dp15c

ExxonMobil Proprietary SAFETY IN PLANT DESIGN

PRESSURE RELIEF DESIGN PRACTICES

Section XV-C

Page 1 of 156

June, 2004

Changes shown by Æ

CONTENTS SECTION

PAGE Revision Memo

1 SCOPE ....................................................................................................................................................... 8 2 REFERENCES............................................................................................................................................ 8 2.1 DESIGN PRACTICES....................................................................................................................... 8 2.2 GLOBAL PRACTICES ...................................................................................................................... 8 2.3 OTHER REFERENCES .................................................................................................................... 8 3 DEFINITIONS ............................................................................................................................................. 9 4 SUMMARY OF SPECIFIC EXXON MOBIL REQUIREMENTS ................................................................ 15 5 BASIC DESIGN CONSIDERATIONS....................................................................................................... 23 5.1 CONTINGENCY BASIS FOR DESIGN........................................................................................... 23 5.2 APPLICATION OF CODES AND STATUTORY REGULATIONS ................................................... 24 5.3 SUMMARY OF PRESSURE RELIEF DESIGN PROCEDURE ....................................................... 24 5.3.1 Consideration of Contingencies................................................................................................. 24 5.3.2 Selection of Pressure Relief Device .......................................................................................... 24 5.3.3 Pressure Relief Device Specification......................................................................................... 25 5.3.4 Design of Pressure Relief Device Installation............................................................................ 25 5.3.5 Summation and Documentation of Contingencies..................................................................... 25 6 DESIGN PROCEDURE, PART I: CONSIDERATION OF CONTINGENCIES AND DETERMINATION OF RELIEVING RATES .......................................................................................................................... 25 6.1 INTRODUCTION............................................................................................................................. 25 6.2 FIRE AS A CAUSE OF OVERPRESSURE..................................................................................... 26 6.2.1 Equipment to be Protected ........................................................................................................ 26 6.2.2 Determination of Relieving Rate and Risk Area ........................................................................ 27 6.2.3 Protection of Vessels from Fire Exposure, in Addition to Pressure Relief ................................. 28 6.3 UTILITY FAILURE AS A CAUSE OF OVERPRESSURE ............................................................... 28 6.3.1 General Considerations............................................................................................................. 28 6.3.2 Electric Power ........................................................................................................................... 29 6.3.3 Cooling Water............................................................................................................................ 31 6.3.4 Steam ........................................................................................................................................ 32 6.3.5 Instrument Air ............................................................................................................................ 32 6.3.6 Instrument Power ...................................................................................................................... 33 6.3.7 Fuel ........................................................................................................................................... 33 6.3.8 Other Utilities............................................................................................................................. 33 6.4 EQUIPMENT MALFUNCTION AS A CAUSE OF OVERPRESSURE............................................. 33 6.5 PURGING / CLEANOUT................................................................................................................. 33 6.6 LIQUID OVERFILL AS A CAUSE OF OVERPRESSURE............................................................... 34

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6.7 OPERATOR ERROR AS A CAUSE OF OVERPRESSURE ........................................................... 35 6.8 EVALUATION OF OVERPRESSURE RESULTING FROM EMERGENCY CONDITIONS, AND DETERMINATION OF RELIEVING RATES........................................................................... 35 6.8.1 Failure of Automatic Control ...................................................................................................... 35 6.8.2 Cooling Failure in Condenser/Cooler ........................................................................................ 38 6.8.3 Air Fin Exchanger Failure .......................................................................................................... 38 6.8.4 Special Conditions in Closed Circuit.......................................................................................... 39 6.8.5 Reflux Flow Failure.................................................................................................................... 39 6.8.6 Pumparound Flow Failure ......................................................................................................... 39 6.8.7 Absorbent Flow Failure ............................................................................................................. 39 6.8.8 Loss of Heat in Series Fractionation System............................................................................. 39 6.8.9 Abnormal Process Heat Input.................................................................................................... 40 6.8.10 Emergency Conditions in Integrated Plants............................................................................ 40 6.8.11 Accumulation of Noncondensibles.......................................................................................... 40 6.8.12 Water or Light Hydrocarbon Into Hot Oil................................................................................. 40 6.8.13 Internal Equipment Blockage.................................................................................................. 41 6.8.14 Manual Valve Maloperation .................................................................................................... 41 6.8.15 Hydraulic Surge ...................................................................................................................... 41 6.8.16 Startup, Shutdown and Alternate Operations ......................................................................... 41 6.8.17 Increased Plant Capacity........................................................................................................ 41 6.9 OVERPRESSURE IN SPECIFIC EQUIPMENT ITEMS .................................................................. 42 6.9.1 Heat Exchanger Split Tube and Tube Leakage......................................................................... 42 6.9.2 Pumps and Downstream Equipment ......................................................................................... 43 6.9.3 Compressor and Downstream Equipment................................................................................. 45 6.9.4 Steam Turbine........................................................................................................................... 45 6.9.5 Fired Heaters and Boilers.......................................................................................................... 47 6.9.6 Fractionator Overhead System.................................................................................................. 48 6.9.7 Pressurized Storage (Offsites) .................................................................................................. 49 6.9.8 Piping ........................................................................................................................................ 50 6.10

OVERPRESSURE CAUSED BY CHEMICAL REACTION....................................................... 50

6.11

OVERPRESSURE CAUSED BY ABNORMAL TEMPERATURE ............................................ 51

6.12 OVERPRESSURE CAUSED BY THERMAL EXPANSION...................................................... 51 6.12.1 Overpressure Potential in Piping ............................................................................................ 51 6.12.2 Method of Protection Against Liquid Thermal Expansion Overpressure................................. 53 6.12.3 Application of Liquid Thermal Expansion Protection............................................................... 53 6.12.4 Installation Details for Liquid Thermal Expansion PR Valve ................................................... 54 6.13 VACUUM AS A CAUSE OF EQUIPMENT FAILURE............................................................... 55 6.13.1 General................................................................................................................................... 55 6.13.2 Design of Equipment to Avoid Failure Under Vacuum............................................................ 56 6.14 EVALUATION OF PRESSURIZATION PATH IN PRESSURE RELIEF DESIGN .................... 56 6.14.1 Piping ..................................................................................................................................... 56 6.14.2 Check Valve ........................................................................................................................... 57 6.14.3 Restrictions............................................................................................................................. 58 6.14.4 Control Valve .......................................................................................................................... 58 6.15 EVALUATION OF ESCAPE PATH IN PRESSURE RELIEF DESIGN..................................... 59 6.15.1 Grouping of Interconnected Vessels....................................................................................... 59 6.15.2 Heat Exchanger Tube Failure................................................................................................. 59 6.15.3 Piping for Interconnecting Vessels and Pressure Relief Facilities .......................................... 59 6.15.4 Car-Sealed Open Valve.......................................................................................................... 59 6.15.5 Car-Sealed Closed Valve ....................................................................................................... 60

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Section XV-C

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6.15.6 Control Valve .......................................................................................................................... 60 6.15.7 Flow Meter Orifice Plate ......................................................................................................... 61 6.15.8 Check Valve ........................................................................................................................... 61 6.15.9 Flow Restriction in Relieving Path Through Equipment.......................................................... 61 6.15.10 Flame Arresters, Detonation Arresters, and Demisting Screens........................................... 61 6.15.11 Parallel Flow Paths ............................................................................................................... 62 7 DESIGN PROCEDURE, PART II PRESSURE RELIEF DEVICES........................................................... 62 7.1 CONVENTIONAL PRESSURE RELIEF VALVE ............................................................................. 62 7.1.1 General Operation and Characteristics ..................................................................................... 62 7.1.2 Valve Opening Characteristics for Vapor Service...................................................................... 63 7.1.3 Valve Opening Characteristics For Liquid Service .................................................................... 63 7.2 BALANCED BELLOWS PRESSURE RELIEF VALVE.................................................................... 64 7.2.1 Application................................................................................................................................. 64 7.2.2 Back Pressure Limitations ......................................................................................................... 64 7.2.3 Bonnet Venting on Bellows Valves............................................................................................ 64 7.3 PILOT-OPERATED PRESSURE RELIEF VALVE .......................................................................... 65 7.3.1 Operating Characteristics .......................................................................................................... 65 7.3.2 Pilot Sensing Point Location...................................................................................................... 66 7.3.3 Pilot Sensing Point Lines........................................................................................................... 66 7.3.4 Pilot Operated Valve Accessories ............................................................................................. 66 7.3.5 Advantages ............................................................................................................................... 66 7.3.6 Disadvantages........................................................................................................................... 67 7.3.7 Applications ............................................................................................................................... 67 7.3.8 Venting of Pilot Vents ................................................................................................................ 68 7.4 EFFECT OF BACK PRESSURE ON PRESSURE RELIEF VALVE................................................ 68 7.4.1 Back Pressure Effects on Valves .............................................................................................. 68 7.4.2 Back Pressure Factors in Pressure Relief Valve Design........................................................... 68 7.5 PRESSURE RELIEF VALVE CHATTERING .................................................................................. 70 7.5.1 Oversized Valve ........................................................................................................................ 70 7.5.2 Excessive Inlet Pressure Drop .................................................................................................. 70 7.5.3 Excessive Built-up Back Pressure............................................................................................. 70 7.5.4 Blowdown Ring Settings............................................................................................................ 71 7.5.5 Liquid Filled Systems ................................................................................................................ 71 7.6 MULTIPLE PRESSURE RELIEF VALVE INSTALLATION ............................................................. 71 7.6.1 Large Release ........................................................................................................................... 71 7.6.2 Preventing Chattering................................................................................................................ 71 7.6.3 Preventing Separation............................................................................................................... 72 7.6.4 Design of Multiple PR Valve Installation.................................................................................... 72 7.7 SPECIAL FEATURES FOR SPRING-LOADED PRESSURE RELIEF VALVE ............................... 72 7.7.1 Soft Seat ................................................................................................................................... 72 7.8 RUPTURE DISC ............................................................................................................................. 73 7.8.1 Advantages ............................................................................................................................... 73 7.8.2 Disadvantages........................................................................................................................... 74 7.8.3 Acceptable Types of Rupture Discs .......................................................................................... 74 7.8.4 Rupture Disc Certification and Testing ...................................................................................... 75 7.8.5 Rupture Disc Specification ........................................................................................................ 75 7.8.6 Manufacturing Range of Rupture Discs..................................................................................... 75 7.8.7 Rupture Disc Burst Pressure ..................................................................................................... 75 7.8.8 Rupture Disc Burst Temperature............................................................................................... 76

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7.8.9 Rupture Disc Sizing................................................................................................................... 76 7.8.10 Rupture Disc Installation......................................................................................................... 77 7.8.11 Rupture Disc Replacement Program ...................................................................................... 78 7.9 EXPLOSION HATCH ...................................................................................................................... 78 7.10 LIQUID SEAL........................................................................................................................... 78 7.10.1 Description ............................................................................................................................. 78 7.10.2 Design Features ..................................................................................................................... 78 7.11

VACUUM RELIEF VALVE ....................................................................................................... 78

7.12 RUPTURE PIN VALVES.......................................................................................................... 79 7.12.1 Buckling Pin Concept ............................................................................................................. 79 7.12.2 RPV Design / Operation ......................................................................................................... 79 7.12.3 RPV Sizing ............................................................................................................................. 79 7.13

PRESSURE RELIEF VALVE FOR FOULING SERVICE ......................................................... 80

7.14 OVERPRESSURE PROTECTION BY USE OF RESTRICTIONS AND ESCAPE PATHS ...... 80 7.14.1 Restrictions............................................................................................................................. 80 7.14.2 Escape Paths ......................................................................................................................... 80 8 DESIGN PROCEDURE, PART III: PRESSURE RELIEF VALVE SIZING AND SPECIFICATION PROCEDURES ............................................................................................................................................. 80 8.1 SIZING FOR VAPOR SERVICE ..................................................................................................... 80 8.1.1 Critical and Subcritical Flow ...................................................................................................... 80 8.1.2 Determination of Critical Flow Pressure .................................................................................... 81 8.1.3 Sizing for Vapor Critical and Subcritical Flow ............................................................................ 81 8.1.4 Sizing of Hydrocarbon Vapor / Hydrogen / Steam Mixtures ...................................................... 83 8.2 SIZING FOR NON-FLASHING LIQUID SERVICE .......................................................................... 83 8.2.1 Sizing Capacity Certified Relief Valves ..................................................................................... 83 8.2.2 Sizing Safety Relief Valves Not-Capacity Certified.................................................................... 84 8.3 SIZING FOR FLASHING MIXED-PHASE (VAPOR AND LIQUID) AND FLASHING LIQUID SERVICE ....................................................................................................................................... 85 8.3.1 Two-Phase Flashing Flow ......................................................................................................... 86 8.3.2 Subcooled or Saturated Liquid Inlet .......................................................................................... 88 8.4 SIZING OF PILOT-OPERATED PRESSURE RELIEF VALVES ..................................................... 91 8.5 PREPARATION OF DESIGN SPECIFICATION FOR PRESSURE RELIEF VALVES.................... 91 8.5.1 Summary of Contingencies ....................................................................................................... 91 8.5.2 Critical Condition ....................................................................................................................... 92 8.5.3 Emergency Temperature........................................................................................................... 92 8.5.4 Design Temperature.................................................................................................................. 92 8.5.5 Set Pressure.............................................................................................................................. 92 8.5.6 Allowable Overpressure ............................................................................................................ 92 8.5.7 Estimated Superimposed Back Pressure .................................................................................. 92 8.5.8 Estimated Built-Up Back Pressure ............................................................................................ 93 8.5.9 Estimated Total Back Pressure ................................................................................................. 93 8.5.10 Number of Valves Required ................................................................................................... 93 8.5.11 Differential Spring Pressure.................................................................................................... 94 8.5.12 PR Valve Type and Size......................................................................................................... 94 8.5.13 Effect of Temperature on Back Pressure Limits of PR Valves................................................ 96 9 DESIGN PROCESS PART IV - PRESSURE RELIEF VALVE SIZING INSTALLATION ........................ 97 9.1 PRESSURE RELIEF VALVE LOCATION ....................................................................................... 97 9.2 SELECTION OF ATMOSPHERIC OR CLOSED DISCHARGE FOR PRESSURE RELIEF VALVES97

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9.2.1 Discharge to a Closed System .................................................................................................. 97 9.2.2 Discharge to Atmosphere .......................................................................................................... 98 9.2.3 Discharge Paths for Multiple Valves.......................................................................................... 98 9.2.4 Application of Criteria for Routing of PR Valve Discharge......................................................... 98 9.3 PREVENTION OF PLUGGING IN PR VALVE INLETS OR OUTLETS........................................... 99 9.4 DESIGN OF PR VALVE INLET PIPING........................................................................................ 100 9.4.1 Inlet Piping Pressure Drop....................................................................................................... 100 9.4.2 Inlet Pipe Sizing....................................................................................................................... 100 9.4.3 Inlet Pipe Layout...................................................................................................................... 100 9.5 DESIGN OF PR VALVE OUTLET PIPING.................................................................................... 100 9.5.1 Discharge to Atmosphere ........................................................................................................ 100 9.5.2 Discharge to a Closed System ................................................................................................ 101 9.6 ISOLATION VALVES FOR PRESSURE RELIEF SYSTEMS ....................................................... 103 10 APPENDIX 1 PROTECTION OF VESSELS AGAINST OVERPRESSURE DUE TO EXTERNAL FIRE ................................................................................................................................. 139 10.1

STEP 1 - AMOUNT OF HEAT ABSORBED........................................................................... 139

10.2

STEP 2 - VAPOR RELEASE RATE AND REQUIRED RELIEF AREA .................................. 145

10.3

DRY VESSELS AND VESSELS CONTAINING SUPERCRITICAL FLUIDS.......................... 148

11 APPENDIX 2 TRANSIENT PRESSURE RESPONSE SIMULATION FOR FLARE SIZING.................. 150 12 APPENDIX 3 CALCULATION OF TUBE RUPTURE RELIEF LOAD ................................................... 152 13 APPENDIX 4 DETAILED REVISION MEMO......................................................................................... 154

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PRESSURE RELIEF DESIGN PRACTICES

Section XV-C

Page 6 of 156

June, 2004

FIGURES Figure I-1 Bottom and Top-Guided Low-Lift Valve for Turbine Exhaust .................................................................. 106 Figure II-1 Typical Conventional Pressure Relief Valve........................................................................................... 112 Figure II-2 Characteristics of Typical Pressure Relief Valve .................................................................................... 113 Figure II-3 Forces Acting on Discs of Balanced Bellows and Conventional Pressure Relief Valves....................... 114 Figure II-4 Pressure Conditions for Pressure Relief Valve Installed on a Pressure Vessel (Vapor Phase) ............. 115 Figure II-5 Typical Balanced Bellows Pressure Relief Valve ................................................................................... 116 Figure II-6 Typical Pilot-Operated Pressure Relief Valve......................................................................................... 117 Figure II-7 Operation of the Agco Patented Fully Adjustable Non-Flowing Pilot Operated Pressure Relief Valve.. 118 Figure II-8 "O" Ring Seat Seal Pressure Relief Valve.............................................................................................. 119 Figure II-9 Pre-Scored Reverse Buckling Rupture Disc........................................................................................... 114 Figure II-10 Pre-Scored Tension-Loaded Rupture Disc........................................................................................... 115 Figure II-11 Effect of Temperature on Burst Pressure for Conventional Rupture Discs........................................... 122 Figure II-12 Explosion Hatch for Asphalt Oxidizer ................................................................................................... 123 Figure II-13 Rupture Pin Device .............................................................................................................................. 124 Figure II-14 Balanced Rupture Pin Device............................................................................................................... 125 Figure III-1 Critical Flow Pressure for Hydrocarbons ............................................................................................... 133 Figure III-2A Variable or Constant Total Back Pressure Factor, Kb, for Conventional or Pilot Operated Pressure Relief Valves (Vapors and Gases) Subcritical Flow ....................................................................................... 134 Figure III-2B Variable or Constant Total Back Pressure Factor, Kb, for Balanced Bellows Pressure Relief Valves (Vapors and Gases) Critical Flow Only ......................................................................................................... 134 Figure III-3 Viscosity Correction: Procedure per API RP-500 ................................................................................. 135 Figure III-4 Variable or Constant Back Pressure Sizing Factor Kw, on Balanced Bellows Pressure Relief Valves (Liquids Only) ................................................................................................................................................. 136 Figure III-5 Capacity Correction Factors Due to Overpressure for Non-ASME Certified Relief Valves in Liquid Service ........................................................................................................................................................... 137 Figure III-6 Critical Two-Phase Pressure Ratio for Subcooled Liquids .................................................................... 138 Figure A1-1 Heat Absorbed from Fire Exposure for Facilities With Good Drainage ................................................ 143 Figure A1-2 Heat Absorbed from Fire Exposure for Facilities With Poor Drainage ................................................. 144

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Section XV-C

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TABLES Table I-1A Pressure Relief Valve Contingencies (Customary) ................................................................................ 104 Table I-1B Pressure Relief Valve Contingencies (Metric) ........................................................................................ 105 Table II-1 Summary of Acceptable Rupture Discs ................................................................................................... 107 Table II 2 Typical Manufacturing Ranges For rupture discs..................................................................................... 108 Table II-3 Rupture Disc Specification Sheet ............................................................................................................ 109 Table II-4 Typical Pressure Temperature Limits for Pre-Scored Reverse Buckling Rupture Discs.......................... 110 Table II-5 Typical Pressure Temperature Limits for Pre-Scored Tension-Loaded Rupture Discs............................ 111 Table III-1 Thermodynamic Properties of Various Substances at 60ºF (15ºC) and Atmospheric Pressure ............. 126 Table III-2 Crosby and Farris Steel Full Nozzle Relief Valves ............................................................................. 12727 Table III-3 CROSBY AND Farris Pressure Relief Valves for Low-Temperature Service ......................................... 131 Table III-4 Values of Constant "C" for Flow Formula Calculations ........................................................................... 132

Revision Memo

06/04

General revision to be consistent with ExxonMobil experience. Detailed revision Memo provided as APPENDIX 4 at the end of this section

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PRESSURE RELIEF DESIGN PRACTICES

Section XV-C

Page 8 of 156

June, 2004

1

SCOPE

This section describes the basic principles and procedures for the evaluation of overpressure potential in plant equipment, and for the selection, design and specification of appropriate pressure relieving facilities. The design of closed pressure relief valve and flare headers is included in this section, but blowdown drums and flares are covered under DP XV, DP XV-D and XV-E, respectively. 2 2.1

Design Temperature, Design Pressure and Flange Rating

DP X-A

Pumping Service Design Procedures

DP X-F

Positive Displacement Pumps

DP XIV

Fluid Flow GLOBAL PRACTICES

GP 03-02-01,

Sewer Systems

GP 03-02-04,

Pressure Relieving Systems

GP 03-03-02,

Suction and Discharge Piping for Centrifugal Pumps

GP 03-03-07,

Inlet and Exhaust Piping for Steam Turbines

GP 03-06-03,

Utility Connections to Piping and Equipment

GP 03-15-01,

Pressure Relief Valves

GP 03-12-01

Valve Selection

GP 05-03-01,

Pressure Testing of Unfired Pressure Vessels

GP 07-01-01,

Fired Heaters

GP 07-02-01,

Industrial Boilers

GP 08-01-01,

Cooling Towers

GP 09-07-03,

Vents for Fixed Roof Atmospheric Storage Tanks

GP 14-03-01,

Fireproofing

GP15-01-01,

Instrumentation for Fired Heaters

GP15-07-02,

Protective Systems

GP 18-10-01,

Additional Requirements for Materials

2.3

ç

DESIGN PRACTICES

DP II

2.2

ç

REFERENCES

1. 2. 3. 4. 5. 6. 7.

OTHER REFERENCES Exxon Blue Book. ASME - Section I, Power Boilers. ASME - Section VIII, Pressure Vessels. ASME B31.3, Process Piping. API RP-520, Sizing, Selection and Installation of Pressure Relieving Devices in Refineries - Part I: Sizing and Selection (7th edition, 2000); Part II: Installation (4th edition, 1994). API RP-521, Guide for Pressure Relieving and Depressuring Systems (4th edition, 1997). th API RP-526, Flanged Steel Pressure-Relief Valves (5 edition, 2002).

EXXONMOBIL RESEARCH AND ENGINEERING COMPANY – FAIRFAX, VA

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PRESSURE RELIEF DESIGN PRACTICES

8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23.

