T2, T3, K, Z at the intermediate pressures can be calculated by using simulation.

Relief Load (W) Calculation Density =

M * P1 * 11.7946 ---------------------------(273.15+T1) * Z

Mass flow Volumetric Flow = ---------------------Density




Page 99 of 116

K ------K -- 1

2 ---------K+1

Critical pressure =

LTC-PB-P0-004

*

P1

If P2 >Critical pressure then flow is "Noncritical" otherwise "Critical"

Factor C = 2.8 *

2 K * --------K+1

K+1 -------K-1

Mass Flow -----------------------------------------Bore =

M ---------------------Z * ( 273 + T 1)

C * P1 *

0.25

2 -------K-1

d' / d =

2 K+1 -------------------K+1 K-1 ----------------------------------------------------------P2 --------P1

Bore Final =

d' / d

2 ----K

---

P2 --------P1

K+1 ------K

X Bore

Find the mass flow rate at final bore value equal to bore actual value Bore Actual = 33% of Di For First check valve Bore Actual =

10% of Di

For remaining each check valve


L&T- CHIYODA LIMITED Date: Feb 15, 2007 Rev: 0



Annexure-6 (Typical Flare Load Summary sheet) Failed check valve behaves as a restriction orifice.As per section 7.12 orifice 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. *RESTRICTION ORIFICE CALCULATION by INST HAND BOOK (E.SATO) BORE,mm FLOW,kg/hr

MW Cp/Cv Z P1,kg/cm2A

657 63664.68282 73291.55456 1096.040106 19.47 1.21 0.887 70.2584

Full=28" 6C3AS Nm3/hr m3/hr 1.21 68.901 barA

T1,?C

40

DENS

58.08608873

kg/m

Pc FACTOR,C

39.52291234 1.821304411

kg/cm A

3

2

CRITICAL(P2
mm

NONCRITICAL 2 P2,kg/cm A

OK NONCRITICAL

d'/d BORE,mm

60 0.036715796 0.020816252 1.15242481 49.9573063

BORE,mm FLOW,kg/hr

MW Cp/Cv Z 2 P2,kg/cm A

431.8 54077.16714 62254.2903 1085.481414 19.47 1.215 0.895 60

Full=20" 9C3AS

1.215 58.8408 barA

T2,?C

35.87

DENS

49.81860257

kg/m

Pc FACTOR,C

33.69438902 1.823998064

kg/cm A

3

3

DENS 29.12372954 kg/m

2

CRITICAL(P3
APPLICABLE

218.781 BORE x 33.33%

NONCRITICAL 2 P3,kg/cm A

d'/d BORE,mm

431.8 BORE,mm Full=20" 9C3AS FLOW,kg/hr 31832.34141 36645.77728 1093.003606 19.47 MW 1.239 Cp/Cv 1.239 0.926 Z 2 P3,kg/cm A 35 34.3238 barA T3,?C 24.88

43.15489583

mm

35 0.037546103 0.037461013 1.000567377 43.17938092

OK NONCRITICAL

APPLICABLE

2

Pc 19.49495324 kg/cm A FACTOR,C 1.83679161 CRITICAL(P3
19.765 OK NONCRITICAL 0.04150499 0.041493352 d'/d 1.000070113 BORE,mm 43.17944239 APPLICABLE

43.18 BORE x 10%

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

L&T- CHIYODA PERSONNEL ONLY

43.18

BORE x 10%




18.5.9 Liquid Overfill

Knock-out Drum LT

LT

LT

D ata Input D ata F low rate to KO D at rated condition F luid density Vessel Inside D iam eter T L-T L length Length above H LL H igh Liquid Level

Sym bo l

ρL

Valu e 71852.4 988

Kg/m 3

3.5 8

m m

4.8

m m

Di L LH H LL

3.2

U nit Kg/hr

Liquid O verfill scenario is not considered when below conditions are satisfying. 1 R esidance tim e for vapour space >= 30 m inute 2 Vessel has safety critical, independent high level alarm C hecking for above scenario Volum e of vapor space = = Flow rate (m 3/h)

=

Π /4 x D i x L H + Π /24 x D i 2

51.79374 m

3

3

3

72.7251 m /hr

R esidance tim e in vessel vapor space

=

Volum e of vapor space 3

Flow rate (m /hr)

R esidance tim e in vessel vapor space 42.73111

= =

0.712185 hrs 42.73111 m inutes

>= >=

30 m inutes 30 m inutes

Liquid overfill scenario need not to considered LT (2 out of 3) can be considered for safety critical,Independent high alarm level

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

L&T- CHIYODA PERSONNEL

L&T- CHIYODA LIMITED Date: Feb 15, 2007 Rev: 0 18.5.10



Alternate approach for PSV relief load calculations (Reduced reboiler duty method) This method describes the relief load calculation for the following scenarios: • Loss of condenser • Loss of reflux • Loss of feed • Loss of upstream Reboiler

Tower Simulations: Normal simulation: First simulate the tower for the normal operation based on the process basis information provided. It is very important to match this simulation with the actual process data available for the respective system. Relief simulations: Tower simulations for various over pressure scenarios will be done at reduced reboiler duty straightaway. Following is the procedure to determine the reduced reboiler duty at a constant dirty “UA”





















For tower relief simulations, specify the number of trays equal to the actual number of trays. If there are any convergence issues, then try reducing the number of trays, If the tower does not converge even after reducing the number of trays, then use multiple flash drum method.