Section XV-C

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Standards of the Heat Exchange Institute (HEI). Acoustically Induced Vibration of High Capacity Pressure Reducing Systems, ER&E Report No. EE.25E.76. Surge Relief Devices for Liquid Filled Piping Systems, ER&E Report No. EE.74E.83. Rupture Discs: A Primer, ER&E Report No. EE.79E.84. Sizing Pressure Relief Valves in Flashing and Two-Phase Service, an Alternative Procedure, ER&E Report No. EE.28E.90. Overpressure Protection Guidelines for Vessels Exposed to Fire, ER&E Report No. EE.72E.93. Non-Fragmenting CSR Rupture Disc Holder, ER&E Report No. EE.92E.92. Reducing Pressure Relief Valve Chatter Induced by Hydraulic Surge, ER&E Report No. EE.86E.95. Safety Technology Manual, TMEE-0073 Updated Guidelines for Preventing Chatter of Pressure Relief Valves in Liquid Filled Systems, ER&E Application Guide EE.35E.98 Improved Analysis Method for Use in Pipe Pressure Surge Evaluations, EE.62E.86 “Break-X” Computer Program for Predicting Peak Pressures in Heat Exchangers due to Tube Rupture, EE.18E.81 Brittle Fracture of Existing Equipment – How to Prevent It, EE.11E.84 Assessment of Equipment for Brittle Fracture, EE.89E.89 Application of Safety Instrumented Systems for the Process Industries, ISA.S84.01-1996 Use of High Integrity Protective Systems (HIPS) to Reduce Loads on Existing Flare Systems, EE.137E.95.

24. Qualifications of Carbon Steel Exchanger Tubes for Service at -150°F (-101°C), EE.10E.78 ç 25. Guidelines for Pressure Relief and Effluent Handling Systems, Center for Chemical Process Safety (CCPS), American Institute of Chemical Engineers (AIChE), 1998. ç 26. Sizing Pressure Relief Valves for Flashing Mixed Phase and Flashing Liquid Service, EE.810E.2002. ç 27. Preventing Multiple Tube Ruptures in Heat Exchangers, EE.717E.2002. ç 28. Maintenance Practices Manual, TMEE-062. ç 29 Leung, J.C. “Size Safety Relief Valves for Flashing Liquids”, Chemical Engineering Progress, February 1992. 3

DEFINITIONS

Accumulation Accumulation is the pressure increase over the maximum allowable working pressure or design pressure (in psi or kPa) of the vessel during discharge through the pressure relief valve, expressed as a percent of that pressure. (See definition of Design Pressure.) Back Pressure Back Pressure General - Is the pressure on the discharge side of a pressure relief valve. Total back pressure is the sum of superimposed and built-up back pressures. Superimposed Back Pressure - Is the pressure at the outlet of the pressure relief valve while the valve is in a closed position. This type of back pressure comes from other sources in the discharge system; it may be constant or variable; and it may govern whether a conventional or balanced valve should be used in specific applications. Built-up Back Pressure - Is the increase in pressure at the outlet of a pressure relief device that develops (typically due to friction but also static) as a result of flow through the discharge system after the pressure relief valve opens. Balanced Pressure Relief Valve A pressure relief valve which is designed to minimize the effect of back pressure on its performance characteristics.

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DESIGN PRACTICES

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Balanced Bellows Pressure Relief Valve A balanced pressure relief valve that incorporates a vented bellows as the means for minimizing the effect of back pressure on the performance characteristics: opening pressure, closing pressure, lift and relieving capacity. Blowdown Blowdown is the difference between the set pressure and the reseating pressure of a pressure relief valve, expressed as percent of set pressure. Closed Discharge System This is the discharge piping for a PR valve which releases to a collection system, such as a blowdown drum and flare header. However, a closed system can also be a process vessel or other equipment at a pressure lower than the set pressure of the PR valve. Cold Differential Test Pressure The cold differential test pressure (in psig or kPa gage) is the pressure at which the valve is adjusted to open on the test stand. This cold differential test pressure includes the corrections for service conditions of superimposed back pressure and temperature. Combustible Liquid with a flash point at or above 100°F (38°C) and handled at more than 15°F (8°C) below its flash point. Common Cause Failure Mode A coincident failure in two or more similar elements of a system caused by a single event. An example of a common cause failure mode is the simultaneous failure of two independent level instruments due to freezing of the process fluid in the instrument leads when exposed to low ambient temperatures. Conventional Pressure Relief Valve A conventional pressure relief valve is a closed-bonnet spring-loaded pressure relief valve that has the bonnet vented to the discharge side of the valve and is therefore unbalanced. The performance characteristics, i.e., opening pressure, closing pressure, lift and relieving capacity, are directly affected by changes in the back pressure on the valve. Design Capacity The capacity used to determine the required area of a relief device based on the limiting contingency. Design Contingency An abnormal condition including maloperation, equipment malfunction, or other event which is not planned, but is foreseen to the extent that the situations involved are considered in establishing equipment design conditions. Design Pressure Design pressure is the pressure in the equipment or piping under consideration at the most severe combination of coincident pressure, temperature, liquid level and vessel pressure drop expected during service, which results in the greatest required component thickness and the highest component rating (e.g., highest ASME B16.5 flange class). More than one set of design conditions should be specified if the most severe pressure, temperature, liquid level and vessel pressure drop will not occur at the same time. For pressure vessels, it is the pressure at the top of the vessel. Maximum liquid level and vessel pressure drop (if appropriate) should also be specified. Design pressure is equal to or less than the maximum allowable working pressure.

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Section XV-C

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Double or Multiple Contingency Two or more independent, unrelated, abnormal events that, if they occurred simultaneously or within a restricted short time interval, could result in an emergency. Double or multiple contingencies are normally not considered in the setting of design conditions or the design of overpressure protection facilities. However, it is the responsibility of the designer to consider common cause failure modes which might reasonably apply. Examples of common cause failure modes include potentially fouling conditions, low winter temperatures or off normal operations, that might cause simultaneous failure of process control and protection systems. Another example is the failure to close of two identical check valves in series. In such circumstances, the designer may need to provide designated "safety critical" protection, such as instrument purge or heating, safety valve inlet/outlet line tracing, independent types of instrument sensors, use of different types of check valves when two check valves in series are used to minimize back flow, etc Emergency An interruption from normal operation in which personnel, equipment or the environment may be affected. Fire Risk Area A process plant is subdivided into fire risk areas, each of which is the maximum area which can reasonably be expected to be totally involved in a single fire. Fire Risk Areas are established by the provision of access ways or clear spacing at least 20 ft (6.1 m) wide on all sides with drainage to catch basins located within the fire risk area. This is used to determine the combined requirement for pressure relief due to fire exposure and should not be confused with the areas used to determine fire water and sewer capacities, which are defined as plot subdivision areas in DP XV-I, Fire Fighting Facilities. Flammable Liquid with a flash point below 100°F (38°C) or a liquid with a flash point at or above 100°F (38°C) but handled within 15°F (8°C) of its flash point. High Integrity Protective System (HIPS) An arrangement of instruments and other equipment, including sensors, logic controllers and final control elements used to isolate or remove a source of pressure from a system or to trip a shutdown or depressuring device such that the design pressure and/or temperature of the protected system will not be exceeded. Typical HIPS applications include load reduction to existing flare systems and the protection of systems where conventional protective systems such as pressure relief valves have proven to be unreliable or impractical. By definition, a HIPS is a safety critical system and must be independent from all other control schemes and from shutdown systems whose failure can lead to an event requiring HIPS activation. Functionally, a HIPS must provide equal or lower (better) unavailability on demand than a typical pressure relief valve. To ensure that this criterion is met, a HIPS should be specified to meet Safety Integrity Level (SIL) 3 or better. Safety Integrity Levels are defined elsewhere in this section. Intermediate - Time pressure Allowance (for piping only) Per ASME B31.3, an increase of not more than 20% above the design pressure or the allowable stress for pressure design at the temperature of the increased condition. It is permitted for a maximum of 50 hours at any one time and for less than 500 hours per year, provided the additional restrictions in DP II are met. Maximum Allowable Working Pressure (MAWP) For pumps and compressors, see DP X-A and DP XI-A. For pressure vessels, per the ASME Code, MAWP is the maximum (gauge) pressure permissible at the top of a vessel in its normal operating position at the designated coincident temperature and liquid level specified for that pressure. MAWP does not apply to piping. MAWP: 1. 2.

May be determined for more than one designated operating temperature and coincident liquid level, using for each temperature the applicable allowable stress value. Is the least of the values for the internal or external pressure for any of the pressure boundary parts.

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Is based on calculations using nominal thickness exclusive of allowances for corrosion and exclusive of thickness required for loadings other than pressure for every element of a vessel. Is assumed to be equal to the design pressure for all cases in which calculations were not made to determine the value of the MAWP. May, in final vessel construction be higher than the design pressure, due to the selection of thicker plates or plates with a nominal thickness greater than required in order to use a standard size.

Open Disposal System This is discharge piping of a PR valve, which releases to the atmosphere either directly or via a collection system (which could include a K.O. drum). Operating Pressure The operating pressure is the gauge pressure to which the equipment is normally subjected in service. A process vessel is usually designed for a pressure which will provide a suitable margin above the operating pressure, in order to prevent leakage of the relief device. For the relationship between normal operating pressure and design pressure, reference should be made to DP II, Design Temperature, Design Pressure and Flange Rating. Where it is necessary to raise operating pressure above the design operating basis, to avoid premature opening of a PR device, the maximum operating pressure can be related to the pressure relief valve set pressure (see Set Pressure). Where a spring-loaded pressure relief valve is used (either conventional or bellows type), up to 50 psig (345 kPa) set pressure, the maximum operating pressure shall be at least 5 psig (35 kPa) lower than the set pressure. For spring-loaded PR valves set above 50 psig (345 kPa), the maximum operating pressure shall be not more than 90% of set pressure. For a pilot operated pressure relief valve, the maximum operating pressure shall be not more than 95% of set pressure at or above 50 psig (345 kPa) and set pressure less 2.5 psig (17 kPa) below 50 psig (345 kPa). For pressure relief valves on low-pressure tankage, the valve manufacturer shall be consulted for appropriate set versus operating pressure limits. Overpressure Overpressure is the pressure increase over the set pressure of the relieving device during discharge. It is the same as accumulation when the relieving device is set at the maximum allowable working pressure of the vessel. It is also used as a generic term to describe an emergency which may cause the pressure to exceed the maximum allowable working pressure. Pilot-Operated Pressure Relief Valve A pilot-operated pressure relief valve is a PR valve that has the major flow device combined with and controlled by a self-actuated auxiliary pressure relief valve. This type of valve does not utilize an external source of energy and is balanced if the auxiliary PR valve is vented to the atmosphere. Pressure Relief Device A device actuated by inlet static pressure and designed to open during an emergency or abnormal condition to prevent the rise of internal fluid pressure in excess of a specified value. The device may also be designed to prevent excessive vacuum. The device may be a pressure relief valve, a non-reclosing pressure relief device or a vacuum relief valve. Pressure Relief Valve This is a generic term applying to relief valves, safety valves or safety relief valves. It is commonly abbreviated to “PR Valve." Rated Capacity The capacity a pressure relief device can pass when fully open at accumulated pressure. This rate is greater than or equal to the design capacity. The relationship between rated and design capacity is determined by the following ratio: (design capacity / required area) = (rated capacity / selected area).

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Relief Valve A relief valve is an automatic pressure-relieving device actuated by the static pressure upstream of the valve, and which opens in proportion to the increase in pressure over the opening pressure. It is used primarily for liquid service. Remote Contingency An abnormal condition which could result in exceeding design pressure at the coincident temperature, but whose probability of occurrence is so low it is not considered as a design contingency. Note that temperatures above the design temperature may also be permitted under remote contingency conditions. Rupture Disc Device A rupture disc device is actuated by inlet static pressure and is designed to function by the bursting of a pressureretaining diaphragm or disc. Usually assembled between mounting flanges, the disc may be of metal, plastic, or metal and plastic. It is designed to withstand pressure up to a specified level, at which it will fail and release the pressure from the system being protected. Safety Critical Device A Safety Critical Device is any device (mechanical, pneumatic, hydraulic, electrical, or electronic), system or subsystem whose failure to operate properly may result in loss of containment leading to possible explosion, fire, or uncontrollable release of hazardous material. Such events may result in: ·

Fatalities/serious injuries to personnel, or impact on the public

·

Major/extended duration or serious/significant resource commitment to address a potential environmental impact.

·

A larger or smaller community disruption

·

A corporate or regional financial impact.

Safety Critical Devices should be tested and maintained as part of a formal program designed to ensure that they will achieve the required level of availability and reliability during their life cycle. For safety critical alarms, written instructions should be provided to enable the operator to respond adequately to the alarm. Excluded from SCDs are those devices whose only consequence of failure is an environmental exception (reporting). This does not obviate the need for reporting environmental incidents. Also excluded from the SCD category are business critical devices whose consequence of failure is purely economic (e.g., custody transfer). Reliable operation of such devices is covered by other appropriate equipment strategies. The term "safety critical" is usually applied to instrumentation, but any device may qualify as safety critical if its failure could lead to serious consequences. For example, heat tracing systems (steam or electric) used to prevent plugging of pressure relief devices due to solidification of process fluids are considered safety critical and should be identified as such. Check valves can also be safety critical under certain conditions. Table 2 in DP XV-A lists some examples of safety critical check valve applications. Other examples of safety critical devices include restriction orifices that limit the flow rate to a pressure relief device and Emergency Block Valves (EBVs). Safety Critical Instrument Any instrument, electrical, electronic or analytical device or system whose failure to operate properly may result in one or more of the following: a.

A serious threat to the safety of plant personnel or the community through loss of containment and subsequent explosion, fire or personnel exposure to hazardous materials

b.

Serious equipment damage with associated safety risk to plant personnel or the community

c.

A serious environmental or industrial hygiene risk to plant personnel or the community.

The term Safety Critical Instrument is equivalent to the term Safety Instrumented System (SIS) in ISA-S84.01 and to the term Protective System in GP 15-07-02.

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Safety Critical Instruments are a subset of Safety Critical Devices. Safety Integrity Level (SIL) One of three possible discrete levels used to characterize the reliability of instrument-based safety systems as prescribed in ISA S84.01. SILs are defined in terms of Probability of Failure on Demand (PFD). The PFDs for various SIL levels are as follows: SAFETY INTEGRITY LEVEL (SIL)

PROBABILITY OF FAILURE ON DEMAND (PFD)

SIL-1

0.01 < PFD £ 0.1

SIL-2

0.001 < PFD £ 0.01

SIL-3

PFD £ 0.001

Safety Relief Valve An automatic spring-loaded pressure relieving device suitable for use either as a safety valve or a relief valve, depending on application. It is used for vapor/gas service or for liquid service. Safety Valve An automatic spring-loaded pressure-relieving device actuated by the static pressure upstream of the valve and characterized by a rapid full opening or pop action. It is used for vapor or gas service. Set Pressure The set pressure (expressed as psig or kPa gage or other increment above atmospheric pressure) is the inlet pressure at which the pressure relief valve is adjusted to open under service conditions. For a relief or safety relief valve in liquid service, the set pressure is to be considered the inlet pressure at which the valve starts to discharge with a significant volume under service conditions. For a safety or safety relief valve in gas or vapor service (including two-phase and supercritical conditions), the set pressure is to be considered the inlet pressure at which the valve pops open under service conditions. Short-Time Pressure Allowance (for piping only) Per ASME B31.3, an increase of not more than 33% above the design pressure or the allowable stress for pressure design at the temperature of the increased condition. It is permitted for a maximum of 10 hours at any one time and for less than 100 hours per year, provided the additional restrictions in DP II are met. Single Risk The equipment affected by a design contingency. Spring Pressure The spring pressure is equal to the set pressure minus the superimposed back pressure for a conventional PR valve. For a balanced pressure relief valve, the spring pressure equals the set pressure. 1.5 Times Design Pressure Rule Equipment design per the ASME Code Section VIII, Division 1, is considered to be adequately protected against overpressure from remote contingencies if the maximum pressure during the remote contingency event can not exceed the proof test pressure, or 1.5 times the design pressure whichever is lower. Equipment designed per the ASME Code Section VIII, Division 2, is considered to be adequately protected against overpressure from remote contingencies if the maximum possible pressure can not exceed the proof test pressure, or 1.25 times the design pressure whichever is lower.

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In addition, the maximum membrane stress in the equipment should not exceed the yield strength for the equipment material at the actual metal temperature experienced by the equipment during the remote contingency under consideration. 4 SUMMARY OF SPECIFIC EXXON MOBIL REQUIREMENTS

S

This section presents a summary of specific requirements that apply to ExxonMobil facilities. These requirements are based on ExxonMobil’s interpretation of the broad principles contained in API Recommended Practices RP 520 and RP 521 and reflect ExxonMobil experience and overpressure protection philosophy. Additional background information for these requirements can be found elsewhere in DP XV-C. The intent of this summary is to expedite access to this information by Contractors and other practitioners engaged in the front-end design of process facilities for ExxonMobil affiliates and licensees. THIS SUMMARY DOES NOT RELIEVE THE USER FROM THE RESPONSIBILITY OF COMPLYING WITH ALL OF THE REQUIREMENTS OF DP XV-C AND API RECOMMENDED PRACTICES RP 520 AND RP 521. IN CASE OF CONFLICT BETWEEN THIS SUMMARY AND THE MAIN BODY OF DP XV-C, THE MAIN BODY OF DP XV-C GOVERNS. 1.

The simultaneous occurrence of two or more abnormal situations (double or multiple contingencies) need not be considered in the design of overpressure protection facilities.

2.

No credit may be taken for operator intervention in preventing a potential overpressure incident..

3.

No credit may be taken for the actions of process control or safety critical instruments other than High Integrity Protective Systems (HIPS) in preventing a potential overpressure incident.

4.

The following basis should be used to determine the maximum flow rate arising from failure of a control valve in the fully open position:

Type of Contingency Design

Flow Basis for Control Valve Installed flow coefficient (Cv) Upstream pressure operating pressure

=

maximum

Downstream pressure = 1.1 x MAWP of downstream system. Remote

Installed flow coefficient (Cv) Upstream pressure operating pressure

=

Flow Basis for Bypass Valve 50% of Cv of control valve at its normal operating position. Pressure drop same as that for control valve.

Installed flow coefficient (Cv). maximum

Pressure drop same as that for control valve.

Downstream pressure = 1.5 x MAWP of downstream system or proof test pressure of downstream system, whichever is lower. ç

5.

Under certain conditions, failure of a control valve in the open position may result in vapor blow-through into a system that is initially filled with stagnant (non-flowing) liquid. This situation may arise, for example, during the startup of certain hydrodesulfurization or hydroconversion units equipped with high-pressure liquid-vapor separators that feed the liquid to lower-pressure stripping towers. When this happens, the pressure in the downstream piping and equipment may temporarily approach that of the equipment upstream of the control valve as the liquid contained in the downstream system is accelerated. For such systems, the pressure-temperature rating of the piping and the design pressure of the equipment (vessels, exchangers) downstream of the control valve shall be determined as follows: 1. Determine the extent of piping and equipment that could be TOTALLY filled with stagnant (non-flowing) liquid immediately before the control valve fails open. 2. For any piping that could be TOTALLY filled with stagnant (non-flowing) liquid, specify a pressure-temperature rating such that the maximum operating pressure of the equipment upstream of the letdown valve does not exceed the short-term allowable pressure for the selected pressure-temperature rating at the operating

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temperature of the upstream system. The short-term allowable pressure is typically 133% of the maximum continuous pressure allowed for a given pressure-temperature rating. For any equipment (vessels, exchangers) that could be TOTALLY filled with stagnant (non-flowing) liquid, specify a design pressure such that the maximum operating pressure of the equipment upstream of the letdown valve does not exceed “C” times the design pressure, where “C” is the multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01. When the application of these guidelines results in an unreasonable increase in the cost of downstream equipment or piping, the following alternatives may be considered: 1. Perform a dynamic analysis of the downstream system to determine the peak pressures as a function of time and downstream distance from the letdown valve. In some cases it may be possible to address the concern by specifying a maximum opening and/or closing rate for the control valve. 2. Consider modifying the configuration of the downstream piping and equipment or the startup sequence such that only a minimal amount of piping and equipment is 100% filled with stagnant (non-flowing) liquid whenever vapor blow-through is a credible scenario. 3. Provide a pressure relief device immediately downstream of the pressure letdown valve set at the maximum allowable working pressure of any piping or equipment located between the pressure letdown valve and the next piece of downstream equipment protected by a pressure relief device. This pressure relief device should be sized for the maximum vapor flow rate that can pass through the fully open control valve.

6.

The following basis should be used to determine the residual cooling capacity of air-cooled exchangers upon failure of the cooling air supply or control mechanisms: Type of Failure

Residual Cooling Capacity

Type of Contingency

Loss of the fan in a single fan unit.

10% of the design capacity for condensers, 30% of the design capacity for coolers.

Design

Loss of one fan in a multi-fan unit

Assume one other fan is shutdown for maintenance.

Design

Use 10% of the design capacity for condensers, 30% of the design capacity for coolers, applied over the surface area served by the two fans assumed to be shut down.

ç Loss of all fans

10% of design capacity for condensers, 30% of design capacity for coolers.

Remote if caused by mechanical failure of the fans. If caused by loss of electric power, the contingency may be a design contingency or a remote contingency, depending on how loss of electric power is defined. See Utility Failure as a Cause of Overpressure.

ç

Failure of one set of automatic or manual louvers in closed position

No residual cooling capacity over the affected surface area.

Design

ç

Failure of all automatic louvers in the closed position.

No residual cooling capacity over the affected surface area.

Remote

ç

Failure of all manual louvers in the closed position

This contingency need not be considered.

Not credible.

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7.

Internal equipment blockage by collapsed internals such as bed supports or outlet collectors, or by plugging of packed beds by coke, scale or catalyst fines may be treated as a remote contingency. Blockage of fractionating towers by collapsed trays need not be considered.

8.

Unless prohibited by local codes, the presence of a manual block valve in a single relief path for a vessel or group of vessels is acceptable only if all of the following conditions are satisfied: a.

The valve is car-sealed in the full open position (CSO) and painted a distinctive color (normally yellow).

b.

The block valves must be line size full port hand-operated ball, gate or plug valves

c.

If the block valve is a gate valve, it shall be installed with the stem oriented at or below the horizontal.

d.

In the event of accidental closure of the block valve the maximum pressure reached in the protected equipment does not exceed 1.5 times its MAWP or its proof test pressure, whichever is lower. This condition need not be satisfied in the case of CSO isolation valves at the inlet or outlet of a pressure relief device intended to allow removal of the pressure relief device for maintenance, since inadvertent closure of such a valve will not result in an immediate overpressure event, and closure of such valves is controlled by administrative procedures. For the same reason, this condition need not be satisfied in the case of CSO isolation valves installed in flare headers to allow isolation of individual branches during plant turnarounds.

For vessels where two or more parallel relief paths exist, see Item 16. 9.

Heat exchanger tube rupture or leakage shall be considered as a remote contingency. Overpressure protection of the low pressure side need not be provided if the proof test pressure of the low pressure side, including attached piping and interconnected equipment is equal to or greater than the design pressure of the high pressure side. If this condition is not satisfied, overpressure protection may be required unless it can be shown that the relief capacity through the piping and equipment connected to the low pressure side is sufficient to prevent the pressure in the low pressure side from exceeding the proof test pressure.

10. Liquid overfilling of vessels as a source of overpressure shall be considered a design contingency unless both of the following conditions are satisfied: a.

Vessel is equipped with a safety critical, independent high-level alarm.

b.

The liquid hold-up above the high level alarm is sufficient to provide a minimum of 30 minutes operator response time after activation of the alarm before an overpressure condition develops. The hold-up time is calculated assuming liquid continues to enter at its maximum expected flow rate with no liquid outflow.

When both of these conditions are satisfied, liquid overfill is considered a remote contingency. If in addition to satisfying the above conditions, the vessel is equipped with a safety critical, independent high-level cut-out that will shut down all the liquid feeds into the vessel, then liquid overfill need not be considered as a potential source of overpressure (principle of not designing for double contingencies takes precedence over principle of not relying upon instrumentation to prevent overpressure). For this criterion to apply, it is necessary that the high-level cut-out be independent of both the process control level instrumentation and the safety critical, independent highlevel alarm and that there be no common cause failure mode that could lead to the simultaneous loss of both the safety critical high-level alarm and the safety critical high-level cutout. In addition, the Safety Integrity Level (SIL) of the system as a whole must be 3 or higher.

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11. Equipment must be protected against potential overpressure caused by reverse flow through check valves. The following scenarios shall be considered. Scenario No.

Number of Check Valves in Series

1

1

Potential Overpressure Scenario Partial failure of check valve.

Type of Contingency Design

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

1

Total failure of check valve.

Remote

Calculate reverse flow rate (liquid and/or vapor) as if the check valve were not there. 3

2 or more

Partial failure of one check valve.

Design

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. 4

2 or more

Total failure of one check valve.

Remote

Failed check valve is ignored. If only two check valves in series are installed, assume the second check valve fails partially open and calculate back flow per Scenario 1. If more than two check valves in series are installed, assume that each of the remaining check valves behaves as a restriction orifice with a diameter equal to 1/10 of the nominal diameter of the check valve. 5

2 or more

Two or more check valves in series fail fully open.

Not credible.

This contingency need not be considered.

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12. Check valves in a pressure relief path are acceptable as long as they meet all of the following conditions: 1. 2. 3.

The valve opens in the pressure relieving direction. The check valve is in a normally flowing line (i.e., normally open). The valve is of the swing-check or wafer (where acceptable per GP 03-12-01) type with no external actuation or damper mechanism.

4.

The pressure drop is included in the system analysis

13. Flow meter orifice plates are permissible in a pressure relief path, except PR valve inlets, outlets or flare headers, provided that the required relief flow can be passed without exceeding the upstream MAWP plus the applicable accumulation (if any) permitted by the design Code. 14. Flame arrestors and detonation arrestors are not permitted in a pressure relief path. 15. Demisting screens (typically, crinkled wire mesh screens) are permitted in a pressure relief path as long as the following conditions are satisfied: a.

Service is non-plugging

b.

Screen is secured in accordance with GP 05-02-01 to minimize risk of dislodgment.

16. When two or more parallel flow paths exist between the protected equipment and the pressure relief device, and one or more of the flow paths can be individually blocked, credit may be taken for the capacity of the remaining open flow path(s) for overpressure protection. The following guidelines apply: a.

If blocking one of the parallel flow paths causes the equipment pressure to exceed 1.5 times the MAWP or the proof test pressure, whichever is lower, either the block valves shall be removed or a pressure relief valve shall be provided to protect the equipment.

b.

If blocking two parallel flow paths causes the equipment pressure to exceed 1.5 times the MAWP or the proof test pressure, whichever is lower, either the block valves shall be removed or a pressure relief valve shall be provided to protect the equipment. This guideline recognizes that any two parallel paths could be blocked simultaneously due to operator error. For example, an operator could mistakenly block the inlets and/or outlets of two parallel paths instead of the inlet and outlet of one path, or block an open path before opening a previously isolated path.

c.

If neither condition (a or b) applies, two options are available: 1.

The inlets and outlets of all of the parallel flow paths shall have their isolation block valves car-sealed open (CSO), OR

2.

Determine the minimum number of parallel flow paths, N, that must remain open to prevent the protected equipment pressure from exceeding its MAWP, and car-seal open the isolation block valves of N+1 paths. If this option is selected, there must be a safety critical written procedure or mechanical interlocks to ensure that at least N+1 parallel paths have their isolation valves CSO at all times

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17. Maximum allowable accumulation for all design contingencies shall be as follows unless local codes specify otherwise: Vessel Type

Type of Contingency

No. of PR Valves in Parallel

Allowable Accumulation,

Any

Any

6

Design (except fire)

1

10 or 3 psi (20.7 kPa) (whichever is greater)

Fired boiler

% of MAWP

(ASME Section I) ç

Unfired Pressure Vessel (ASME Section VIII)

2 or more

16 or 4 psi (27.6 kPa) (whichever is greater Fire ç

Any

21

For equipment designed to codes other than ASME Sections I or VIII, consult EMRE’s Mechanical Engineering Section.

18. The maximum superimposed back pressure for non-discharging PR valves during a maximum system release (from either single or multiple valve releases under a design contingency) shall be as follows: For spring-loaded, conventional PR valves: Psi(max.) = 0.826 C Ps - Pd For balanced bellows and pilot operated valves: Psi(max.) = 0.50 C Ps Where: Psi(max.) = Maximum superimposed back pressure Pset = Pressure relief valve set pressure Pd = Differential spring pressure C = Multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01, dimensionless

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19. For a design contingency (including fire), the built-up back pressure for conventional spring-loaded pressure relief valves shall not exceed the following: ç

Vessel Type

Type of Contingency

No. of PR Valves in Parallel

Allowable Built-Up Back Pressure, % of MAWP

Fired boiler

Any

Any

6

Design (except fire)

1

10 or 3 psi (20.7 kPa) (whichever is greater)

(ASME Section I) ç

Unfired Pressure Vessel (ASME Section VIII)

2 or more

16 or 4 psi (27.6 kPa) (whichever is greater Fire

Any

21

For a remote contingency, the maximum allowable built-up back pressure for conventional spring-loaded pressure relief valves shall be: Pb(max.) = 0.173 C Pset Where: Pb(max.) = Maximum built-up back pressure Pset = PRV set pressure C = Multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01, dimensionless 20. For a design contingency (including fire),the total back pressure for balanced bellows pressure relief valves shall not exceed 50% of set pressure. For total back pressures in excess of 30% of set pressure for valves in vapor service or 15% of set pressure for valves in liquid service, a back pressure correction factor shall be applied as recommended by the manufacturer or as obtained from Figure III-2B or Figure III-4. For pilot operated PR valves, the total back pressure shall not exceed 75% of set pressure. For a remote contingency, the maximum allowable total back pressure for balanced bellows and pilot operated pressure relief valves shall be: Pb(max.) = 0.50 C Pset Where: Pb(max.) = Maximum built-up back pressure Pset = PRV set pressure C = Multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01, dimensionless The back pressure correction factor for balanced bellows pressure relief valves for a remote contingency may be obtained from Figure III-2B or Figure III-4 using the effective set pressure in place of the set pressure in the calculation of % Gauge Back Pressure. The effective set pressure is defined as follows: Pse = C Pset / (1 + Allowable Accumulation, %) Where: Pse = Eeffective set pressure

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Pset = Actual set pressure C = Multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01, dimensionless ç

21. The maximum allowable frictional pressure drop between the protected equipment and the pressure relief valve inlet flange is 3% of set pressure for set pressures equal to or greater than 50 psig(345 kPa gauge) and 5%of set pressure for set pressures less than 50 psig (345 kPa gauge) for all design contingencies including fire. For remote contingencies, the maximum allowable frictional pressure drop between the protected equipment and the pressure relief valve inlet flange is 4% of set pressure for set pressures 50 psig (345 kPag) or higher and 7% for set pressures lower than 50 psig (345 kPag).. The pressure drop limitations include only frictional losses and do not include static head or the effects of fluid acceleration. 22. The inlet and outlet frictional pressure drops for individual PR valves shall be calculated using the PR valve rated capacity for releases that are partially or totally vapor at PR valve inlet conditions except for fire contingency. For releases that are 100% liquid at PR valve inlet conditions and for fire contingencies, the PR valve design capacity may be used to calculate inlet and outlet piping frictional pressure drops. 23. Frictional pressure drop in closed PR valve discharge collection systems that collect the discharge from two or more PR valves shall be calculated using the sum of the design capacities for all the PR valves that discharge simultaneously for the contingency under consideration. 24. The maximum permissible flow velocity at any point of the PR valve discharge piping is 75% of sonic velocity, regardless of whether the PR valve discharges to atmosphere or to a closed system. Flow velocity is calculated at the design capacity of the PR valve. 25. The minimum permissible exit velocity for the atmospheric discharge of flammable vapors is 100 ft/sec at 25% of the rated capacity of the PR valve or at the minimum anticipated relief load, whichever is greater. If this criterion cannot be met with a single PR valve installation, consideration should be given to specifying two or more PR valves with individual discharge risers and staggered set pressures, or dispersion calculations should be done to verify that a flammable mixture will not be present at potential sources of ignition downwind from the point of discharge. 26. Calculation of relief rates for fire The wetted surface used to determine the heat absorption will be calculated according to API 521, with the following additions: a. For horizontal vessels any wetted surface located above 25 ft (7.5 m) but below the vessel centerline will be added to the area used. b. For vertical vessels located entirely above 25 ft (7.5 m), only the area of the bottom head will be used. If the vessel is supported by a full skirt extending all the way to the ground and the skirt has no more than one opening which does not exceed 20” (500 mm) diameter, the area of the bottom head may be excluded regardless of its elevation above grade. c. In all cases, the expanded volume of the liquid should be used. The expanded volume of the liquid includes the thermal expansion of the liquid from its initial temperature to its boiling point at the accumulated pressure of the vessel. d. For air cooled exchangers, see APPENDIX 1. Fire Risk Areas are established by the provision of access ways or clear spacing at least 20 ft (6.1 m) wide on all sides with drainage to catch basins located within the fire risk area. They are used to determine the combined requirement for pressure relief due to fire exposure. The selection of single fire risk areas within a plant or unit must consider the design of the drainage system and the equipment layout. These should be selected to limit the extent of 2 2 the fire risk area to no more than 5000 ft (500 m ). However, the extent of the fire risk area must be based on the 2 actual drainage pattern and the actual spacing that is available and may result in areas greater than 5000 ft (500 2 m ).

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5 BASIC DESIGN CONSIDERATIONS This section discusses the principal causes of overpressure in refinery and chemical plant equipment and describes design procedures for minimizing the effects of these causes. Overpressure is the result of an unbalance or disruption of the normal flows of material and energy that cause material or energy, or both, to build up in some part of the system. Analysis of the causes and magnitudes of overpressure is therefore a special and complex study of material and energy balances in a process system. Although efforts have been made to cover all major circumstances, the designer is cautioned not to consider the conditions described as the only causes of overpressure. Any circumstance that reasonably constitutes a hazard under the prevailing conditions for a system should be considered in the design. Overheating above design temperature may also result in overpressure, due to the reduction in allowable stress. A pressure relief valve cannot protect against this type of contingency. Thus, to provide some degree of protection, safety critical instrumentation, depressuring and fireproofing should be considered. Reference should be made to the section on chemical reactions. 5.1

CONTINGENCY BASIS FOR DESIGN

The cost of providing facilities to relieve all possible abnormal situations simultaneously would be prohibitive. Every abnormal situation arises from a specific cause or contingency. The simultaneous occurrence of two or more abnormal situations, or contingencies (i.e., a double contingency) is unlikely. Hence, generally an abnormal situation which can arise only from two or more unrelated contingencies (e.g., the simultaneous failure of both a control valve in the open position and cooling water, or the failure of an exchanger tube at the same time a control valve fails closed) is normally not considered for sizing safety equipment. Contingencies, including external fire, are considered as unrelated if there is no process, mechanical, or electrical inter-relationship between them, or if the length of time elapsing between possible successive occurrences of these contingencies is sufficient to separate their effects. Every unit or piece of equipment must be studied individually and every contingency must be evaluated. The safety equipment for an individual unit is sized to handle the largest load resulting from all possible design contingencies. When analyzing any contingency, one must consider all directly related effects which may occur from that contingency. For example, should an air failure also cause a control valve in a cooling circuit to close, then both the air failure and the loss of cooling in that circuit are considered as part of the same contingency. Likewise, if a certain abnormal situation would involve more than one unit, then all affected units must be considered together. An example of this is the use of a stream from one unit to provide cooling in a second unit. Loss of power in the first unit would result in loss of this cooling in the second unit, and thus must be considered as part of the same contingency. In analyzing the system to identify all design contingencies that may occur and the resulting relief requirements (and overpressure protection system design), no credit may be taken for operator intervention in preventing a potential overpressure incident. However, operator intervention may be relied upon to classify a liquid overfill scenario as a remote contingency as described under LIQUID OVERFILL AS A CAUSE OF OVERPRESSURE. No credit may be taken for the actions of process control or safety critical instrumentation other than High Integrity Protective Systems (HIPS) as the final protection layer in preventing a potential overpressure incident. Credit for safety critical instrumentation may be taken, however, in reducing the demand rate to a pressure relief device provided as the final protection layer, as described in the following paragraph. Safety Critical Instruments (other than HIPS) meeting the requirements of GP 15-07-02, Protective Systems may be considered in the design of certain components of the relief system, such as the flare collection header, blowdown drum, seal drum and flare tip, as a means to reduce the simultaneous load to the flare in a contingency involving multiple pressure relief devices as described in APPENDIX 2. However, credit may not be taken for safety critical instruments (other than HIPS) in determining the need for or the required relief capacity of individual pressure relief devices. When taking credit for HIPS or safety critical instrument systems as described in the preceding paragraph, the designer must confirm that the dynamic response of the system as a whole, including sensing elements, transmitters control valves and the protected system as a whole (vessels, heat exchangers, fired heaters, piping, etc.) is adequate to prevent the protected system pressure from reaching the relief device set pressure. Where warranted, a rigorous dynamic simulation of the system as described in APPENDIX 2 should be performed. Unless a rigorous dynamic

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simulation shows otherwise, it shall be assumed that the residual heat input from fired heaters following activation of the main fuel cut-out is 10% of the design heat duty. The equipment judged to be involved in any one emergency is termed a “single risk." The single risk which results in the largest load on the safety facilities in any system is termed the “largest single risk" and forms the design basis for the common collection system, such as the flare header, blowdown drum and flare. The emergency which results in the largest single risk on the overall basis may be different from the emergency which forms the basis for each individual piece of equipment. While generally only a design contingency is considered for design purposes, there may be situations where two or more simultaneous contingencies should be taken into account, e.g., if there is some remote interrelationship between them, and pressures or temperatures developed could result in catastrophic failure. Such remote contingencies are also considered, but the “1.5 Times Design Pressure" rule may be applied in this situation. (See the discussion of this rule under DESIGN PROCEDURE, PART I.) Overpressure which may occur at normal or below normal pressures, as a result of reduced allowable stresses at higher than design temperatures, are also evaluated and appropriate protective features applied in the design. For example, such conditions may result from chemical reactions, startup or upset conditions. Likewise, low metal temperature must be considered, such as from autorefrigeration, to make sure that brittle fracture conditions do not develop. 5.2

APPLICATION OF CODES AND STATUTORY REGULATIONS

The basis for design overpressure described in this section is related to the ASME Boiler and Pressure Vessel Code and ANSI B31.3, Code for Petroleum Refinery Piping. Compliance with these codes is a requirement, or is recognized as the equivalent of a requirement in many locations. In the United States, the ASME Code is now mandatory since it is a requirement under the Occupational Safety and Health Act. Where more stringent codes apply, the local requirements must be met. Therefore, local codes must be checked to determine their requirements. For example, some countries do not permit the use of block valves underneath pressure relief valves, unless dual valves with interlocks are installed. Also, in some cases, 21% accumulation under fire exposure conditions is not permitted, and accumulation allowed may be lower than the ASME Code (for example no increased accumulation when multiple PR valves are used). The affiliate for which the design is intended is usually the best source of information on local codes. 5.3

SUMMARY OF PRESSURE RELIEF DESIGN PROCEDURE

The essential steps in the design of protection against overpressure which are covered in detail in other parts of this section are summarized below: 5.3.1 1)

2) ç

3)

Consideration of Contingencies

All contingencies which may result in equipment overpressure are considered, including external fire exposure of equipment, utility failure, equipment failures and malfunctions, abnormal processing conditions, thermal expansion, startup and shutdown, and operator error. For each contingency, the resulting overpressure is evaluated and the need for appropriately increased design pressure (to withstand the emergency pressure) or pressure-relieving facilities to prevent overpressure (with calculated relieving rates) is established. Also, see DP II. If a contingency consequence is indeterminate (e.g. compressor may or may not trip, or operators may or may not intervene), each possibility should be analyzed and the relief flow determined for the worse case.

5.3.2

Selection of Pressure Relief Device

From the range of available pressure relief valves and other devices, selection is made of the appropriate type for each item of equipment subject to overpressure. Instrumentation, check valves, and similar devices are generally not acceptable as means of overpressure protection.

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5.3.3

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Pressure Relief Device Specification

Standard calculation procedures are applied to determine the size of the pressure relief device (usually a pressure relief valve) required for the maximum relieving rate, together with other information necessary to specify the device. 5.3.4

Design of Pressure Relief Device Installation

Finally, the pressure relief device installation is designed in detail, including location, sizing of inlet and outlet piping, valving and drainage, selection of open or closed discharge, and design of closed discharge system to a flare or other location. 5.3.5

Summation and Documentation of Contingencies

The Design Specification should include a tabulation of all major contingencies considered, together with their relief requirements. Such a tabulation is helpful to assure that all contingencies have been considered and for selecting the contingency which sets the design of the collection system. It is also necessary and invaluable for future analysis of the overpressure protection system. An example of a tabulation sheet is included as Table I-1. S

6 DESIGN PROCEDURE, PART I: CONSIDERATION OF CONTINGENCIES AND DETERMINATION OF RELIEVING RATES

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6.1

INTRODUCTION

The first step in the design of protection against overpressure is to consider all contingencies which may cause overpressure, and to evaluate them in terms of the pressures generated and/or the rates at which fluids must be relieved. ç

All unfired pressure vessels designed to the ASME Code Section VIII must be protected by pressure relieving devices that will prevent accumulation (of excessive pressure) within the vessel exceeding 10% of the design pressure or 3 psi (20.7 kPa), whichever is greater, (16% or 4 psi (27.6 kPa), whichever is greater, if multiple PR devices are used) unless the design pressure of the vessel equals or exceeds the maximum pressure that could be developed. When the excess pressure is caused by an external fire, 21% accumulation is permitted (if allowed by local codes). Fired pressure vessels are covered by the ASME Code Section I (Power Boilers), which requires pressure relief devices to prevent accumulation exceeding 6%. The following unfired steam generators are considered as unfired pressure vessels, and maximum accumulation should be specified in accordance with the ASME Code, Section VIII (unless prohibited by local codes). 1) Evaporators and heat exchangers in which steam is generated. 2) Vessels, e.g., waste heat boilers, in which steam is generated incidental to the operation of a processing system containing a number of pressure vessels, such as are used in chemical and petroleum products manufacture. (Equipment which may fire a supplemental fuel should be considered as a fired pressure vessel.) The design contingency basis for these considerations, as well as a means for tabulating and documenting the various contingencies considered, is described under BASIC DESIGN CONSIDERATIONS. The types of contingencies which should be considered, together with guidelines for evaluating them, are detailed in the remainder of this part of DESIGN PROCEDURE, PART I. Selection of design pressure for equipment is covered in DP II, Design Temperature, Design Pressure and Flange Rating. Design for overpressure protection in most cases consists of providing pressure relief devices sized to handle the calculated relieving rates necessary to prevent emergency pressures from rising above the design pressure (plus allowable accumulation). As an alternative means of protection, it is economical in some cases to specify an increased equipment design pressure which will withstand the maximum pressure that can be generated, without relieving any contained fluids. Also, in some cases, the cost of the collection system can be reduced by specifying higher design pressures which will permit a higher back pressure in the collection system. See DP II. For remote contingencies, the “1.5 Times Design Pressure Rule" is applicable.

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"1.5 Times Design Pressure Rule" - The additional load caused by the remote contingency (to which the "1.5 Times Design Pressure Rule" is applied) need not be considered in calculations of flare and PR valve radiant heat levels. For situations where the relief area calculated for the remote contingency on the basis of the "1.5 Times Design Pressure Rule" exceeds the relief area calculated for the limiting design contingency, or when the remote contingency is the only overpressure scenario applicable to a pressure relief valve, the required PR valve relief area should be set equal to the relief area calculated for the remote contingency based on applying the 1.5 Times Design Pressure Rule. The relief flow rate reported in the specification sheet should be set equal to the calculated capacity of a pressure relief valve having an effective relief area equal to the required relief area calculated above at the Code allowable accumulation. ç

In addition, since the intent is to keep the vessel pressure no higher than the proof test pressure, the pressure drop between the vessel and the location of the PR valve (including inlet line losses) must be taken into account. For some equipment, the "1.5 Times Design Pressure Rule" may not apply. The yield stress must be reviewed based on the actual condition (physical and operational) of the equipment. See the paragraph entitled Overpressure Caused by Abnormal Temperature for additional information on this topic. Examples where the "1.5 Times Design Pressure Rule" may apply (i.e., normally considered remote contingencies) are: 1) Contingencies which have some remote interrelationship and which could develop pressures or temperatures sufficient to cause catastrophic failure, or result in a large release of toxic or light hydrocarbon material. 2) Abnormal events, such as: a. Heat exchanger tube failure. b. Inadvertent closure of a CSO valve except for CSO valves used to isolate pressure relief devices for maintenance or to isolate individual branches in flare systems for which accidental closure is considered non-credible. c. Inadvertent opening of a CSC valve. d. Plugging of a fixed bed reactor catalyst bed (some local codes consider catalyst bed plugging as a contingency that requires normal pressure relief valve protection). e. Collapse of reactor outlet collector causing total obstruction of flow. f. Installation of a rupture disc upside down. g. A control valve failing open with its bypass fully open.