18.5.11

PVRV / PCV / Emergency load calculations for Tanks

The below calculation is based on API-2000.






DESIGN DATA / INPUT: 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Tank ID Tank T/T height Tank operating pressure Tank working temperature Inbreathing N2 PCV Outbreathing N2 PCV Pressure & Vacuum Relief Emergency Venting by Blow-off Hatch. SP for 113-PCV-1153 SP for 113-PCV-1152 SP for 113-PVV-1151 SP for Blow-off Hatch Filling rate Emptying rate Tank Capacity Tank Design Presure

= = = = = = = = = = = = = = = =

4 5.11 0.004903 50 113-PCV-1153 113-PCV-1152 113-PVRV-1151

m m barg

50 mmWC(g)

0.4903 Kpa(g)

11 11 64 29.4 -4.9

barg barg barg barg m³/h m³/h m³ mbarg mbarg

300 mmWC(g) -50 mmWC(g)

2.9420 Kpa(g) -0.4903 Kpa(g)

9.72

Kg/m

ASSUMPTIONS: 1 The Normal Boiling Point of tank liquid (50% LA) is less than 149°C. 2 Blow-off hatch provided for Emergency Venting. 3 o 3 Density of Nitrogen is taken as 9.72 Kg/m at 7.6 barg , 25 C.

3

CALCULATION: (A)

INBREATHING CALCULATION (VACUUM : EMPTY) (1) As per API std. 2000, for boiling point < 149°C ( Table-1B - Column -1) The requirement for venting capacity for maximum liquid movement out of the tank should be equivalent to 0.94 Nm³/h of Air for each cubic meter, per hour of maximum emptying rate. Maximum Emptying rate Nm³/h air required for this flow rate

= = =

(2) Thermal Inbreathing From Table-2B, Column-2 of API Std. 2000, Therefore, for tank capacity = 64 m³, by interpolation, Thermal venting capacity = 3.37 + (64-20)* (16.9 -3.37) / (100-20) = =

(B)

11 m³/h 10.3 Nm³/h of air 10.7 Nm³/h of N2

10.8 Nm³/h of Air 11.2 Nm³/h of N2

Requirements for Thermal Venting Capacity API 2000, Table 2B Tank Capacity Inbreathing Outbreathing FP>=37.8 FP<37.8 3 3 3 3 m Nm /h Nm /h Nm /h 1 1.69 1.01 1.69 20 3.37 2.02 3.37 100 16.9 10.1 16.9

OUTBREATHING CALCULATION (PRESSURE : FILLING) (1) As per API std. 2000, for boiling point < 149°C ( Table-1B - Column -3) The requirement for venting capacity for maximum liquid movement into the tank and the resulting vaporization should be equivalent to 2.02 Nm³/h for each cubic meter, per hour of maximum filling rate Maximum Filling rate Nm³/h air required for the above filling rate

= =

11 m³/h 22.22 Nm³/h of air

Nm³/h N2 required

=

23 Nm³/h of N2

(2) Thermal Outbreathing From Table-2B, Column-4 of API Std. 2000, Therefore, for tank capacity = 64 m³, by interpolation, Thermal venting capacity = 3.37 + (64-20)* (16.9 -3.37) / (100-20) =

Normal Venting Requirements API 2000, Table 1B Inbreathing Outbreathing Flash / Boiling Liq. Moving Point Liq. Moving In Out 0 3 3 3 3 C Nm /h / m /h Nm /h / m /h FP >=37.8 0.94 1.01 BP>=148.9 0.94 1.01 FP<37.8 0.94 2.02 BP<148.9 0.94 2.02

10.8 Nm³/h of Air 11.2 Nm³/h of N2

(3) Outbreathing Requirment for 113-PCV-1153 Fails Open ( Nitrogen) The basis is 113-PCV-1153 fail open with upstream Max. N2 pressure at 7.6 barg and downstream operating pressure of 0.004903 barg .The max flow(full bore) is 55 kg/h. Max Flow (form CV calculation) = 55 kg/h Molar Flow = 1.96 kgmol/h Nm³/h flow of N2 = 44.012 Nm³/h As per API Std. 2000, "The Normal Venting capacity shall be atleast the sum of the Venting requirements for Liquid movement and thermal effect - (Ref: Cl: 4.3.2 page 4)


42.51 Nm³/h of Air



(C)



Emergency Venting capacity calculation: (1) EXTERNAL FIRE CASE Nm³/h = 881.55 x Q x F / L x (T/M)^0.5 Where, Q = Heat input from fire exposure in watts = A = Weted surface area in m² F = environmental factor from table, 1B L = Latent heat of vaporization at relieving Pr & Temp, in J/kg T = Relieving temp in °K M = Molecular weight of vapor Design pressure of the tank = H= Height of Vertical tank = Height to be considered as per API = (Ref:Page 9 of API Std 2000 - notes below Table-3B) Wetted Surface Area of Tank = Wetted Surface Area Calculated , A = Refering to given table on page-9 of API std 2000, Heat Input to be considered , Q =