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6.2

FIRE AS A CAUSE OF OVERPRESSURE

Equipment in a plant area handling flammable or combustible fluids is subject to potential exposure from an external fire, which may lead to overpressure resulting from vaporization of contained liquids. This hazard may exist even in items of equipment containing nonflammable materials. 6.2.1

Equipment to be Protected

All vessels must be protected from overpressure. In addition, all vessels subject to overpressure by fire must be protected by PR valves, with the following exceptions: 1.

If allowed by the applicable pressure vessel code, fire may be excluded as a contingency for PR device sizing for a vessel which normally contains no liquid, since failure of the shell from overheating would probably occur even if a PR valve were provided. Examples are fuel gas knockout drums and compressor suction knockout drums where a liquid level is not maintained. Some jurisdictions require pressure relief valve protection for “dry drum" situations. If a PR valve is required (or desired) for “dry drum" conditions, the sizing procedure contained in APPENDIX 1 may be used. However, it should be recognized that a pressure relief valve will only prevent the pressure from rising above the allowable accumulation and will not necessarily prevent (although it may delay) vessel failure due to overheating. In these cases, consideration should be given to the use of non-reclosing devices such as a rupture pin valve, rupture disc or fusible plug, since such devices will depressure the vessel upon actuation and reduce the risk of vessel failure due to overheating. Refer to APPENDIX 1 for additional information on protecting dry vessels against overpressure due to external fire.

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3.

4.

5.

6.

7.

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Typically, drums and towers 2 ft (.6 m) and less in diameter, constructed of pipe, pipe fittings or equivalent, do not require PR valves for protection against fire, unless these are stamped as coded vessels. This exception is based on the fact that piping is not provided with protection against overpressure from this contingency. PR valves are required on such vessels, however, if overpressure can result from contingencies other than fire. Interconnected vessels may be treated as one unit for pressure relief purposes during a fire (and also other contingencies) if the piping and valving between them meet applicable criteria as described in this Design Procedure. Except for special situations, (or unless required by local codes) pressure relief devices are not individually provided for fire exposure of piping. Special situations which may require individual pressure relief device include congestion and substandard spacing, or unusually large equipment with normal liquid holdup over 1,000 gallons (4 m3) or which represents over 15% of the total wetted surface of the system to which it is directly connected for pressure relief. Fire exposure overpressure protection for filters: Filters are typically designed to be blocked off from the process flow for periods of time and remain filled with liquid. Therefore, filters that can be blocked off should be provided with PR valves to protect them against fire exposure unless the filter falls in either of the following categories: 1) the filter is made of pipe sections 24 in. (0.6 m) or less in diameter, or 2) the filter contains a non-flammable fluid, is not located within the diked area of a tank, and is located at least 20 ft (6 m) in all directions from all sources of hydrocarbon or potential fire locations. The piping exception is a result of the ANSI code not requiring protection for piping (and by extension of equipment made from piping sections) and accessories such as strainers. Note that filters made of low melting alloys require special consideration since they require additional protection, such as fireproofing. Fire exposure overpressure protection for heat exchangers: In general, heat exchangers do not need a separate PR valve for protection against fire exposure since they are usually protected by PR valves in interconnected equipment or have an open escape path to atmosphere via a cooling tower or tankage. This is true even if the heat exchanger has a manual block valve between it and the PR valve since it is not expected that this valve will be closed by operators during a fire incident. However, in situations where a fail-close control valve or an EBV could isolate the heat exchanger from the PR valve providing protection against fire exposure, a separate PR valve to protect the exchanger may be required. Although experience shows that the usual consequence of such a scenario is relatively benign and is typically limited to a relatively small leak related to gasket failure, each situation should be assessed individually to determine whether or not a pressure relief valve is required to manage the risk. The risk assessment should consider, among other things, the requirements of local codes, the mechanical design features of the exchanger, the volume, toxicity and flammability of the contained fluid and the likely consequence (minor leak or catastrophic breach of the pressure containing envelope). In the absence of a favorable risk assessment, a pressure relief valve should be provided. 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 PR valves 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" during the period of time it is isolated from the PR valve that would normally provide protection. To increase the probability that this operating procedure is followed, a caution sign in accordance with GP 03-02-04 shall be permanently placed at the block valves of all exchangers not equipped with a permanently open bypass. Fire exposure overpressure protection for air-cooled exchangers is discussed in APPENDIX 1. Another special situation involves vessels filled with both a liquid and a solid (such as molecular sieves or catalysts). In this case, the behavior of the vessel contents normally precludes the cooling effect of liquid boiling. Hence rupture discs, fireproofing and depressuring should be considered as alternatives to protection by PR valves.

6.2.2

Determination of Relieving Rate and Risk Area

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 covered in APPENDIX 1. For determining PR valve 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

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generated by normal process heat input on compression, etc., are not considered. No credit is taken for any escape path for fire load vapors other than through the PR valve (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. In order 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. See DEFINITIONS for definition of a fire risk area. Plant layout should be designed in accordance with the spacing standards (see DP XV-G) and must include accessibility for fire fighting. The fire risk areas for the purpose of overpressure protection are established by the provision of accessways or clear spacing at least 20 ft (6.1 m) wide on all sides, which permit fire fighting attack into all parts of the area and which limit the spread of fire. Clear space under pipebands, if more than 20 ft (6.1 m) wide, is considered as acceptable separation between fire risk areas. The selection of single fire risk areas within a plant or unit must, in addition, consider the design of the drainage system and the equipment layout. When a fire occurs, it is assumed that all fluid flow to and from the fire risk area has been stopped and that major machinery within the fire risk area, such as compressor fitted with remote shutdown facilities, are stopped. Credit is not generally given to flow out of the normal process channels, since they are also generally closed during the emergency. The total fire load is calculated for each fire risk area and used in the determination of the largest single risk release. Where the size of a closed discharge header is set by the fire relieving capacity requirement, advantage may be taken of reducing the requirement by providing fireproofing or insulation on vessels with large liquid inventories, as described in DP XV-H and covered by APPENDIX 1. If a situation occurs which involves more than one fire risk area simultaneously (such as an entire Refinery or Chemical complex), it would be classed as a remote contingency event, and the "1.5 Time Design Pressure Rule" may be applied. See DESIGN PROCEDURE, PART I, INTRODUCTION. 6.2.3

Protection of Vessels from Fire Exposure, in Addition to Pressure Relief

Pressure relief valves cannot protect a vessel that becomes locally overheated on an unwetted surface, although they do prevent the pressure from rising beyond accumulation pressure. However, in such a case the vessel may be effectively protected against failure by either one of two methods for mitigating the effect of fire: 1. The Reduction of Pressure by Depressuring - The reduction of pressure in a vessel exposed to fire has the advantages of not only reducing the metal stress to a value that will not result in failure, but also of reducing markedly the quantity of fuel that might feed the fire should failure occur. This depressuring can be achieved by use of rupture discs or instrumented emergency depressuring (vapor blowdown) systems (described in DP XV-F). When over pressure protection is only required because of fire exposure, rupture discs should be considered. 2. An Effective Limitation of the Heat Input - Application of firewater from fixed and mobile fire fighting facilities is the primary method of cooling equipment which is exposed to fire. These facilities are described in DP XV-I. Further protection by fixed water deluge or spray systems, or fireproofing, is applied in areas of particularly high fire risk, as described in DP XV-I and XV-H, respectively. However, in sizing PR valves, no credit is taken for reduced heat input due to application of cooling water, since it cannot be considered 100% effective in all fire conditions. S

6.3

UTILITY FAILURE AS A CAUSE OF OVERPRESSURE

6.3.1

General Considerations

Failure of the utility supplies (e.g., electric power, cooling water, steam, instrument air or instrument power, or fuel) to refinery plant facilities will in many instances result in emergency conditions with potential for overpressuring equipment. Although utility supply systems are designed for reliability by the appropriate selection of multiple generation and distribution systems, spare equipment, backup systems, etc., the possibility of failure still remains. Possible failure mechanisms of each utility must, therefore, be examined and evaluated to determine the associated requirements for overpressure protection. The basic rules for these considerations are as follows:

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2.

3.

4.

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Interruptions of utility supply are considered only on a design contingency basis, i.e., corresponding to a failure of a single component of the generation or distribution system of one utility. Consideration must, however, be given to the direct effect of one utility on another. If a supply failure in one utility system, as a result of a design contingency, results in a complete or partial loss of another inter-related utility, then the dual failure must be considered. For example, in a plant where electricity is generated by steam turbine generators, loss of steam production will cause direct loss of power. Failure is considered both on a local basis, i.e., loss of utility supply to one item of equipment (e.g., electric power to a pump motor) and on a general basis, i.e., loss of supply to all consuming equipment in a process unit if it can occur as a result of a design contingency (e.g., cooling water to all coolers and condensers). For the purpose of these pressure relief design considerations, a process unit is defined as one which meets all the following criteria: a. It is segregated within its own clearly identifiable battery limits boundary. b. It is supplied with each utility through one or two independent laterals from an offsite header. c. It constitutes a complete processing function. For a process unit with its own segregated and self-contained closed PR discharge system, only a utility failure to that unit need be considered for the purpose of sizing the safety facilities. However, when two or more units share a closed disposal system (e.g., a common blowdown drum and/or flare), the design procedure must include consideration of the potential for a design contingency resulting in utility supply failures to more than one of the units. Although such refinery-wide or plant-wide utility failures are not always used as a basis for sizing the safety facilities, they must be evaluated. This entails the evaluation of reliability of generation and distribution systems and requires good engineering design and the inclusion of adequate backup features. Examples of such backup features are included in the discussion of each utility contingency. In designs where all pressure relief valves discharge into a closed collection system, because of environmental restrictions, a total failure of one utility deserves more careful consideration since there are no atmospheric releases which would tend to relieve the load on the closed system. Evaluation of the effects of overpressure attributable to the loss of a particular utility supply must include the chain of developments that could occur and the reaction time involved. In situations where fluid flow stops due to failure of its utility supply, but is in parallel with equipment having a different energy source, credit may be taken for the unaffected and functioning equipment to the extent that operation is maintained and the operating equipment will not trip out due to overloading. 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 which have two unrelated sources of energy to the drivers. Backup systems which depend upon the action of automatic cut-in devices (e.g., a turbine-driven standby spare for a motor-driven cooling water pump, with PLCI control) would not be considered an acceptable means of preventing a utility failure for normal pressure relief design purposes, even though their installation is fully justified by improved continuity and reliability of plant operations.

UTILITY FAILURE CONTINGENCIES TO BE CONSIDERED The application of the above design considerations to the major utility systems for typical installations is described below. In some cases, the loss of utility supply is not a direct cause of overpressure, but it initiates a plant upset or emergency (e.g., power failure leading to loss of tower reflux), which in turn may result in overpressure. Where necessary, reference should be made to the procedures for evaluating such upset or emergency situations and for determination of relieving rates, described later in this section. 6.3.2

Electric Power

1. Normal Individual and Process Unit Basis for PR Sizing Considerations - The following design contingencies should be considered as the basis for evaluating overpressure that can result from electric power failures: a. Individual failure of power supply to any one item of consuming equipment, such as a motor driver for a pump, fan or compressor.

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b. c.

Total failure of power to all consuming equipment in a process unit supplied by a unit substation. 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 for the design contingency to assume that normally closed circuit breakers will function; while for the remote contingency assume that the first normally closed circuit breaker fails to isolate the fault and it extends to the adjacent bus bar. 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; while the remote contingency would be the loss of the affected bus bar plus the adjacent bus bar assuming that one of the circuit breakers fails to function on time and the fault extends. If in the example above, the substation was 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 which results in the highest release rate should be used as the design basis for this contingency. Alternatively, the design specification must 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 system, such as a blowdown or 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 as long as the worst case (100% of the load for the worst combination of equipment loss) is the basis for design as a remote contingency to which the “1.5 Times Design Pressure Rule" is applied. 2. Consideration of Plant-wide or Refinery-wide Power Failure - The following general power failures on a plantwide scale must be considered. a. Failure of purchased power supply to the plant or refinery. b. Failure of internally generated power supply to the plant or refinery. c. Total power failure in any one major substation. (Usually considered a remote contingency to which "1.5 Times Design Pressure Rule" is applied.) As discussed under General Considerations above, adequate backup features must be included to reduce the probability of such major failures to an acceptably low level and balanced against the consequences, should such failures occur. The following backup arrangements are normally required as a minimum: 1. Two or more feeders for purchased power. 2. Two or more parallel generators with a spare backup where power is generated in the plant or refinery. 3. More than one fuel to boilers generating steam for turbine generators. 4. Automatic load shedding arrangements to maintain supply preferentially to critical consumers. 5. Secondary selective power distribution systems. (In these systems, the substations used have two busses, each supplied by a normally-closed incoming line circuit breaker and connected together by a normally-open bus tie circuit breaker. The dual sources normally divide the load in non-parallel operation. Upon failure of one source, the substation is isolated from the failed source and the de-energized bus section is connected to the source remaining in service. This “transfer" of load should be automatic and all motors connected to the bus bar must be provided with re-acceleration.)

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6.3.3 S

1.

2.

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Cooling Water

Normal Individual and Process Unit Basis for PR Sizing Considerations - The following design contingencies should 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 which can be valved off from the offsite main. Consideration of Plant-wide or Refinery-wide Failure - The following general cooling water failures must 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. c. Loss of all the fans on a cooling tower that would result from any design contingency in the utility systems supplying or controlling the fan drivers. In the case of partial loss of the cooling water system due to a design contingency, the cooling water will be lost earlier to elevated users, such as condensers. These users may contribute disproportionately more to the safety release than the users to which cooling water is still available. In this instance, the actual safety release will be somewhat greater than a release proportional to the quantity of cooling water lost but lower than total loss of cooling water. To evaluate this situation three options are available: 1. Assume that partial loss of cooling water, as a design contingency, results in the same safety release rate as total loss of cooling water. 2. Determine, based upon a detailed analysis of the system configuration, where cooling water will flow upon partial loss of water, and the resulting safety release rate from each piece of affected equipment. 3. Design for partial loss as a design contingency and total loss as a remote contingency if a significant portion of the plant PR valves discharge to a closed system, and option 1 results in an oversized closed system. When this design contingency becomes controlling (i.e., sets size of all or part of the closed system) an acceptance basis to reduce the size of the closed system is to design it assuming that partial loss of cooling water results in a safety release proportional to the amount of capacity lost. For example, loss of one-half of the cooling water capacity due to the loss of one-of-two 50% pumps results in a flare system load equal to one-half of the load caused by complete failure of the cooling water system. To balance this optimistic basis, the closed system must be designed in a manner somewhat more conservative than usual, as follows: a. Design for loss of cooling water causing a safety release proportional to the amount of loss as a design contingency. b. Design for total cooling water system failure as a remote contingency to which the "1.5 Times Design Pressure Rule" is applied to all PR valves blowing. c. Design the closed system such that other protected equipment not involved in the cooling water contingency cannot be overpressured by more than the "1.5 Times Design Pressure Rule," even during a total cooling water failure. d. Design each flare lateral to accommodate the largest possible release up to the total design release rate. Since it may be impractical to determine through which laterals the releases which make up the total are coming from, the design of flare laterals must presume that any one lateral could be at its maximum possible load up to the total design rate. For example consider a closed system consisting of two laterals, A and B. During a total cooling water system failure the PR valve releases add up to 140 klb/hr (18 kg/s) in Lateral A and 60 klb/hr (7.5 kg/s) in Lateral B, for a total load of 200 klb/hr (25 kg/s). To design for a partial loss of 50% of the cooling water system, the design release is one-half of the total or 100 klb/hr (12.5 kg/s). Lateral A is designed for its full release up to the design release or 100 klb/hr (12.5 kg/s). Similarly, Lateral B is designed for 60 klb/hr (7.5 kg/s) while the sections of closed system header downstream of the juncture of the two laterals is designed for 100 klb/hr (12.5 kg/s). These sizes would be compared to sizes developed from other contingencies to select actual lateral size.

As discussed under General Considerations above, adequate backup features must be included to reduce the likelihood of a major failure. As a minimum, all of the following should normally be provided:

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1. Multiple cooling water pumps with different type drivers and automatic cut-in of the spare pump. The motors must be designed to avoid overloading over the full range of the pump operating curve and as a result of the automatic cut-in. 2. Holdup in the sump of a cooling tower should be specified as per DP XXVII of the Design Practices. An independent low water level alarm set at the minimum holdup level should also be provided. This should provide sufficient warning so that corrective steps can be taken by operating personnel. Without such an alarm, makeup water failure may not be apparent. 3. Secondary selective power supply to cooling tower fan motors. 4. Adequate instrumentation and alarms to give warning of potential cooling water system failures, such as a low pressure alarm on the makeup cooling water supply header. The safety system load associated with the total loss of any of the independent systems could be considered under the remote contingency rules if the design complies with Items 1 through 4 above. Application of the following should also be considered, in appropriate cases: 1. Multiple cooling water systems to reduce the size of the releases in case of total system failure. For example, to reduce the impact of total cooling water loss, independent multiple cooling water systems could be provided. These independent systems would supply different sections of the plant. 2. Cross-connected or looped distribution headers, to gain the added spare capacity of multiple cooling water systems. S

6.3.4

S

Steam

1. Normal Individual and Process Unit Basis for PR Sizing Considerations - The following design contingencies should be considered as the basis for evaluating overpressure that can result from steam failures: a. Individual steam failure to any one item of consuming equipment (e.g., turbine drivers, reboilers, strippers, ejectors, etc.). b. Total failure of any one lateral supplying a process unit which can be valved off from the offsite main. 2. Consideration of Plant-wide or Refinery-wide Failures - The following general steam failures must be considered: a. Failure of any section of the offsite steam main. b. Loss of any one steam generator. c. Loss of purchased steam in any one supply line. As discussed in General Considerations above, the probability of these major failures must be reduced by backup features, such as the following: a. Multiple boilers with spare capacity fired by multiple fuels. b. Adequate control and alarm systems, automatic load shedding arrangements, etc. 6.3.5

Instrument Air

1. Normal Individual Process Unit Basis for PR Sizing Considerations - The following design contingencies should be considered as the basis for evaluating overpressure that can result from an instrument air failure: a. Loss of instrument air supply to any one individual control instrument or control valve. It is assumed that the correct air failure response occurs. In the case of “remain stationary" control valves, it is assumed that the drift action to the fully opened or closed position takes place. Failure of automatic controls is covered under EVALUATION OF OVERPRESSURE RESULTING FROM EMERGENCY CONDITIONS, AND DETERMINATION OF RELIEVING RATES later in this section. Note that these latter considerations include failure of any control valve to both the opened and the closed position. b. Loss of instrument air from a valved sub-header as well as total failure of any one valved lateral supplying a process unit from the offsite main: The correct air failure response of instruments and control valves is assumed. Consider “remain stationary" valves as drifting to either the fully opened or closed position, depending on the direction of the actuator. 2. Consideration of Plant-wide or Refinery-wide Failures - The following general instrument air failures must be considered:

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Failure of any section of the offsite instrument air main. Loss of flow through any one set of instrument air dryers.

As discussed under General Considerations above, the probability of these major failures must be reduced by appropriate backup features. Both of the following should be considered as minimum requirements: a. Multiple air compressors with different drivers and automatic cut-in of the spare machine. b. Spared instrument air drying capacity. S

6.3.6

Instrument Power

Instrument power failures are evaluated on a basis similar to that described for a power failure. Included in the considerations for PR sizing should be the failure of power supply to all instruments in and controlled from a single bus bar. Reliability features should include secondary selective power supply to control rooms, with emergency generator or battery backup for critical instruments and control computers. Critical controls should be able to continue operation independently of control computers. S

6.3.7

Fuel

Fuel supplies to boilers, fired heaters, gas turbine and engine drivers, etc., are designed with features such as multiple fuel gas sources, propane vaporizer backup, and a liquid fuel surge tank, to promote reliability. The failure of any one fuel to a process unit or utility generation facility is used as the basis for evaluating a potential overpressure. S

6.3.8

Other Utilities

Failure of other utilities, such as inert gas to seals and purge systems, or compressed air (when used by the process) may in some cases determine pressure relief requirements. These cases are evaluated on a design contingency failure basis similar to the above. S

6.4

S

EQUIPMENT MALFUNCTION AS A CAUSE OF OVERPRESSURE

In addition to utility supply failures, items of equipment are subject to individual failure through mechanical malfunction. Such items include pumps, fans, compressors, mixers, instruments and control valves. The process upset resulting from such malfunctions (e.g., loss of a reflux pump) may in turn result in emergency conditions and the potential for overpressure. These contingencies should be examined and evaluated as described under EVALUATION OF OVERPRESSURE RESULTING FROM EMERGENCY CONDITIONS, AND DETERMINATION OF RELIEVING RATES in this section. In applying these rules, credit can generally be taken for pressure and temperature conditions existing under relieving or accumulated pressure conditions. 6.5

PURGING / CLEANOUT

During air or hydrocarbon purging, or cleanout, facilities used for these purposes might subject the vessels to pressures beyond their design. Each operation should be individually evaluated for adequate pressure protection requirements. Utility connections using dropout spools, blinds, or double blocks with a check valve and bleed are used to prevent contamination from backing into the utilities and contaminating these systems. When utilities are hooked up to purge or flush operating equipment, care should be taken to prevent overpressure during the purging/cleanout operation. During purging or cleanout, the possibility of failure of any valve in the system that could overpressure equipment should be considered as a design contingency and dealt with appropriately, e.g., install a pressure relief valve to protect the system or uprate the design pressure of the equipment involved. However, if permanent blinding points or break-away connections and safety critical procedures are provided to avoid accidental overpressuring of equipment during purging or cleanout, maloperation of valves in utility hookups may not need to be considered in evaluating pressure relief facilities. The complexity of the procedures and the frequency of their use are important factors to be addressed in this analysis.

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S

6.6

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LIQUID OVERFILL AS A CAUSE OF OVERPRESSURE

PR valves 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 PR valve 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 extent of overfill possible may be limited by the upstream vessel inventory.

In determining the required relief capacity of the PR valve, 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 PR valve 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 safety valve because of the overfill contingency may be two phase flow, especially if the inlet flow normally contains vapor. In the event of two phase flow, the PR valve must be designed to relieve the vapor plus liquid, minus the flow available through remaining normally open outlets, unless a dedicated PR valve is installed to specifically handle the liquid. The overfill must be considered as a design contingency for PR valve sizing purposes UNLESS BOTH of the following are provided: 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 larger) holdup based on design liquid inlet rate and a stoppage of the liquid outflow. If the above are provided, the overfill contingency may be considered a remote contingency to which the “1.5 Times Design Pressure Rule" is applied 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 facility. 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) to protect against liquid overfill may be considered as an alternative (or in addition) to a pressure relief device. The intent of such a system is to render liquid overfill a double contingency, which need not be evaluated in the overpressure protection analysis. Two alternative architectures for such a system are suggested: 1.

Provide a safety critical, independent high-level alarm (LHA) located such that the vapor space above the LHA is equivalent to at least 30 minutes holdup based on design liquid inlet flow rate with zero liquid outflow (this makes liquid overfill a remote contingency) PLUS provide a safety critical, independent high-level cut-out (LHCO) on all incoming feeds including start up oil (this makes liquid overfill a double contingency), OR

2.

Provide a high-integrity, safety critical, independent high-level cut-out (LHCO) on all incoming feeds including start up oil.

Regardless of the architecture chosen, the overall availability of the protective system must be equivalent to Safety Integrity Level (SIL) 3 or better (99.9% or better) for the protective system to qualify as a HIPS. The selected system shall be designed, evaluated and installed in accordance with the criteria in EE.137E.95. These criteria include the need for redundancy, the need to consider the possibility of 10% leakage across the individual isolation valves and the need to confirm that simultaneous failure of the control system and the safety critical instrumentation

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cannot occur as a result of a common cause failure mode by including suitable safeguards as described under double or multiple contingencies. In addition, the dynamics of the HIPS must be evaluated to ensure that the set pressure of the PR 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 (as described above) 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 PR valve protecting the vessel. To account for possible isolation valve leakage, the PR valve 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 and/or LH(CO) as described in the preceding paragraphs is not necessary if either of the following conditions is met:

S

1.

The pressure relief valve protecting the vessel has sufficient capacity to handle a liquid overfill without exceeding the Code allowable accumulation (i.e. liquid overfill has been deemed a design contingency.) AND the pressure relief valve discharges to a closed system, OR

2.

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).

6.7

OPERATOR ERROR AS A CAUSE OF OVERPRESSURE

Operator or human error is considered a potential cause of overpressure. Contingencies of sabotage, gross negligence or incompetence are generally not considered. Gross negligence type items which generally are not included are: failure to install or remove blinds, bypassing of emergency devices, operating with closed block valves around pressure relief devices and misalignment of process flow during startup. While closing and opening of CSO and CSC valves in process streams could also be considered as gross negligence, these incidents are sufficiently severe that they must be considered, although the "1.5 Times Design Pressure Rule" may be applied in such cases. (Refer to the section on CSO valves under EVALUATION OF PRESSURIZATION PATH IN PRESSURE RELIEF DESIGN in this section.) S

6.8

EVALUATION OF OVERPRESSURE RESULTING FROM EMERGENCY CONDITIONS, AND DETERMINATION OF RELIEVING RATES

The following paragraphs describe a range of typical plant emergency situations which may result from utility failures, equipment malfunctions, or plant upsets, and which may result in equipment overpressure. Guidelines for the evaluation of these emergency conditions and determination of relieving rates are included. The relieving rates required for all valid contingencies for each PR device (and also other continuous or emergency releases into closed systems) must be documented as illustrated in Table I-1. 6.8.1

Failure of Automatic Control

Automatic control devices are generally actuated directly from the process or indirectly from a process variable (cascade), 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. Such “remain stationary" control valves will, however, drift in the direction in which the spring drives the valve and this drift must be considered if it results in a more conservative design. The failure of a process-measuring element in a transmitter or controller without coincidental failure of the operating power to the final controlled element should also be reviewed to determine the effect on the final controlled element. However, when examining a process system for overpressure potential, one should assume that any one automatic control device could be either open or closed, regardless of its fail-safe action under loss of its transmission signal or operating medium.

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When the control valve size is established by the designer, for example selecting a Cv, it is assumed that this size valve is installed. Credit for the limiting capacity of the control valve may be taken, refer to EVALUATION OF PRESSURIZATION PATH IN PRESSURE RELIEF DESIGN in this section. If the control valve size is later increased it will be necessary to recheck the PR valve relief considerations. ç

Distributed Control System (DCS) failures may induce PR valve relief rates greater than individual control output failures, and should be evaluated on a case-by-case basis, taking into account all identified hardware, firmware, and software fault conditions. 1. Instrument Air Failure or Power Failure Action - The response of the control valve to failure of the instrument air or power supply should be selected to minimize the hazards of the resulting emergency situation. Generally, this is achieved by specifying the closure (i.e., fail close) of control valves in sources of heat input, water drawoffs and feed and product streams. Boxing-in the plant equipment in this way, on the basis that any resulting overpressure is relieved by properly designed PR valves, is considered safer than the uncontrolled dumping of plant contents into tankage and other units. A control valve in a heating system should generally be set to fail closed, to eliminate heat input. However, a fired heater process inlet control valve, should generally be set to fail open, to prevent overheating the process coil(s). Likewise, heat integrated circuits need careful scrutiny to determine the effect of the loss of cooling or heating. For example, a closed circuit system which is used for both heating and cooling could result in increased heat input if the flow of the stream which removes heat should fail. 2. Control Valve System Analysis - To evaluate system relieving capacity requirements for any design contingency (other than failure of the utility which affects valve movement), such as opening or closing of a single valve or utility failure, it is assumed that all control valves in the system which open under the contingency under consideration, remain in the position required for normal processing flow. Therefore, credit may be taken for the minimum (turndown) normal capacity of these valves, corrected to relieving conditions, provided that the downstream system is capable of handling any increased flow. While some controllers may respond correctly by increasing valve openings, capacity credit should be taken only to the extent corresponding to their minimum (turndown) normal operating position. This will avoid subjective decisions involved in evaluating response times and effects of controller settings, such as proportional band, reset, and rate action. It is also compatible with the basic philosophy that instruments may not necessarily operate or may be in the manual mode at the time of the emergency. Should the valve close under the contingency considered, no credit should be taken for relief through this valve. 3. Failure of Individual Control Valve - The following individual control valve failures should be included 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 highpressure 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 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 mechanism 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. In all cases except for (3) below involving failure of a control valve in the wide open position, it is necessary to consider the effect on the relief rate of the bypass valve (if any) being partially open. This is in recognition of practical experience which indicates that operators sometimes maintain the bypass valve partially open to maintain the control valve in a controlling position. The following three scenarios must be analyzed for all fail open contingencies for control valves and the larger relief requirement used to evaluate the adequacy for overpressure protection: 1. The control valve fails wide open with its bypass valve partly open. This scenario is evaluated as a design contingency. In calculating 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 Cv of the control valve in its normally operating position, regardless of the actual size of the bypass valve. In this analysis, it is not

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necessary to consider the maximum trim that fits into the associated control valve if it can be established that Management of Change (MOC) protocols would preclude unauthorized trim replacement. Otherwise, the maximum size trim that fits into the associated control valve (not necessarily the installed trim) must be used to calculated the flow rate. The evaluation of the flow through the control valve and the bypass should be done assuming the upstream pressure remains at the highest normal operating level, while the downstream pressure increases to 110% of the downstream system design pressure. Credit may be taken for vapor being relieved through the normal channels (if the control scheme does not bottle-up the equipment) as well as through the PR valve. 2. The control valve fails wide open with its bypass valve also wide open (open 100%)., This scenario is evaluated as a remote contingency. In calculating the relieving rate for this case, the actual size of the bypass valve should be used, and the flow rate through the bypass valve would be the maximum flow with the bypass fully open. (Note that some existing facilities may have bypass valves with a Cv twice as large as the associated control valve. For new designs the bypass valve should be specified with a Cv approximately equal to that of the associated control valve.) The evaluation of the flow rate through the control valve and the bypass should be done assuming the upstream pressure remains at the highest normal operating level, while the downstream pressure increases to 150% of the downstream system design pressure (or the proof test pressure, whichever is lower). Credit may be taken for vapor being relieved through the normal channels (if the control scheme does not bottle-up the equipment) as well as through the PR valve. 3. The control valve fails wide open with the bypass fully closed during startup. This scenario is evaluated as a design contingency. In calculating the relieving rate for this case, assume that the downstream vessel is not yet operational. Therefore relief is only through the PR valve. In addition, the fluid in the equipment must be considered to be the startup fluid which may be significantly different from the normal fluid in the equipment. When the “bypass” valve consists of a duplicate control valve instead of a manual throttling valve (globe valve or equivalent), the same rules apply as for the case of manual bypass valves, provided that the duplicate control valve is operated as a “standby” or “spare” for the control valve normally in service (i.e., both control valves are never in service simultaneously). However, if the level controller acts on both valves simultaneously or through a split-range arrangement, or if the failure position of both control valves is fail-open (FO) or fail-hold drifting open (FH(O)), then failure of both valves in the fully open position must be treated as a design contingency. Under certain conditions, failure of a control valve in the open position may result in vapor blow-through into a system that is initially filled with stagnant (non-flowing) liquid. This situation may arise, for example, during the startup of certain hydrodesulfurization or hydroconversion units equipped with high-pressure liquid-vapor separators that feed the liquid to lower-pressure stripping towers. When this happens, the pressure in the downstream piping and equipment may temporarily approach that of the equipment upstream of the control valve as the liquid contained in the downstream system is accelerated. For such systems, the pressure-temperature rating of the piping and the design pressure of the equipment (vessels, exchangers) downstream of the control valve shall be determined as follows: 1. Determine the extent of piping and equipment that could be TOTALLY filled with stagnant (non-flowing) liquid immediately before the control valve fails open. This situation would typically arise only during startup. During normal operation, a high-pressure liquid letdown valve will normally generate flash vapor, so that the presence of a non-flowing, 100% liquid phase on the downstream piping or equipment is unlikely. 2. For any piping that could be TOTALLY filled with stagnant (non-flowing) liquid, specify a pressure-temperature rating such that the maximum operating pressure of the equipment upstream of the letdown valve does not exceed the short-term allowable pressure for the selected pressure-temperature rating at the operating temperature of the upstream system. The short-term allowable pressure is typically 133% of the maximum continuous pressure allowed for a given pressure-temperature rating. 3. For any equipment (vessels, exchangers) that could be TOTALLY filled with stagnant (non-flowing) liquid, specify a design pressure such that the maximum operating pressure of the equipment upstream of the letdown valve does not exceed “C” times the design pressure, where “C” is the multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01. When the application of these guidelines results in an unreasonable increase in the cost of downstream equipment or piping, the following alternatives may be considered: 1. Perform a dynamic analysis of the downstream system to determine the peak pressures as a function of time and downstream distance from the letdown valve. In some cases it may be possible to address the concern by specifying a maximum opening and/or closing rate for the control valve.

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2.

4.

Consider modifying the configuration of the downstream piping and equipment or the startup sequence such that only a minimal amount of piping and equipment is 100% filled with stagnant liquid whenever vapor blow-through is a credible scenario. 3. Provide a pressure relief device immediately downstream of the pressure letdown valve set at the maximum allowable working pressure of any piping or equipment located between the pressure letdown valve and the next piece of downstream equipment protected by a pressure relief device. When analyzing such individual control valve failures, one should consider the actions of other control valves in the system in accordance with Item 2, Control Valve System Analysis. However, the PR valve must be sized to handle the peak flow condition calculated from the various possible contingency scenarios for control valves. Special Capacity Consideration - Although control devices, such as diaphragm-operated control valves, are specified and sized for normal operating conditions, they are also expected to operate during upset conditions, including periods when pressure relieving devices are relieving. Valve design and valve-operator capability must be selected to ensure operation of the valve plug in accordance with control signals during abnormal pressure conditions. When wide discrepancies exist between normal and emergency conditions, the higher valve-actuator pressure requirements should be covered in the Design Specification. When determining pressure relief requirements, one should calculate the capacities of control valves at the temperature and pressure that occur during the relieving conditions, since these are in many cases significantly different from capacities at normal operating conditions. Downstream equipment must be analyzed under relieving conditions. 5. Evaluation of Pressurization and Escape Path - Reference should also be made to EVALUATION OF PRESSURIZATION PATH IN PRESSURE RELIEF DESIGN and EVALUATION OF ESCAPE PATH IN PRESSURE RELIEF DESIGN later in this PART I of the Design Procedure, for further discussion of control valves as a factor in pressure relief design. 6.8.2

Cooling Failure in Condenser/Cooler

In addition to the general failure of cooling water discussed under UTILITY FAILURE AS A CAUSE OF OVERPRESSURE, failure of cooling water flow to each individual condenser or cooler must be considered. Normally, no credit is taken for any residual cooling in a shell and tube condenser after the cooling stream fails, because it is time-limited and dependent on physical configuration of piping. 1. Total Condensing - The relief requirement is the total incoming vapor rate to the condenser. If desired, credit may be taken for reduced relieving rate, when recalculated at a temperature corresponding to the new vapor composition at the PR valve set pressure plus overpressure, and heat input prevailing at the time of relief. In the case of a fractionator, the overhead accumulator surge capacity at normal liquid level is typically limited to less than 10 minutes. Therefore, if the duration of cooling failure exceeds normal liquid holdup time, reflux is lost and the overhead composition, temperature, and vapor rate from the tower may change significantly. Hence, for many designs loss of a significant portion of tower overhead condensing capacity should be evaluated as loss of reflux. Also, the vapor load at the time of relief may be reduced below the normal operating rate, due to the higher pressure, which may suppress vaporization at the time of the overpressure. Pinchout of a reboiler is such a situation. In such a case, maximum steam process design conditions should be used, rather than the maximum steam pressure which could exist under pressure relieving conditions of the steam system. 2. Partial Condensing - The relief requirement is the difference between the incoming and outgoing vapor rates at relieving conditions. The incoming vapor rate should be calculated on the same basis as stated in Item 1. For a tower, if the reflux is changed in composition or rate, the incoming vapor rate to the condenser should be determined for the new conditions. 6.8.3

Air Fin Exchanger Failure

Loss of air fin exchanger capacity may result from fan failure, inadvertent louver closure, pitch control failure, or variable speed motor driver failure. 1. Fan Failure - The effect of fan failure on heat transfer capacity will depend on the configuration of fans and tube bundles. For pressure relief design, the design contingency failure of one fan is considered. (Failure of all fans, that would result from a general power failure, would be included under utility failure considerations.) When two or more fans are provided, it is assumed that one other fan is shut down for maintenance at the time of failure.

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Credit may be taken for continuing heat transfer as a result of natural convection. As a guide, this may be taken as 10% of design capacity for condensing service and 30% of design capacity for cooling service, applied over the area of tube bundle normally cooled by the fans that are shut down or failed. Thus, for an air-cooled condenser having two fans, the residual cooling capacity upon loss of one fan would be 10% of design (one fan assumed to be shut down for maintenance or operational reasons at the time of failure). For an air-cooled condenser equipped with four fans, the residual cooling capacity upon loss of one fan would be 55% of design (two fans running at their full capacity provide 50% of the total cooling capacity, while one shut down fan and one failed fan each provide 2.5% of the total cooling capacity by natural convection. Additional credit for natural convection cooling may be taken if supported by engineering calculations. 2. Louver Failure - Inadvertent louver closure may result from automatic control failure or mechanical linkage failure. The effect on heat transfer will depend on the degree of restriction to air flow in the closed position and the configuration of louvers in relation to tube bundles (e.g., louvers might not be installed over all tube bundles in a given service). For pressure relief design, the design contingency closure of one set of louvers is assumed. (Failure of all louvers, that would result from a general instrument air or power failure, would be included in utility failure considerations.) No credit may be taken for continuing heat transfer due to natural convection, since the closed louvers would interfere with free air circulation. 3. Pitch Control Failure - For the purpose of pressure relief design, the fan pitch position that result in the least air flow (therefore least cooling) is assumed as a design contingency. Credit may be taken for continued cooling at this air flow. 4. Variable Speed Motor Driver Speed Control Failure - Failure of the driver speed control may result in a significant loss of cooling depending on the last speed of the fan. For the purposes of pressure relief design, the speed that results in the least air flow (therefore least cooling) is assumed as a design contingency. Credit may be taken for continued cooling at this air flow. 6.8.4

Special Conditions in Closed Circuit

Where heating or cooling is used in a closed loop circuit (e.g., hot oil and refrigeration system), consideration must be given to overpressure conditions that might occur on loss of fluid flow, loss of heat input or loss of heat removal. 6.8.5

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 PR 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 PR 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. 6.8.6

Pumparound Flow Failure

The relief requirement is the vaporization rate caused by an amount of heat equal to that removed in the pumparound circuit. The latent heat of vaporization would correspond to the temperature and pressure at PR valve relieving conditions. “Pinchout" of steam heaters may be considered, if appropriate. When pumparound duty is high, or the feed to the fractionator is highly superheated (e.g. FCCU and Coker fractionators), loss of a pumparound 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 dry-out is usually the sum of all the vapor feeds entering the fractionator plus any stripping steam or reboiler vapor (where applicable). 6.8.7

Absorbent Flow Failure

In a unit where large quantities of inlet vapor may be removed in the absorber, loss of absorbent could cause a pressure rise to relief pressure, since the downstream system may not be adequate to handle the increased flow. In such cases, the effect of this additional vapor flow into downstream equipment must be analyzed. 6.8.8

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

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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. 6.8.9

Abnormal Process Heat Input

The required capacity is the maximum vapor generation rate at PR valve relieving conditions, including any noncondensibles produced from overheating, less the normal condensation or vapor outflow rate. In every case, the designer should consider the potential behavior of a system and each of its components. For example, the fuel or heating medium control valve or the tube heat transfer may be the limiting consideration. Consistent with the practice in other causes of overpressure, design values should be used for an item such as valve size (except maximum trim is used for control valves). However, built-in overcapacity, such as the common practice of specifying burners capable of 125 percent of heater design heat input, must be considered. Where limit stops are installed on valves, the wide-open capacity should be used rather than the capacity at the stop setting. In shell and tube heat exchange equipment, heat input should be calculated on the basis of clean, rather than fouled, conditions. 6.8.10

Emergency Conditions in Integrated Plants

In integrated plants, a process upset in one unit may have an effect on other units (e.g., loss of flow of a pumparound which is used as a source of heat for reboiling other towers). All possibilities such as these must be carefully considered and the potential for resulting overpressure evaluated. 6.8.11

Accumulation of Noncondensibles

Noncondensibles do not accumulate under normal conditions since they are released with the process vapor streams. However, with certain piping configurations, it is possible for noncondensibles to accumulate to the point that a condenser is “blanketed." Such a condition could occur if an automatic vent control valve failed closed for a period of time. This effect is equal to a total loss of coolant, and thus need not be considered separately. 6.8.12

Water or Light Hydrocarbon Into Hot Oil

Although this situation remains a source of potential overpressure, no generally recognized methods for calculating the relieving rate requirements are available. In some situations, the quantity of water present and the heat available in the process stream are known, or can be estimated hence, the PR valve size can be calculated. For example, in the case of a hot feed accumulator, it may be possible to estimate the pressure that would be developed if water were pumped into the vessel at various rates. Other examples where it may be possible to estimate the potential quantity of water that may enter the equipment include towers where loss of level in the overhead separator may send an oilwater mixture or even water as reflux to the tower, and in heat exchangers where a tube failure can introduce low boiling liquid or water (heat exchanger tube rupture is discussed in OVERPRESSURE IN SPECIFIC EQUIPMENT ITEMS). Since the expansion in volume from liquid to vapor is so great (approximately 1,400-fold at atmospheric pressure in the case of water) and the speed of vapor generation is very great, it is questionable whether the PR valve could open fast enough to be of value. However, a rupture disc could provide relief for these explosion-like events and therefore, may be the most appropriate pressure relief device for this contingency. Proper process system design and operation, including startup conditions, are very important requirements to eliminate the possibility of introducing water or light hydrocarbon into hot oil. Avoidance of water-collecting pockets, proper steam condensate traps, and double blocks and bleeds on water connections to hot process lines are some precautions that can be taken. Likewise, vessel bottom withdrawal connections should not be installed with internal extensions, which could result in water being trapped in the bottom of the vessel. Refer also to the discussion under Asphalt Operations and Atmospheric Tankage in DP XV-B.

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Internal Equipment Blockage

Contingencies such as collapsed reactor bed vessel internals (e.g., fixed-bed reactor grids, reactor outlet collector collapse/plug, coked catalyst beds, accumulation of catalyst fines, plugging of screens and strainers, lines blocked with coke, etc.), should be considered, to identify any overpressure situations that could result. The use of the “1.5 Times Design Pressure Rule" (see DESIGN PROCEDURE, PART I, INTRODUCTION) is generally applicable in such cases, if this is a remote contingency. Overpressure due to collapse of fractionator tower tray internals is so rare that it is generally not a design consideration. ç

6.8.14

Manual Valve Maloperation

Inadvertent operation of a block valve while the plant is onstream may expose equipment to a pressure that exceeds the maximum allowable working pressure. For the purpose of design, it is considered that only one manual valve is opened or closed (except as noted below) and control devices are in their normal operation position, as described earlier. A PR valve is required if the block valve is not locked or car sealed in its “safe” position (either open or closed) and if closure or opening of such valve can result in overpressure. For limitations on the use of car-sealed valves, see the discussion under EVALUATION OF ESCAPE PATH IN PRESSURE RELIEF DESIGN. ç

As an example, consider a control valve station equipped with a manual bypass valve. If opening of the manual valve can overpressure equipment or piping downstream of the control valve, a pressure relief device is required to protect the downstream equipment unless the bypass valve is car-sealed closed and the system meets the limitations on the use of car-sealed valves discussed under EVALUATION OF ESCAPE PATH IN PRESSURE RELIEF DESIGN. For the purposes of calculating the required relief rate, the control valve is assumed to remain in its normal operating position.

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When normally closed double block valves are installed in accordance with GP-03-12-01, it shall be assumed that both block valves can be inadvertently opened (as if only a single block valve were present), unless at least one of them is car-sealed closed. The limitations on the use of car-sealed valves discussed under EVALUATION OF ESCAPE PATH IN PRESSURE RELIEF DESIGN also apply to this case.

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For all cases that rely on a pressure relief device to prevent overpressure, the quantity of material to be relieved should be determined at conditions corresponding to the PR valve set pressure plus overpressure, not at normal operating conditions. Frequently, there is an appreciable reduction in required PR valve capacity when this difference in conditions is considerable. The effect of friction pressure drop in the connecting line between the source of pressure and the system being protected should also be considered in determining the capacity requirement. If the valve passes a liquid which flashes or the heat content causes vaporization of liquid, this must be considered in determining PR valve size. 6.8.15

Hydraulic Surge

Pressure surge occurs in liquid filled piping systems when the velocity of the liquid changes rapidly due to sudden valve closure, sudden pressure letdown, pump startup, pump shutdown or similar events. When pressure surge occurs, forces produced in the piping system may exceed the design capability. Various mechanical relief devices can be used to limit the magnitude of this pressure surge: rupture discs, accumulators, and proprietary devices such as the Grove Flexflo valve. Methods for evaluating surge pressures and selecting the best surge relief device can be found in Report Nos. EE.74E.83, EE.62E.86, EE.86E.95 and EE.35E.98. 6.8.16

Startup, Shutdown and Alternate Operations

Not only design steady-state conditions, but also startup, shutdown, washout, regeneration, alternate feed stocks, blocked operations and other possible different conditions must be evaluated for overpressure protection. 6.8.17

Increased Plant Capacity

When an existing plant capacity is increased, the entire pressure relieving system should be reevaluated, even though no new equipment has been added.