Latent heat of vaporisation Relieving temperature Molecular weight Environmental factor considered Venting requirement (2) Steam coil tube rupture case Amount of steam released from 2" ruptured coil (from equation of tube rupture) Latent heat of condensing steam at relieving P Latent heat of tank liquid at relieving P Amount of tank liquid vaporised Vapour density Venting requirement

= = = = = =

= = = = = = = = =

224200*A

0.566

0.03 barg 5.11 m 5.11 m (PI x D x H) 64

(Vertical height or 9.14m whichever is lower)

m²

2364583.315

2218200 105.5 378.5 18.11 1 4296

(<0.07 barg)

watts

J/kg °C °K kg/kgmol Nm³/h of AIR

12531 Kg/h 2252.6 KJ/Kg 2218.2 KJ/Kg Heat released by condensed steam / Latent heat of tank liquid 12725 Kg/h 0.8921 Kg/m3 14264 m3/h tank vapour (MolWt = 18.11) 10197 Nm3/h of tank vapour 6368 Nm3/h of Air



L&T- CHIYODA LIMITED Date: Feb 15, 2007 Rev: 0 18.6



Annexure-6 (Typical Flare Load Summary sheet)




Date: Feb 15, 2007 Rev: 0

18.7


Annexure-7 (Flare Header / PSV outlet line sizing) 18.7.1 Individual Failure – Single contingency contributing the POWER LOST TO UNIT

I N P U T

LINE NO. FROM PSV-328123 A/B/C/D TO SUBHEADER Nominal Dia. inch 18 Pipe Class A1A Schedule I.D. mm 445.2 Length m 50 Roughness mm 0.0500 Flow Rate Nm3/hr 24,085.2 Viscosity CP 0.02 MW 85.82 Cp/Cv 1.08 Z 0.909 Temp degC 125 Press., @In kg/cm2G 1.711 Press., @In BarG 1.679 Flow Area m2 0.156 Weight Flow kg/h 92221 Weight Flow kg/s 25.617 Gas Density @In kg/m3 7.6782 Volume Flow @In m3/s 3.336 Velocity @In m/s 21.432 Re. No. 3.66E+06 Fric. Factor 0.01269 Press., @Out kg/cm2G 1.686 Press., @Out BarG 1.653 GasDns @Out kg/m3 7.606 Vol. Flow @Out m3/s 3.368 Velocity @Out m/s 21.636 Mach no. @Out 0.111 PIPE FRICTION LOSS 0.026 PSV Set Pressure (Kg/cm2G) 3.5 PSV Type (Conv./Balanced Bellows) Pilot operated Acceptable Back Pressure (Kg/cm2G 1.93 Line size is acceptable or not Yes Total Pressure Drop 0.41 O

SUBHEADER HEADER

SUBHEADER FLARE KOD 20 A1A

FLARE KOD B/L

495.3 58 0.0500 72,255.7 0.02 85.82 1.08 0.909 125 1.686 1.653 0.193 276663 76.851 7.6058 10.104 52.442 9.88E+06 0.01219 1.515 1.486 7.129 10.781 55.953 0.287 0.171

30 A1A S10 746.16 479 0.0500 72,255.7 0.02 85.82 1.08 0.909 125 1.515 1.486 0.437 276663 76.851 7.1285 10.781 24.654 6.56E+06 0.01149 1.343 1.317 6.648 11.561 26.438 0.136 0.172

30 A1A S10 746.16 115 0.0500 72,255.7 0.02 85.82 1.08 0.909 125 1.343 1.317 0.437 276663 76.851 6.6477 11.561 26.438 6.56E+06 0.01149 1.300 1.275 6.527 11.774 26.926 0.138 0.043

3

12

5

90 Elbow O 45 Elbow Reducer Expander Gate valve Flow thro' straight outlet tee Flow thro' side outlet tee Equivalent Length, meters

35.6

29.7

179.1

74.6

Straight Length, meters Total length, meters

7.0 49.6

14.0 57.7

150.0 479.1

20.0 114.6

2 1 1 1

maximum load)





18.7.2

Group failure

18.7.2.1

Fire Envelope, Combined Cooling water


Envelope-8


68 m

7m

5m

1.23 135

1.16 172

1.4 143


Cp/Cv Temp oC


18.8



Annexure-8 (Flare stack, Figure-A, B)






Flare Stack Height (Figure-A)

Drag Coefficient, C →

Determination of Drag Coefficient (Figure-B)

→





18.9

Annexure-9 (Flare knock out drum, Figure-C)

18.10

Annexure-10 (Seal drum, Figure-D)







Annexure-11 (Typical flare system P&I Diagram)






Format for Relief load calculation sheets

19.0 OTHER REFERENCES 19.1

Handbook by Crosby

19.2

Questions and Answers for API-520 / 521



PSV and Flare

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