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OVERPRESSURE IN SPECIFIC EQUIPMENT ITEMS

In addition to equipment malfunctions which can cause process overpressure in associated equipment (e.g., overpressure in a fractionator due to failure of cooling water or reflux pump), certain items of equipment are themselves subject to overpressure due to mechanical reasons. Such items include heat exchangers, pumps, compressors, turbines and fired heaters. The design of appropriate protection for them is covered in the following paragraphs. 6.9.1

Heat Exchanger Split Tube and Tube Leakage

In a shell and tube exchanger, the tubes are subject to failure from a number of causes, such as thermal shock, vibration or corrosion. Whatever the cause, the possibility of the high-pressure stream overpressuring equipment on the low-pressure side of the exchanger is the result. Hence, in heat exchangers, tube failure must be considered as a potential contingency for overpressure of the low-pressure side. Note that normally the higher-pressure stream flows through the tubes and that tubes and tubesheets are designed for differential pressure, potentially creating unusual problems. ç

A tube split contingency need not be considered for the following types of exchangers: 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 hole concept and, consider all potential Equipment Degradation Modes, see TMEE 062 Section 7 EDD's and Section 8 PDD's. 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). Research has shown that carbon steel tubes are not susceptible to brittle fracture above this temperature (see EE.10E.78). Nickel steel, stainless steel, nickel alloy and aluminum tubes may operate at even lower temperatures without risk of brittle fracture. 5. The tubes are not subject to fatigue or creep. 6. The process fluid will not cause aggressive corrosion or degradation of tubes and tubesheets (for example pitting from salt deposits, corrosion from acidic condensates or stress corrosion cracking). Consult with EMRE’s Materials Engineering specialists to determine the appropriate material for the service conditions. 7. An appropriate tube inspection program will be developed for the exchanger bundle, after consulting with EMRE's Materials Engineering specialists.

However, all these exchanger types should be evaluated considering leakage through a 0.25 in. (6 mm) hole due to corrosion. The pressure relationships in the heat exchanger must be known to permit proper evaluation of the results of a tube split. The ability of the complete low-pressure system to absorb the release through the split tube must be determined. The possible pressure rise must be ascertained, to determine whether additional pressure relief will be required if flow from the split tube were to discharge into the lower pressure stream. The low pressure side of an exchanger must be protected by pressure relief devices if the design pressure on the high pressure side is more than ”C” times the design pressure of the low pressure side and the low pressure side cannot handle the discharge from a split tube without exceeding ”C” times the low pressure side design pressure, where “C” is the multiplier applied to the low-pressure side design pressure to determine the hydrostatic test pressure per GP 05-03-01. In determining whether the piping and equipment on the low-pressure side can handle a discharge from a split tube, any control valve present shall be assumed to be positioned for the minimum (turndown) normal design flow rate. If the control valve is normally closed or if the tube failure may cause the control valve to close, then

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no pressure relief can be assumed to occur through the piping. The entire low-pressure system must be examined for potential overpressure by a split tube. If the decision is to uprate the design pressure of the low pressure system in order to eliminate a split tube contingency, the complete low pressure system must be uprated or the entire low pressure side must be checked to ascertain that the “1.5 Times Design Pressure Rule" is met.

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If a PR valve 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. Refer to a sample procedure for calculating the maximum flow in APPENDIX 3. In calculating this maximum flow rate, the normal process flow into the low-pressure side is typically assumed to stop and the pressure difference across the tube opening is the difference between the maximum operating pressure of the high-pressure side and 1.5 times the design pressure (or the proof test pressure, if lower) of the low-pressure side. The effect of flashing as liquid flows from the high pressure side to the low pressure side, vaporization of any liquid in the low pressure side due to resultant high temperature fluid, and loss of normal process flow in the low pressure side must be taken into consideration in determining the relieving rate for the PR valve. In the event of a tube failure, transient pressures on the low-pressure side of the heat exchanger should be evaluated when the differential pressure between the high pressure side and the low pressure side equals or exceeds 500 psi (3,500 kPa). If the high pressure is on the tube side of the heat exchanger, the shell side transient pressure can be evaluated using “BREAK-X," a computer program for predicting peak pressures in heat exchangers due to tube rupture (refer to Report No. EE.18E.81), or equivalent computer program if approved and validated by EMRE. If the high pressure is on the shell side of the heat exchanger, “BREAK X" is not applicable. Therefore, to evaluate transient pressures in this situation, the Mechanical Engineering Section of ExxonMobil Engineering should be consulted. When the design pressure of the high pressure side exceeds the design pressure of the low pressure side by 1000 psi (6,900 kPa) or more and where an active corrosion mechanism is present, the probability and potential consequence of a multiple tube rupture shall be assessed qualitatively. Experience shows that in such exchangers the rupture of one tube has resulted in the rupture of several adjacent tubes due to a sudden pressure surge and deteriorated conditions of tubes in the exchanger. This assessment shall consider both the Safety, Health and Environmental (SHE) risks and the operational risk due to the likelihood that the event may render the affected equipment unfit for service, which will require replacement before normal operations are resumed. In addition, the upstream and downstream piping and equipment shall be designed to accommodate the surge forces due to the pressure surge predicted by "BREAK X" for a single tube rupture. Also the low-pressure side shall be examined for potential overpressure from ten split tubes, assuming the maximum flow through two open ends of each tube. If the resulting pressure could exceed C times the design pressure of the low-pressure system, then overpressure protection shall be provided. In addition to evaluating the effect of a split tube, it should be recognized that internal tube sheet or tube leakage can occur, often unknowingly, under normal operation. Where the single action of deliberately blocking the low pressure side of the exchanger would result in the low pressure side of the exchanger exceeding 1.5 times its design pressure or its proof test pressure, whichever is lower, as a result of an internal leak, the low pressure side of the exchanger should be uprated; or a PR valve sized for the leakage through a 0.25 in. (6 mm) hole or a minimum size PR valve [1 in. x 2 in. (25 mm x 50 mm)] should be installed. Alternatively, permanent signs warning against closing the block valves on the low pressure side unless a bleeder has been opened or the high pressure side has been isolated and blinded should be attached to the block valves on the low pressure side. If blockage of the low-pressure side can occur as a result of an operating event such as total closure of a control valve, the contingency is no longer considered remote and must be treated as a design contingency for the purposes of overpressure protection. The effect of a temperature change on the low-pressure side as a result of tube leakage is generally neglected when the design temperature of the low-pressure side is specified, since an increase in temperature is usually considered as a case of short-term allowable stress. The impact of low temperature caused by depressuring through the split tube must also be analyzed. Where brittle fracture conditions might occur in the low pressure side, various procedures to minimize the chance of tube failure (such as welding the tubes into the tube sheet and upgrading the tube materials to obtain better corrosion resistance) are acceptable alternatives to specifying brittle fracture resistant materials throughout the low pressure side. 6.9.2

Pumps and Downstream Equipment

See DP II to calculate pump casing and downstream equipment design pressures. A PR valve is required for a pump when the shutoff pressure of the pump is greater than the design pressure of the pump casing, the discharge piping,

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or any downstream equipment that may be blocked-in against the pump. Positive displacement pumps normally require a PR valve for overpressure protection since the pump shutoff pressure can not generally be defined. In most cases centrifugal pumps do not require a PR valve for overpressure protection since the pump shutoff pressure can be defined and the pump and downstream equipment is generally designed for this pressure. When a PR valve is required, the PR valve set pressure is normally equal to the design pressure of the equipment being protected. When the equipment being protected has different design pressures, the set pressure of the PR valve must take into consideration the lowest design pressure in the system (which may be in the pump auxiliary equipment such as flushing/seal systems). The PR valve is sized such that the accumulation during relief will not exceed allowable overpressure (1.1 or 1.16 times the lowest design pressure, depending upon the number of relief devices used). However, where only piping is involved, a short-term pressure allowance may apply. If the pump casing design pressure or the mechanical seal design pressure is lower than the maximum pressure at shutoff of the pump, the maximum pressure at shutoff of an associated operating pump, or the design pressure of the pump auxiliary equipment (such as external flushing or seal systems), a PR valve must be installed to protect the pump. The set pressure for a pump PR valve is the lower of the pressure rating of the mechanical seal, the pump casing pressure or the design pressure of any other limiting component. The PR valve is sized for the potential source of excessive pressure, as follows: 1. If external flushing or seal systems are the only source of excessive pressure, a pump suction PR valve is sized for the maximum flow from these systems. 2. If the only source of excessive pressure is an associated pump, a pump suction PR valve is sized for reverse flow through the downstream check valve. Refer to “EVALUATION OF PRESSURIZATION PATH IN PRESSURE RELIEF DESIGN” for a discussion on the use of check valves to limit overpressure. When drilled check valves or check valve bypasses are specified for pump warm-up purposes per GP 03-03-02, the pump suction PR valve shall include capacity for the normal flow associated with these facilities. 3. If the source of excessive pressure can be both the external flushing/seal system and an associated pump, a pump suction PR valve is sized for the greater of 1 or 2. 4. If the source of excessive pressure is the discharge of the pump, a pump discharge PR valve is sized for the maximum actual rate that the pump can deliver at the accumulated pressure of the PR valve. The design pressure of a steam-driven reciprocating pump and downstream equipment may be set by the maximum process pressure which the steam cylinder is able to produce at maximum steam pressure, in which case no pressure relief facilities are required. However, in most cases it is not economical to set the design pressure of downstream equipment as high as this maximum stalling pressure. In these cases, a PR valve would be required to protect the downstream equipment against overpressure. For reciprocating pumps driven by electric motors, PR valves serve the dual purposes of protecting the pump and downstream piping from overpressure, and protecting the driver from overload. DP X-F describes this application. Other positive displacement pumps, such as rotary, gear, and diaphragm pumps, normally require PR valve protection for both the pump and downstream equipment. For any pump requiring a PR valve for its protection or for protection of downstream equipment, the PR valve set pressure should be higher than the normal pump discharge pressure as defined in DP II. Note, however, that in some cases a higher PR valve set pressure may be desirable to assure a sufficient differential when the pump is to be operated under lower than normal design pumping rate. This will recognize the higher pump discharge pressure under low flow conditions. In the case of reciprocating pumps protected by spring loaded PR valves, the PR valve should be set above the maximum pulsation pressure or 15 percent above the operating pressure, whichever is greater. When this is not possible because of equipment design pressure or specified operating pressure level, pilotoperated valves should be considered. The capacity of a pump discharge PR valve should equal the capacity of the pump at the pressure conditions existing while the PR valve is relieving. To reduce the size of a PR valve installed at the discharge of a centrifugal pump with a known pump curve, advantage can be taken for the reduction in pump capacity as it backs up on its performance curve. Pump PR valves should discharge to a closed system. In many cases discharge paths may be routed to the suction line or suction vessel.

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Compressor and Downstream Equipment

PR valves are required for any compressor where the maximum pressure which can be generated during surge or restricted discharge conditions exceeds the design pressure of the discharge piping, downstream equipment compressor seals, or compressor casing. For centrifugal compressors, it is usually economical to set the design pressure lower than the maximum possible pressure that the compressor can develop, and to provide appropriate PR valve protection on the discharge. In some cases (e.g., where the flow through a PR valve would be the release which establishes the size of a closed disposal system), it may be advantageous to set the design pressure of the compressor casing and downstream equipment equal to the maximum pressure that can be generated at the surge point, assuming the most severe combination of speed, molecular weight, suction pressure and temperature conditions that can occur as the result of a design contingency. For positive displacement compressors, discharge PR valves are nearly always required. Reliance on stalling of a reciprocating compressor is generally not economically attractive, since driver stalling pressures are usually quite high in comparison to operating pressure. Pressure relief valves for centrifugal compressors should be set higher than the normal operating pressure by 25 psi (170 kPa) or 10% of operating pressure, whichever is greater.. Interstage PR valves should be set at least as high as the compressor settling-out pressure, to avoid valve lifting during compressor shutdowns. In the case of reciprocating compressors protected by spring loaded PR valves, the PR valve should be set above the maximum pulsation pressure or 15 percent above the operating pressure, whichever is greater. When this is not possible because of equipment design pressure or specified operating pressure level, pilot-operated valves should be considered. Short-term pressure allowances for piping may be considered. Low-pressure stage casings and interstage circuits on both centrifugal and positive displacement multi-stage compressors are not normally designed for full discharge pressure and must also be provided with overpressure protection. Where interstage PR valves are required, PR valve capacity should be equal to the compressor capacity at the emergency conditions. If recycle and/or anti-surge lines are provided, interstage PR valves should be sized for the greater of the compressor capacity or the flow through the recycle lines with fully opened recycle valves, assuming check valve leakage (see check valve reverse flow under “EVALUATION OF PRESSURIZATION PATH IN PRESSURE RELIEF DESIGN” in this Design Practice). Where a reciprocating compressor is used, the compressor internals may be considered the same as a single check valve. For reciprocating compressors, if an operating compressor stops running, vapor may backflow through the compressor and overpressure equipment upstream of the compressor. To calculate the amount of vapor which may backflow through a reciprocating compressor consider each compressor stage as a single check valve. If there is a check valve in the discharge of the stage, consider it as an additional check valve. Refer to “EVALUATION OF PRESSURIZATION PATH IN PRESSURE RELIEF DESIGN”” for a discussion on reverse flow through check valves Note some multi-stage machines have recycle lines around individual cylinders, with control valves, for startup or capacity control. These must be assessed separately, similar to the standard low flow recycle loops. For centrifugal compressors, the combination of PR valve set point and relieving capacity should be such as to avoid surge conditions over the anticipated combinations of emergency conditions and operating variables. Compressor PR valves should discharge to an appropriate atmospheric or closed system, and not directly to the suction of the machine. Since many variables are involved, it may be advisable to consult the Machinery Engineering Section on specific problems. 6.9.4

Steam Turbine

A PR valve is required on the steam inlet to any steam turbine if the maximum steam supply pressure is greater than the design pressure of the casing inlet. The PR valve should be set at the casing inlet design pressure and sized such that overpressure of the casing is prevented under conditions of wide open steam supply and no exhaust flow.

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Protection of the exhaust end of steam turbines is dependent on whether they are in condensing or noncondensing service, as follows: 1. Condensing Turbine - The condenser and the exhaust end of a condensing turbine casing are not normally designed for full steam supply pressure. Therefore, in such cases, protection must be provided against overpressure which could result from loss of cooling water or other operating failure. The special type of pressure relief valve which is normally installed on the turbine exhaust for this purpose is illustrated in Figure I-1. It has no spring end and is normally held closed by the vacuum conditions in the condenser; but a supply of fresh water (not salt or brackish water) is required for the sealing system. The condenser vendor usually specifies and provides the PR valve in accordance with the specification of the Standards of the Heat Exchanger Institute. The required relieving rates for these PR valves are based upon the steam rate to the turbine under ordinary condensing operation only, and the appropriate size can be checked against the following table, which is taken from Standards of the Heat Exchanger Institute, Surface Condenser Section. MAXIMUM STEAM RATE TO TURBINE, lb/h Up

to 7,500 7,501 11,800 11,801 17,000 17,001 20,000 20,001 23,100

to

6 8 8 8 10

MAXIMUM STEAM RATE TO TURBINE, kg/s < 0.95 0.95

to

1.50

to

2.15

to

2.53

to

2.92

to

3.81

to

4.82

to

5.68

to

5.95

to

7.81

to

8.57 10.33 10.34 13.38 13.39 15.15

to

1.49

REQUIRED PR VALVE SIZE (INLET FLANGE DIAMETER, mm) 150 200 200 200 250

2.14 to 2.52 to 2.91

23,101 30,200 30,201 38,200 38,201 45,000 45,001 47,200

to

47,201 62,000 62,001 68,000 68,001 82,000 82,001 106,000 106,001 120,000

to

120,001 170,000 170,001 250,000 250,001 380,000 380,001 550,000

ç

to

REQUIRED PR VALVE SIZE (INLET FLANGE DIAMETER, in.)

to

10 12 12 14

3.80 4.81

to

250 300 300 350

5.67 to 5.94

to to

14 16 16 18 18

to to to to to to

20 24 30 36

7.80 8.56

15.16 21.46 21.47 31.56 31.57 47.98 47.99 69.44

350 400 400 450 450

to to to to

500 600 750 900

to to

When a condensing turbine has one or more intermediate extraction stages, each extraction line should be protected against overpressure due to blockage of the extraction line. If a PR valve is used to provide this protection, it should be sized for the full steam flow rate to the turbine without taking credit for the steam extraction at other stages (if any) or for steam flow to the condenser. Condensing turbines with intermediate extraction typically rely on internal re-admission valves to route the steam flow that exceeds the extraction rate to the condenser (or to lower pressure extraction stages, if any). This approach is consistent with the

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concept that no credit may be taken for favorable response of instruments or control valves in reducing the required relief load. Noncondensing Turbine - The casing of a noncondensing turbine is usually not designed for full steam supply pressure at the exhaust end. A pressure relief valve is therefore required at the turbine exhaust if the pressure in any part of the casing can exceed its design pressure as a result of exhaust valve closure, back pressure fluctuations or similar contingency. The PR valve should exhaust to the atmosphere, and its set pressure should be higher than the normal exhaust pressure by 25 psi (170 kPa) or 10% of operating pressure, whichever is greater. In addition, the lowest design pressure of any section of the casing must be specified to be no lower than the PR valve set pressure plus the pressure drop to the PR valve during relief. The PR valve should be sized to pass the maximum steam flow assuming sonic velocity through the smallest restriction in the flow and at the maximum inlet pressure. Credit may be taken for steam flow which is withdrawn from an intermediate turbine stage if it would not be blocked by the same contingency as closure of the exhaust. Exceptions to the foregoing requirements apply in the following cases: a. Turbines exhausting to the atmosphere through open piping without valves do not require exhaust overpressure protection. b. Turbines exhausting into an exhaust steam main through a top or side connection do not require exhaust overpressure protection, provided that the maximum inlet steam pressure does not exceed 150 psig (1,000 kPa gage), but a warning notice must be provided at the exhaust valve and the valve must be CSO, in accordance with GP 03-03-07.

6.9.5

Fired Heaters and Boilers

Two potential forms of overpressure may apply to fired heaters and boilers: overpressure of the firebox by forceddraft fans or tube rupture; and overpressure of tubes due to outlet blockage or from overheating due to loss of process flow. 1. Firebox Overpressure - The firebox of a forced-draft fired heater or boiler is designed to withstand the overpressure that can be generated by the fans with dampers in their closed position, in accordance with DP VIIIK, Air-Preheaters, and GP 07-01-01 and GP 07-02-01. This needs to be specially checked when both forced and induced-draft fans are provided to discharge combustion products through heat recovery facilities, since higher than normal fan pressures may be used to overcome pressure drop. When excessive pressure can be developed, protection can be provided by use of a high pressure cut-out or pressure relief doors. In the case of high pressure process fired heaters, a tube rupture could also be the cause of firebox overpressure. In this case, “explosion" doors can be used to provide protection. When the tube pressure exceeds 1,000 psig (6900 kPa gage), the analysis is complex and COMBUSTION ENGINEERING SPECIALISTS should be consulted. 2. Boiler Steam Side Overpressure - All fired boilers are provided with PR valves sized to relieve the full steam rate in the event of closure of the normal outlet, in accordance with the ASME Code, Section I (Power Boilers), or other applicable regulations. Overpressure protection for waste heat boilers is designed in accordance with the ASME Code requirements for “pressure vessels," provided that they comply with the definitions in Paragraph U-1 (e) of Section VIII, Division 1, of the Code. 3. Process Fired Heater Coil Overpressure - The coil of any fired heater where the process flow can be stopped by inadvertent closure of a valve in the fired heater outlet (operator error) or as a result of planned emergency action, is subject to potential overpressure and tube failure due to overheating and consequent reduction in allowable stress. Unless such mechanisms of flow interruption (arising from a design contingency) can be effectively eliminated, the fired heater must be protected against loss of process flow, which can lead to overheating and tube failure, and against overpressure from upstream equipment such as pumps or compressors. Protection against loss of process flow is required by GP 15-01-01 for all fired heaters, whether or not they are equipped with a block valve and/or a PR valve at the coil outlet. According to GP 15-01-01, all fired heaters shall have a safety critical low-flow cut-out [FL(CO)] with pre-alarm which shuts off the main fuel(s) on low total process feed flow. The provision of a PR valve on the outlet of a fired heater to ensure continuity of process flow if the coil outlet is blocked is not recommended because of the potential for coking at the PR valve inlet and for thermally shocking the discharge piping when the PR valve blows.

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Protection against overpressure can be achieved by setting the coil design pressure at or above the shut-off pressure of the feed source(s) or by providing a PR valve. If a PR valve is provided, it should preferentially be located at the coil inlet. Although locating the PR valve at the coil outlet does provide additional protection against loss of flow (beyond that provided by the FL(CO) on total feed), it does not eliminate the need to comply with the requirements of GP 15-01-01, and is not recommended for the reasons stated in the preceding paragraph. When a PR valve is provided on the fired heater feed line, the valve should be located upstream of the orifice which senses low fired heater feed flow and actuates the fuel cutout, so that the fuel will be cut out in case the fired heater should be blocked at the outlet. The design features required to reduce the likelihood of fired heater tubes overheating and subsequent overpressure are as follows: a. Low flow alarms, fuel cutout on loss of process flow, and fired heater feed reliability should be provided in accordance with DP XV-B and GP 15-01-01. The low flow alarm and fuel cutout are the primary protection against coil failure due to overheating from loss of feed or closure of an inlet or outlet block valve. b. Control valves in fired heater inlets should fail open, or remain stationary and drift to the open position on actuating medium or signal failure, to prevent coil overheating. c. If a block valve is installed in the fired heater inlet only, a PR valve is not required and the block valve need not be CSO since closure of this valve will not cause excessive pressure. In this case, the fired heater coil is protected from overheating and potential failure by the FL(CO) on total feed prescribed by GP 15-01-01. When manual or automatic control valves are provided on each pass to provide for feed distribution in a multi-pass fired heater as required by GP 15-01-01, protection against the loss of flow in any one pass is provided by a low-flow alarm on each pass (non-coking services) or by a low-flow cut-out on each pass (coking service) per GP 15-01-01. d. e.

f.

6.9.6

The provision of only a check valve in a fired heater outlet line for emergency isolation purposes, per DP XVF, does not require the provision of pressure relieving facilities. Although not recommended, if a PR valve is installed at the fired heater outlet, it should be located downstream of any temperature control device so that overfiring does not occur when the PR valve is relieving. The design of the PR valve should conform to the following guidelines: 1. The PR valve can be installed as a bypass around the EBV or may discharge to the atmosphere or to another closed system. It should be sized for at least 25% of normal flow and should have a set point 10% or 25 psi (170 kPa) above the normal operating pressure, whichever is greater. 2. The fired heater feed source must have a pressure/flow characteristic such that at least 25% of the normal flow will be maintained through the fired heater, if the coil outlet inadvertently blocked and the PR valve then opens. Allowance should be made for pressure drop in the system due to fouling. 3. The PR valve should be designed for coil outlet conditions, and should include a purge if necessary to minimize coke deposition in the PR valve inlet. (Refer to PRESSURE RELIEF VALVE INSTALLATION later in this section.) 4. The mechanical design of the discharge piping must consider the possibility of severe thermal shocking whenever the PR valve blows. When an EBV (Emergency Block Valve) is installed in a fired heater outlet for emergency isolation purposes per DP XV-F, it is necessary to rapidly cut out the main fuel supply to prevent tube rupture in case the EBV should inadvertently be closed. This is achieved by providing a low-flow cut-out (FL(CO)) on the total feed to the fired heater as prescribed in GP 15-01-01. In addition, the EBV should be equipped with a limit switch that will trip the main fuel supply to the fired heater and shutdown the pump(s) and/or compressor(s) feeding the fired heater when the valve reaches the half-closed position. Fractionator Overhead System

In addition to the design contingencies valid for the tower, the overhead system is also subject to a number of unusual contingencies. Guidance on how to consider these, assuming the main means of protection are pressure relief (PR) valves in the tower itself or in the overhead line follows: 1. Tube Rupture - In many designs the overhead duty as well as tower reboilers and preheaters are divided into a number of different services for heat integration purposes, for example, crude preheat followed by air fins and cooling water. Since some of these services may be at a considerably higher pressure than the tower, tube rupture in the shell & tube exchanger and its impact on tower PR valves needs to be assessed. The basis for

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assessment was described earlier and a detailed step-by-step procedure is attached as APPENDIX 3. Key considerations are the following: a. Tube rupture is a remote contingency. b. When the tube rupture occurs, all other equipment continues to function at its normal minimum (turndown) capacity unless there are automatic systems that would be triggered by the contingency and cause equipment operation to change. If this change in operation (triggered by the automatic system) would increase the relief available through normal routes, credit may not be taken for the additional relief above the normal minimum (turndown) outflow form the system. If the change in operation (triggered by the automatic system) would decrease the relief available through normal routes, this debit should be taken into account to the full extent. For example, a control valve on the vapor leaving the overhead drum that is tied into the pressure control system would be expected to fully open to attempt to limit the pressure rise in the overhead drum. In this example, no credit may be taken for the additional flow through the control valve above the normal turndown rate. c. Since the tube rupture is already assumed to be a remote contingency, when it occurs the operator is assumed to take no action; neither positive (that would reduce the overpressure) nor negative (that would result in even greater overpressure). 2. Overhead Drum Overfilling - Overfilling of an overhead drum occurs when the incoming liquid from the condenser exceeds the outflow because flow ceased in this route. Loss of outflow can be the result of a variety of reasons, such as the following: operator error (closure of a block valve), pump mechanical failure, loss of pump motive power (such as steam or electricity), loss of instrument air to a control valve, and mechanical failure of a control valve. This contingency should be reviewed. See LIQUID OVERFILL AS A CAUSE OF OVERPRESSURE. Once the vessel overfills, if the PR valves protecting the drum are 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 longer be any incoming liquid. Instead the lack of a disposal route for the overhead vapor will cause the tower PR valves to open. Therefore, at a minimum the tower PR valves must be designed for the full overhead flow. Regardless whether the drum overfilling contingency is judged a design or a remote contingency, the design pressure of the overhead drum must take into account the maximum fill level that will be reached during the contingency. Hence, if the overfill is a design contingency, the drum design pressure must be equal to the set pressure of the tower PR valves plus the static head up to the flooded condenser. 3. Tower Overfilling - Completely filling a large tower with liquid has occurred a number of times (at least 9 times during a 10 year period based on the data presented in 83EEEL-2678). As a result, tower overfill must be considered as an overpressure contingency but may be designated as a remote contingency provided the criteria discussed in LIQUID OVERFILL AS A CAUSE OF OVERPRESSURE are met. As with the overhead drum overfill contingency, regardless whether the tower overfill contingency is judged a design or a remote contingency, the design pressure of the overhead drum must take into account the maximum fill level that will be reached during the contingency. Hence, if the overfill is a design contingency, the overhead drum and associated equipment design pressure must be equal to or greater than the set pressure of the tower PR valve plus the static head up to the tower PR valve elevation. If the overfill is a remote contingency, the overhead drum design pressure must be equal to or greater than two-thirds of the sum of the accumulated pressure of the tower PR valve plus the static head up to the tower PR valve elevation. In addition, for the tower overfill contingency, the complete overhead system and all attached equipment (e.g., side stream stripper) must be designed to be liquid filled with the maximum specific gravity liquid. This may require special considerations for the support of affected equipment. 6.9.7

Pressurized Storage (Offsites)

In general, offsite pressurized storage is designed as a pressure vessel and PR valves are provided for all valid contingencies similar to onsite facilities. However, due to the location of these vessels, a number of special considerations must be considered, as follows: 1. Due to the presence of dikes around pressurized storage facilities, drainage away from the vessel is generally limited or not available. Hence, when evaluating the fire exposure contingency no credit may be taken for good drainage (refer to APPENDIX 1).

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2.

When overfilling of the pressurized storage is physically possible (i.e., the feed pumps have sufficient head to overcome the liquid level and the PR valve set point), it must be considered as a contingency. The relief rate would be based on the characteristics of the feed pump and credit may be taken for reduced rate at the accumulated PR valve pressure. In addition, consideration must be given to the flashing and autorefrigeration that may occur as the fluid is relieved through the PR valve. Refer to “LIQUID OVERFILL AS A CAUSE OF OVERPRESSURE” for additional considerations.

3.

If pressurized storage vessels are not designed for full vacuum, a vacuum vent/breaker must be installed. In addition, since the vacuum breaker would permit air ingress (which may form a flammable-air mixture), a low pressure cut-in that introduces fuel gas or a suitable inert gas should be provided and its set point adjusted such that it actuates prior to any air entering the vessel.

6.9.8

S

Section

Piping

In general, it is good engineering practice for all piping (both onsite and offsite) to be capable of withstanding a pressure at least equal to the design pressure of the equipment to which it is connected. When the piping to be installed does not have the same design pressure as the equipment to which it is connected, it may be protected against overpressure by the use of PR valves. The set pressure for these PR valves would generally equal the design pressure of the piping. In establishing the piping design pressure no credit may be taken for the corrosion allowance. Hence, the piping design pressure is calculated after reducing the wall thickness by the corrosion allowance and assuming the minimum thickness to be equal to 87% of the nominal thickness. In some cases, when the cause of excessive pressure may not be frequent, advantage may be taken of the short-term overstress conditions in ANSI B31.3. However, prior to taking advantage of the “special line" designation, the designer must verify that all requirements of ANSI B31.3 are met. If the potential cause of overpressure is fire exposure, there is no code requirement to protect piping. Overpressure caused by thermal expansion is a special situation and is covered later in this section. 6.10

OVERPRESSURE CAUSED BY CHEMICAL REACTION

In chemical reaction processes, decomposition reactions and temperature runaways may occur as a result of feed or quench failure, overheating of feed, contaminants, or other similar causes. High-pressure hydrogen processes and methanation reactions are examples. These unwanted chemical reactions may result in excessive temperature and pressure in the reactor vessels. The system behavior during the emergency can be characterized as follows: 1. Tempered - Tempered systems are those in which the unwanted reaction produces condensable products and the temperature and pressure rise are directly linked by the vapor pressure curve of the reactants and products in the reactor. Typically, tempered systems are liquid phase reactions in which a reactant (or solvent) is a major part of the reactor contents and absorbs the majority of the heat produced by the chemical reaction. 2. Gassy - Gassy systems are those in which the unwanted reaction produces a non-condensable product and therefore the pressure and temperature in the reactor are not tied to the vapor pressure characteristics of the reactor contents. Gassy systems may be either liquid phase decompositions or gas phase reactions. 3. Hybrid - Hybrid systems are those that exhibit characteristics of both tempered and gassy systems. Many times the hybrid system will initially behave as a tempered system but subsequently develop into a gassy system. Systems that are tempered can, under some circumstances, be protected against overpressure caused by an unwanted chemical reaction with the use of PR devices. Gassy and hybrid systems tend to overheat and result in requiring excessively high relieving rates. In either case, systems that are gassy or hybrid cannot, in general, be fully protected against overpressure caused by the unwanted chemical reaction with the use of PR devices. For situations where protection can not be fully provided by PR devices, safety critical instrumentation should, in many cases, be used since early detection and depressuring might kill the unwanted reaction and/or reduce the metal stress. The required relieving rate for any system must be determined from extensive knowledge of the reaction kinetics or can be derived from experimental work. State of the art procedures for obtaining relieving rates and also for determining the behavior of the system have been developed by the AIChE's Design Institute for Emergency Relief Systems (DIERS), and review of their publications should be made for more information on the techniques developed. Overheating can result in overpressure due to reduction of allowable stress. Therefore, the design of systems prone to these incidents must include monitoring and control features to reduce the occurrence of decompositions and runaway reactions in gassy systems since conventional pressure relieving devices cannot normally provide protection

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against these contingencies. Design temperatures for these systems must be specified at a margin above normal operating temperature sufficient to permit the detection of abnormal temperatures and institution of corrective measures by manual or automatic controls, see DP II. Appropriate design features may include feed-forward temperature control, high temperature alarms, and high temperature cutouts. A high temperature cutout may stop feed flow, bypass the high temperature zone, recycle reacted product to dilute the feed, and depressure the unit to atmosphere or a closed system. Where the equipment being protected is susceptible to plugging care must be taken to ensure that depressuring or shutdown facilities will work as intended. S6.11

OVERPRESSURE CAUSED BY ABNORMAL TEMPERATURE The inter-relationship of allowable stresses (and hence design pressure of equipment) and temperature must be considered for operating conditions which may exist during upsets, emergencies, startup or shutdown. The effects of high temperatures in some contingencies are discussed in this section under FIRE AS A CAUSE OF OVERPRESSURE, and OVERPRESSURE CAUSED BY CHEMICAL REACTION. Low temperatures which may result from ambient conditions, autorefrigeration, etc., must also be evaluated to ensure that vessels which may be subjected to temperatures below embrittlement transition temperatures are designed such that allowable stresses under these conditions are not exceeded. This subject is covered in detail in DP II, Design Temperature, Design Pressure and Flange Rating, in GP 18-10-01 and also in Report Nos. EE.11E.84 and EE.89E.89.

S

6.12

OVERPRESSURE CAUSED BY THERMAL EXPANSION

Occurrence of Thermal Expansion Overpressure - Lines or equipment which can be left full of liquid under nonflow conditions and which can be heated while completely blocked-in must have some means of relieving pressure built up by thermal expansion of the contained liquid. Solar radiation, as well as other heat sources, must be considered. Lines or equipment which are hotter than ambient when blocked in and which cannot otherwise be heated above the blocked-in temperature do not need protection against liquid thermal expansion. The following are common examples of some thermal expansion mechanisms. 1. Piping or vessels blocked in while filled with liquid, and subsequently heated by heat tracing, coils, or heat transfer from the atmosphere or other equipment. 2. Piping or vessels blocked in while filled with liquid at or below ambient temperature, and subsequently heated by direct solar radiation. Cryogenic and refrigeration systems must particularly be examined in this respect. Note that as a result of radiative cooling at night it is possible for piping to be cooled 10°F (6°C) or more below the ambient temperature. Similarly, solar radiation can increase piping temperature 20°F (11°C) or more above the ambient temperature. 3. A heat exchanger blocked in on the cold side with flow continuing on the hot side. This situation can sometimes occur during normal operation. For example, consider an exchanger train where plant feed is preheated by exchange with hot products, with the feed flowing from a pump (with a check valve in the discharge) through the exchangers to a flash drum. A level controller on the flash drum operates a control valve between the exchanger train and the flash drum. Thus, if the control valve closes, the feed system is blocked in and subject to thermal expansion. 6.12.1

Overpressure Potential in Piping

The potential for overpressure due to liquid thermal expansion is recognized by codes and standards, for example, ANSI B31.3. However, the magnitude of the pressure rise is not always appreciated. The basic equation for calculating the pressure increase due to thermal expansion in a piping system is as follows: DP =

( DT ) (b - 3a ) - (qt / v ) æ R ö K + ç ÷ (2.5 - 2s ) è Eh ø

Eq. (1)

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where: DP DT b= a= K= E= R= h= s= q= t = v=

Page 52 of 156

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= Pressure increase, psi (kPa) = Temperature increase, ºF (ºC) Coefficient of cubic expansion for the liquid, in.3/(in.3 ºF) [m3/(m3 ºC)] Coefficient of linear expansion for the metal wall, in./(in.-ºF) [m/(m-ºC)] Compressibility of the liquid, in.3/(in.3 psi) [m3/(m3 kPa)] Modulus of elasticity for the metal wall, psi (kPa) Inside radius of the pipe, in. (m) Wall thickness, in. (m) Poisson's ratio, usually 0.3 Liquid leakage rate, in.3/s (m3/s) Elapsed time for leakage, s Pipe volume, in.3 (m3)

This equation accounts for the thermal expansion of the liquid, thermal expansion of the pipe, and leakage out of the trapped section of piping. Typical values for the variables in the above equation are as follows: K, in.3 / (in.3 - psi) [m3 / (m3 - kPa)] Propane Butane Gasoline Diesel Water

CS 2.25 Cr 5 Cr SS

b, in.3 / (in.3 - ºF) [m3 / (m3 - ºC)]

0.189 x 10-4 (2.74 x 10-6) 0.123 x 10-4 (1.78 x 10-6) 0.052 x 10-4 (0.75 x 10-6) 0.044 x 10-4 (0.64 x 10-6) 0.034 x 10-4 (0.49 x 10-6) E, psi [kPa]

0.119 x 10-2 (2.14 x 10-3) 0.085 x 10-2 (1.53 x 10-3) 0.060 x 10-2 (1.08 x 10-3) 0.050 x 10-2 (9.0 x 10-4) 0.024 x 10-2 (4.3 x 10-4)

30 x 106 (207 x 106) 30 x 106 (207 x 106) 28 x 106 (193 x 106) 28 x 106 (193 x 106)

6.0 x 10-6 (1.08 x 10-5) 5.65 x 10-6 (1.02 x 10-5) 5.6 x 10-6 (1.01 x 10-5) 9.0 x 10-6 (1.62 x 10-5)

a, in. / (in. - ºF) [m / (m - ºC)]

Using these values it can be shown that small temperature increases can result in very high pressure rises, depending on the type of liquid trapped. Typical pressure change versus temperature change for an 8 in. CS line without leakage are offered as follows:

Propane Butane Gasoline Diesel Water

DP / DT, psi / ºF

DP / DT, kPa / °C

60 64 98 91 53

745 794 1216 1129 657

Hence, pressure in the several thousands of psi can be achieved with moderate increases in the temperature of the trapped liquid. Leakage from the trapped system alleviates the pressure increase but typical leakage rates, particularly for soft seated valves, are insufficient to prevent a significant pressure rise in the trapped section. For example, to prevent the pressure from increasing in a 1000 ft (300 m) section of 8 in. (200 mm) CS line filled with propane and subjected to a temperature rise of 50°F (27°C), the leakage rate has to be maintained at 0.42 gpm (2.6 x 10-5 m3/sec) over a six hour period. This value is several orders of magnitude higher than the maximum allowable leakage rates in API Std-598 for new valves, which are as follows:

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VALVE TYPE Gate Globe Plug Metal Seated Check All Soft Seated

MAXIMUM LEAKAGE ALLOWED, gpm (m3/sec) 0.0003 0.0003 0.0003 0.0006 0.0 (0)

(1.9 X 10-8) (1.9 X 10-8) (1.9 X 10-8) (3.8 X 10-8)

Even accounting for an in-service increase in leakage rate equivalent to 2 orders of magnitude, the resulting leakage rate may be insufficient to prevent a high pressure from being developed in the example above. Hence, valve leakage can, in general, not prevent excessive pressure due to thermal expansion. Note that in attempting to identify the temperature change versus pressure change, consideration must also be given for a constant pressure source such as a running pump. This type of situation may be normal practice when a pump supplies a number of users at remote distances. For example, if a line was blocked-in against a running pump in the evening at 150 psig (1035 kPa) and 50°F (10°C), and the temperature fell to 32°F (0°C) at night with the pump still running, and the next day the line was heated to 90°F (32°C), the DT is 58°F (32°C) instead of a DT of 40°F (22°C). 6.12.2

Method of Protection Against Liquid Thermal Expansion Overpressure

Protection against thermal expansion overpressure may be provided by the one of the following methods: 1. Installation of a PR valve. 2. Installation of a small permanently open bypass around one of the block valves, per GP 03-02-04. (The bypass should be 1 in. in diameter, with check valve. This method is only applicable where leakage through the bypass is acceptable and not prohibited by regulations.) An alternative to a permanently open bypass could be a drilled hole in all of the block valves (or check valve) as long as leakage is acceptable and accounted for in the design. 3. Procedures ensuring that blocked-in equipment is drained of liquid. Items 2 and 3 may not be permitted by all local codes. In addition, while designing for the maximum pressure that can be developed is an acceptable protection method, it is rarely practical. 6.12.3

Application of Liquid Thermal Expansion Protection

Protection against thermal expansion overpressure should be included for specific applications in accordance with the following: 1. Heat Exchanger - Heat exchangers, where the cooler side can be blocked in full of liquid while the hot side fluid flow continues, must be protected by either: a. A manually operated bleeder valve, plus caution sign, in accordance with GP 03-02-04 when both block valves are located at the exchanger. If both block valves are not at the exchanger, Method b. or c. below must be used. b. A small permanently open bypass around one of the block valves per GP 03-02-04.

2.

c. Installation of a PR valve. If a bypass or PR valve is provided, its capacity must be adequate to relieve any vapor generated from the cold fluid by heat input from the hot side under design flow conditions, credit may be taken for lower heat transfer due to the no-flow condition. Note that a check valve in the piping upstream of the cooler side of an exchanger is considered as a block valve. Piping - Sections of piping in any liquid service, whether onsite or offsite, which can be blocked in while liquid filled and subjected to liquid thermal expansion from subsequent heating, must be protected by one of the following: a. Installation of a PR valve per GP 03-02-04. b. Installation of a small permanently open bypass around one of the block valves, per GP 03-02-04. (The bypass should be 1 in. in diameter, with check valve. This method is only applicable where leakage through

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3.

4.

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2.

3. 4.

5.

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the bypass is acceptable and not prohibited by regulations.) An alternative to a permanently open bypass could be a drilled hole in all of the block valves (or check valve) as long as leakage is acceptable and accounted for in the design. c. Means for withdrawing liquid so that the line does not remain liquid filled (Procedures to require drainage must be in place and enforced). If the process piping is initially hotter than ambient, and there are no means to increase the temperature, such as heat tracing or solar radiation, no protection against thermal expansion is needed. Short sections of piping less than 100 ft (30 m) in length but not exceeding 250 gallons (900 l) in volume which can be blocked in, generally do not need thermal relief valves. If a thermal relief valve is provided, it should relieve to a closed system when possible (may be required to relieve to a closed system by local codes). Vessels - All vessels and equipment which can be blocked in while liquid filled and subjected to subsequent heating and thermal expansion by any of the mechanisms described above with reference to heat exchangers, must be protected by any one of the methods described above for piping, i.e., a. Installation of a PR valve. b. Installation of a small permanently open bypass around one of the block valves. c. Means for withdrawing liquid, generally manual, but requiring well defined procedural safeguards. In cases where vessels are provided with PR valves for protection against overpressure from fire exposure or an operating failure contingency, additional thermal expansion protection is not required. Control Valve - Double-seated control valves are considered to pass sufficient leakage flow that equipment blocked in by such valves need not be provided with thermal expansion protection.

6.12.4 1.

Section

Installation Details for Liquid Thermal Expansion PR Valve

Liquid thermal expansion PR valves (thermal expansion valves) should be specified with a set point as high as possible above operating pressure to avoid inadvertent releases. For vessels, the ASME Code must be followed, which in most instances limits the thermal relief PR valve set pressure to the vessel design pressure. When the thermal relief PR valve is installed only for the protection of piping systems, settings up to the overpressure levels permitted by the ASME B31.3 intermediate term over stress conditions are applicable if local codes permit. Thus, the set pressure of a liquid thermal relief PR valve protecting piping only would be the lower of System Test Pressure or 1.20 times the design pressure of the pipe; considering 1.20 times the design pressure of the flange class. Back pressure must be taken into consideration if the thermal relief PR valve discharges to a closed system, such that the pressure equivalent to the lower of system test pressure or 1.2 times design pressure is not exceeded. The capacity requirement for the PR valve is not easy to determine, although Eq. (1) above can be used to estimate the rate for piping systems. Since the volume to be released in order to relieve pressure is small, a nominal 3/4 in. by 1 in. (20 mm x 25 mm) PR valve is normally specified, particularly where only solar heating is involved. Larger sizes should be considered for long uninsulated above-ground pipelines, and for large liquidfilled vessels or heat exchangers. Pressures generated due to vaporization as well as liquid expansion should not be overlooked. In cases where blocked-in liquids may vaporize at relieving conditions, thermal relief devices should be sized based on potential displacement effects (e.g. displaced liquid or two-phase flow, as well as vapour) as determined from system geometry. The rate of required release is a function of the rate at which the fluid temperature increases. If the rate of temperature rise is not known, the default rate of temperature rise shall be 9°F (5°C) per hour. A thermal expansion PR valve may be installed at any convenient point on the equipment or piping which it is protecting. Availability of a suitable discharge route will determine location in many cases. For onsite locations, thermal expansion PR valves releasing liquid must discharge into a closed system if the liquid within the system is toxic or above its flash point. This may be a flare header or the equipment (or piping) on the opposite side of one of the blocking-in valves. Onsite thermal expansion PR valves releasing liquid may discharge to atmosphere at grade level in a safe location, such as to a dirty water sewer catch basin (as detailed in GP 03-02-04), if the liquid within the system is below 600°F (315°C) and below its flash point. Where permitted by local regulations, material above its flash point may be discharged to a sewer if the amount is small [less than 25 gal. (95 l)], and if the material is heavier than 68° API (710 kg/m3). In offsite locations, thermal expansion PR valves may discharge to a flare header upstream of a knockout drum, if available, or to the equipment (e.g., a tank) on the opposite side of one of the blocking-in valves, or to the

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atmosphere. Atmospheric discharges where permitted by local regulations, must be at grade level in a safe location, as detailed in GP 03-02-04. 6. 7. S

6.13

Thermal expansion PR valves in onsite or offsite locations which release severely toxic fluids (as defined in DP XV-A) must discharge to an appropriate closed system. Each thermal expansion PR valve should be provided with an inlet CSO valve (and an outlet CSO valve in the case of closed discharge) to permit isolation for inspection and testing, if permitted by local codes. VACUUM AS A CAUSE OF EQUIPMENT FAILURE

6.13.1 General Equipment which can operate under a vacuum, either continuously or intermittently, must be designed to withstand partial or full vacuum conditions or otherwise be protected. In some cases, this may include piping as well as vessels or other equipment. Other equipment which does not operate under vacuum, either continuously or intermittently, may be exposed to vacuum inadvertently, by contingencies such as the following: 1. Instrumentation malfunctions. 2. Drainage of nonvolatile liquid from a vessel without atmospheric venting or gas repressuring. 3. Shutting off steam at the completion of steam purging without admitting a noncondensible vapor (e.g., air at shutdown, fuel gas at startup). 4. Maloperation of valves. 5. Low ambient temperatures resulting in subatmospheric vapor pressure of certain materials (e.g., some alcohols, aromatics, C4 and C5) in pressure storage. 6.

7. 8. 9.

Loss of heat input to closed process equipment handling low vapor pressure materials (e.g., fractionation of alcohols and aromatic solvents), while cooling continues such as by a condenser or through heat loss to the atmosphere. Loss of heat input to waste heat boilers with resulting condensation of steam. Loss of heat input to closed process equipment where appreciable quantities of steam are generated, e.g., DEA and MEA regenerators. Overcooling in total condensers.

In some of the above situations, vacuum protection can be provided by the installation of vacuum relief devices, e.g., vacuum relief valves on tanks. In other cases, reliance that no vacuum will be developed is placed on proper operation by the process personnel, e.g., not blocking in a steamed vessel during startup or shutdown. Generally, however, any vacuum condition which can be created during process operation such as abnormal cooling, low ambient temperature, loss of heat or blocked suctions on compressors must be considered in the design. In designing for vacuum, credit may be taken for the fact that a vacuum situation may not create a full vacuum. Thus, not all vessels or equipment need be designed for a 100% vacuum situation. For example, if the vacuum situation is created by a blocked suction in a compressor circuit and the vacuum created is limited to 10 psia (70 kPa absolute) by the compressor characteristics, the system needs only to be designed with a margin as defined in DP II. As a general rule, vacuum relief devices are permitted on offsite atmospheric storage vessels handling clean finished products, since there is essentially no possibility of an internal ignition source. However, vacuum relief instrumentation which permit breaking of a vacuum with inerts or flammable vapors are not permitted as the sole means of protection on process equipment, since they are not judged to be sufficiently reliable to provide adequate protection under all circumstances. Vacuum devices which permit air to enter may be considered, in cases where the equipment does not or cannot contain flammables, e.g., some steam systems. For systems where a flammable atmosphere can develop with the influx of air through a vacuum breaker, instrumentation should be employed to break the vacuum with inert gas or hydrocarbon gas at a higher setting than the vacuum breaker in order to reduce the probability of a flammable mixture in the system. However, since instrumentation is not sufficiently reliable (as noted above), a vacuum breaker must also be provided.

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Design of Equipment to Avoid Failure Under Vacuum

Where equipment is not designed for the appropriate level of vacuum, protection should be provided. In general, vacuum vents and inert or gas repressuring systems are not considered an acceptable alternative to vacuum design for process equipment. Vacuum breakers are difficult to maintain tight and may admit air into the equipment. Repressuring systems may be provided for air in leakage or process reasons, but they are not considered sufficiently reliable for equipment protection. Vacuum vents (air) are, however, used on refrigerated storage vessels for clean products, as a backup to a repressuring and low-pressure compressor shutdown system. This is acceptable, since there is no internal source of ignition and the vacuum vents would function only if the primary vacuum protection (repressuring and compressor shutdown) failed to operate. Also, when vacuum protection is required on pressure vessels such as spheres and spheroids, vacuum relief devices admitting air are acceptable since the possibility of having a flammable mixture is slight and there are no internal ignition sources. In the case of low-pressure fractionation equipment, vacuum design is not required if all of the following can be met: 1. There is an adequately sized atmospheric vacuum relief device to prevent vacuum. 2. There are no pyrophoric materials such as peroxides, acetylides or sulfides, or other internal ignition possibilities such as static present, either normally or through abnormal conditions. 3.

Process temperatures are at least 150°F (83°C) below the autoignition point of the materials handled.

Fractionators which meet the above criteria and, therefore, do not need to be designed for vacuum must, however, also be provided with both of the following: 1. A reliable automatic repressuring system (inert gas or hydrocarbon gas) to minimize the possibility of vacuum conditions occurring. 2. A board-mounted low pressure alarm, set at a positive pressure, and remotely operated control valve (or a motorized block valve with a restriction), so that repressuring gas can be admitted from the control center, should the automatic system fail to function. As a rule, steam systems do not require special vacuum protection, since they are normally capable of withstanding vacuum developed if steam generation should fail and residual steam condense. However, low-pressure steam systems should be verified for potential vacuum failures. Generally, equipment need not be designed for vacuum due to blocking in of a vessel after steaming for shutdown reasons. Reliance is placed on good operations to insure that the vessel or equipment is not bottled up. Also, vacuum design is not required for spheres, spheroids and similar vessels when vacuum conditions result only from draining of water during startup, since good operating practice would require gas displacement or venting. Cone roof atmospheric storage tanks must be provided with either a pressure-vacuum valve or an open vent, depending upon the flash point of the stored product. See GP 09-07-03. S

6.14

EVALUATION OF PRESSURIZATION PATH IN PRESSURE RELIEF DESIGN

The following paragraphs indicate the basis for design of permissible capacity limitation in flow paths through which an item of equipment can be overpressured by a source of high-pressure fluids. 6.14.1

Piping

Credit may be taken for pressure drop and maximum flow through piping which forms a pressurization path to a vessel on which a PR valve is to be installed for overpressure protection. The calculation must be performed for relieving conditions. However, where credit is taken for pressure drop in determining the PR valve setting, it must also be considered that under no-flow conditions pressures will equalize throughout the system at the PR valve relieving pressure. Also, if vapor relief is required through a liquid system, the dynamics of liquid displacement prior to vapor release must be taken into account. For example, in the case of two liquid-filled vessels interconnected by a bottom liquid line with a PR valve on the second vessel, liquid displacement through the interconnecting line may not be sufficient to protect the first vessel if the overpressure is caused by vapor generation.

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Check Valve

A check valve is not effective for preventing overpressure by reverse flow from a high-pressure source. Experience shows 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 the MAWP of the vessel.

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 Valves in Series

1

1

Potential Overpressure Scenario

Partial failure of check valve.

Type of Contingency

Design

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

1

Total failure of check valve.

Remote

Calculate reverse flow rate (liquid and/or vapor) as if the check valve were not there. 3

2 or more

Partial failure of one check valve..

Design

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.

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2 or more

Total failure of one check valve.

Remote

Failed check valve is ignored. . If only two check valves in series are installed, assume the second check valve fails partially open and calculate back flow per Scenario 1. If more than two check valves in series are installed, assume that each of the remaining check valves behaves as a restriction orifice with a diameter equal to 1/10 of the nominal diameter of the check valve.

5

2 or more

Two or more check valves in series fail fully open.

Not credible.

This contingency need not be considered. When credit is taken for the presence of check valves in the pressurization path, the check valve(s) should be of different design (to avoid common cause failure modes) and should be identified as safety critical for maintenance and inspection purposes. 6.14.3

Restrictions

In general, restrictions, either a specially designed spool piece or a restriction orifice, should not be used as a means of limiting the capacity of a pressurization path. In special cases, where large incentives (such as reducing the size of the flare system) apply, a restriction may be used, provided that all the following conditions are satisfied: 1. A warning against unauthorized removal is provided by means of the following: a. A warning sign plate welded to the restriction, and b. A note in the relevant documentation (specification, flow diagrams, operating manuals, etc.) is provided. 2. Concentric reducers are installed upstream and downstream of any restriction spool piece used. These reducers minimize turbulence, erosion, and noise. 3. Physical means of preventing inadvertent removal of the restriction orifice, if used, (for example welding to the adjacent piping flange), must be provided. 4. The installation of the restriction is reviewed by the appropriate safety group, e.g., site SOC. 5. The restriction orifice must be inspected at turnaround to define if enlargement has occurred. 6. The restriction orifice is mechanically designed for a differential pressure equal to the upstream design pressure. The use of a spool piece is preferred over a restriction orifice because it minimizes the risk of the required restriction being removed permanently, and its effectiveness is not reduced as a result of erosion or damage during normal operation. The restriction spool piece should also reduce vibration and noise relative to a restriction orifice. 6.14.4

Control Valve

Refer to Failure of Automatic Control, elsewhere in this Section, for a discussion of the analysis of failures of individual control valves in the full open position. A control valve with a limit stop to restrict the maximum opening is not acceptable as a means of limiting the capacity of a pressurizing path, since the stop may later be removed or the

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valve changed. Credit for the limiting capacity of a control valve in the wide open position may be taken if either of the following conditions apply: 1. The flow rate through the fully open control valve and its bypass (if any) determined as specified under Failure of Automatic Control does not exceed 75% of the rated capacity of the pressure relief device protecting the downstream equipment. 2. A permanent sign is attached to the valve body or adjacent piping warning against replacing the control valve or its bypass valve (if any) with larger capacity ones unless the downstream overpressure protection facilities are checked for the increased relief capacity resulting from the change, and a similar warning is included in the specification sheets, operating manuals, P&I Diagrams and other relevant documents. S

6.15

EVALUATION OF ESCAPE PATH IN PRESSURE RELIEF DESIGN

The following paragraphs cover the basis for design of permissible escape paths when considering overpressure contingencies. 6.15.1

Grouping of Interconnected Vessels

Two or more pressure vessels connected by piping may be considered as a single unit for pressure relief purposes, subject to the conditions listed below. If these conditions are satisfied, then pressure-relieving facilities for the group may be located on any one of the vessels or on the interconnecting piping. However, pressure drops through the system under relieving conditions must be such that no vessel in the group is exposed to more than its design pressure (plus permissible accumulation) during any design contingency. (See EVALUATION OF PRESSURIZATION PATH IN PRESSURE RELIEF DESIGN above.) In addition, to meet code requirements the PR valve must open before the pressure anywhere in the system being protected exceeds the design pressure. In evaluating the relieving rates for fire when a group of vessels is considered as a single unit for pressure relief purposes, fire exposure must be assumed on vessels in the group which are in the same fire risk area. (See discussion of fire risk area under FIRE AS A CAUSE OF OVERPRESSURE.) 6.15.2

Heat Exchanger Tube Failure

The requirements applicable to different piping system components (valves, orifices, etc.) also apply to escape paths required on the low pressure side of heat exchangers to prevent overpressure in the event of tube failure. Refer also to Heat Exchanger Tube Failure previously discussed and in GP 03-02-04. 6.15.3

Piping for Interconnecting Vessels and Pressure Relief Facilities

Piping must be of adequate capacity to handle cumulative relieving rates through the system arising from any design contingency. A special situation occurs with submerged condensers, where the condenser outlet is usually below the normal liquid level in a distillate drum. If a fire occurs near the drum, heat input to the drum will make the pressure rise in the tower-drum system. When the PR valve on the tower blows, flow will be out of the drum, forcing liquid up the tower overhead line. If heat input to the drum continues, considerable liquid static head may build up in the overhead line. This depends, of course, on drum volume and the vertical length of the overhead line. If this pressure increase can be greater than 21% of the drum design pressure, then either a safety valve must be installed on the drum or the drum design pressure must be increased. 6.15.4

Car-Sealed Open Valve

Unless prohibited by local codes, car-sealed open (CSO) block valves are permissible in pressure relieving escape paths, provided that the contingency of closing the CSO valve does not cause any equipment to exceed the “1.5 Times Design Pressure Rule." This does not apply to CSO valves at the inlet and/or outlet of pressure relief devices intended to isolate the pressure relief device for maintenance, or to CSO valves installed in flare headers for the isolation of individual branches during plant turnarounds, since closure of such valves does not result in immediate overpressure and is controlled by administrative procedures. The requirements for CSO valves are as follows:

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2.

3.

4.

5. 6.

7.

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Car sealing is a means of ensuring the correct positioning of a block valve and should be used only where the full open position is an essential part of a pressure relief system or escape path. A CSO valve should not be used for process convenience, but confined to safety applications. CSO valves must be line size full port hand-operated ball, gate or plug valves (motor and air operated block valves may not be considered CSO valves). In some instances, flare lines for example, high performance butterfly valves may be used in CSO service. In this service, a butterfly valve must be specified to a rigorous set of standards which must include such items as: the disc must be a fail open design; shaft seals must be packing gland type; operator to shaft connection must not allow a failure mode to permit disc to rotate freely; bearings shall be external shaft type; disc will have a position indicator; a stop bar will be installed to prevent rotation beyond full open; sweeping steam ports for flushing seats will be provided; guaranteed low flow pressure drop in open position; and bubble tight seat shutoff. The Mechanical Engineering Section of ExxonMobil Engineering should be consulted to design details of these high performance butterfly valves. CSO valves must have no significant cross-sectional area restriction or obstruction in the open position. The pressure drop across the valve must be taken into account in defining design pressures and the PR valve set pressure. Gate valves must be installed with the stem oriented in the horizontal position (preferred in freezing climates), or with the stem oriented below the horizontal. This requirement reduces the possibility of a dropped gate obstructing flow. CSO valves should be painted a distinctive color, normally yellow. Plastic car seals or wire with lead seals may be used. Each plant must establish an effective procedure and policy for regular checking and logging of car seals. Breaking of car seals should be permitted only by authorized persons. Where double block valves are required for tight shut-off, both valves should be CSO.

6.15.5

Car-Sealed Closed Valve

In certain cases it may be necessary to use car sealed closed (CSC) valves, such as in a bypass around a fuel gas control valve used for fired heater flameout protection. The bypass is provided so that the automatic shutdown system can be periodically checked for operation. Where CSC valves are used for other purposes, they are also limited to applications where inadvertent opening of the CSC valve is treated as a remote contingency. 6.15.6

Control Valve

Use of a control valve in a pressure relief escape path is generally not permitted. By way of exception, a control valve may be permitted in the process flow path which serves as the pressure-relieving path of the low-pressure side of a heat exchanger during a tube failure incident. However, the system must be thoroughly analyzed to ensure that overpressure cannot occur (see earlier discussion of Heat Exchanger Split Tube and Tube Leakage for conditions). In some unique cases where large incentives apply, such as fluid catalytic cracking unit regenerator flue gas valves, a control valve with a minimum opening feature may be used, subject to ALL of the following conditions: 1.

The minimum opening, which may be a hole or cut out in the valve disc or plug, must be sized to pass the design-relieving rate without overpressuring any equipment. Limit stops on valve stem movement are not an acceptable means of ensuring the minimum opening. 2. The fact that the minimum opening feature is included for pressure relief, and must not be changed, should be clearly noted in relevant documentation (specification sheets, mechanical catalog, flow diagrams, operating manual, etc.) and a warning sign plate should be welded to the valve body. 3. The installation should be reviewed by the appropriate safety group, e.g., sit SOC. A three-way control valve which splits or combines two flows in a pressure relieving path is acceptable provided there is an adequate relieving path available in all valve positions. It is preferred that the outlet(s) total open cross sectional area is equal or greater than the inlet path(s) area in all valve positions. However, if the cross sectional area of the three-way control valve is smaller than the cross sectional area of the adjacent piping, the additional pressure drop caused by the presence of the three-way control valve must be taken into account in the design of the pressure relief system.

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Two two-way butterfly valves splitting or combining flow in a pressure-relieving path are acceptable if ALL of the following conditions are satisfied: 1. Three-way control valves are NOT available in the size required. 2.

3. 4. 5. 6. 7.

The valve stems in the two-way butterfly valves are mechanically linked such that one valve opens when the other closes. The mechanical linkage must be durable and sufficiently rugged to prevent damage in normal use or during maintenance. A single actuator manipulates both valves. The design of the mechanical linkage device and the mounting is carried out by the valve manufacturer. The smaller of the butterfly valves must have an adequate relieving area. All equipment upstream of the two-way butterfly valves satisfy the “1.5 Times Design Pressure Rule" if both twoway valves were to close. A sign is affixed to the valves prohibiting the removal of the linkage.

Note that electrical, pneumatic, or logic interlocked two-way control valves are not an acceptable alternative to mechanically linked two-way butterfly valves to meeting the above requirements. 6.15.7

Flow Meter Orifice Plate

A flow meter orifice plate is permissible in a normal process flow pressure relieving path, provided that it can pass the required emergency flow without exceeding pressure limits of the upstream equipment. However, it is not acceptable in PR valve inlets and flare headers. 6.15.8

Check Valve

A check valve is acceptable in a process pressure-relieving path, provided that: 1. The valve opens in the pressure relieving direction, and 2. The check valve is in a normally flowing line (i.e., normally open), and 3. The valve is of the swing-check or wafer (where acceptable per GP 03-12-01) type with no external actuation or damper mechanism, and 4. The pressure drop is included in the system analysis. A check valve is not, however, permissible in PR valve inlet or outlet piping, or in any flare or PR valve header. 6.15.9

Flow Restriction in Relieving Path Through Equipment

The potential for a flow restriction in a pressure relieving path caused by coke formation, loosened refractory lining materials, catalyst fines, plugged catalyst beds, collapsed vessel internals, etc., must be evaluated, considering the equipment design details and operating experience in similar plants. If the occurrence of such restrictions can be anticipated, the pressure relieving facilities must be added upstream of the potential restriction. If the restriction is considered a remote contingency, then the “1.5 Times Design Pressure Rule" may be applied. The inclusion of special instrumentation (e.g., high-pressure alarms, pressure drop alarming, and recorders, etc.) may be used to reduce the likelihood of an unforeseen occurrence but not to eliminate the contingency. Discharge of pressure relieving flows through auxiliary equipment which provides an open path to the atmosphere (e.g., the regenerator flue gas system on catalytic cracking units, or the barometric condenser tail pipe and vent on a vacuum tower) must be similarly evaluated in terms of the possibility of internal restrictions. 6.15.10 Flame Arresters, Detonation Arresters, and Demisting Screens Flame and/or detonation arresters are not permitted in a pressure-relieving path. Except in flare blow down and seal drums, demisting or crinkle wire mesh screens (CWMS) are acceptable in a pressure relief path, provided the criteria listed below are followed:

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·

If the service is non-plugging as determined by prior operating experience, a pressure relief device (PRD) may be located above the CWMS, although the preferred location is below the CWMS.

·

If the process is known to have plugging tendencies or the plugging tendency is unknown (i.e., a new process), a PRD must be installed below the CWMS.

·

In all cases, but particularly if the PRD is located above the CWMS, the screen must be installed securely and in accordance with GP 05-02-01. If the screen is not installed in accordance with GP 05-02-01, or the method of installation is unknown, the potential for mechanical failure resulting in plugging of the path to the PRD should be considered within the remote contingency basis.

6.15.11 Parallel Flow Paths When two or more parallel flow paths exist between the protected equipment and the pressure relief device, and one or more of the flow paths can be individually blocked, credit may be taken for the capacity of the remaining open flow path(s) for overpressure protection. The following guidelines apply: a.

If blocking one of the parallel flow paths causes the equipment pressure to exceed 1.5 times the MAWP or the proof test pressure, whichever is lower, either the block valves shall be removed or a pressure relief valve shall be provided to protect the equipment.

b.

If blocking two parallel flow paths causes the equipment pressure to exceed 1.5 times the MAWP or the proof test pressure, whichever is lower, either the block valves shall be removed or a pressure relief valve shall be provided to protect the equipment. This guideline recognizes that any two parallel paths could be blocked simultaneously due to operator error. For example, an operator could mistakenly block the inlets and/or outlets of two parallel paths instead of the inlet and outlet of one path, or block an open path before opening a previously isolated path.

c.

If neither condition (a or b) applies, two options are available: 1.

The inlets and outlets of all of the parallel flow paths shall have their isolation block valves car-sealed open (CSO), OR

2.

Determine the minimum number of parallel flow paths, N, that must remain open to prevent the protected equipment pressure from exceeding its MAWP, and car-seal open the isolation block valves of N+1 paths. If this option is selected, there must be a safety critical written procedure or mechanical interlocks to ensure that at least N+1 parallel paths have their isolation valves CSO at all times.

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7 DESIGN PROCEDURE, PART II PRESSURE RELIEF DEVICES This part of the Design Procedure describes the various pressure relief devices that are available, with their characteristics and criteria for selection. Calculation procedures for sizing PR valves are covered in PART III of the Design Procedure.

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7.1

CONVENTIONAL PRESSURE RELIEF VALVE

The pressure relief device used for the majority of refinery and chemical plant equipment is the spring-loaded, topguided, high-lift, nozzle-type pressure relief valve, which is illustrated in Figure II-1. The spring is usually external and enclosed by a bonnet for weather protection, and the bonnet chamber is vented through an internal passage to the valve outlet. 7.1.1

General Operation and Characteristics

The operation and characteristics of a conventional pressure relief valve are shown diagrammatically in Figure II-2. The action of the valve as pressure rises from the initial normal operating pressure (assuming no back pressure) is described below. The effect of back pressure on PR valve operation is described later. 1. In spring operated PR valves, significant leakage between the valve seat and disc (“simmer”) typically occurs at about 95% of set pressure. However, depending upon valve maintenance, seating type, and condition, simmerfree operation may be possible at up to 98% of set pressure. Simmer is due to the progressively decreasing net closing force acting on the disc (spring pressure minus internal pressure).

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As the operating pressure rises, the resulting force on the valve disc increases, opposing the spring force, until at the set pressure (normally adjusted to equal the vessel design pressure) the forces on the disc are balanced and the disc starts to lift. As the vessel pressure continues to rise above set pressure, the spring is further compressed until the disc is at full lift. The valve is designed to pass its rated capacity at the maximum allowable accumulation. For contingencies other than fire, the maximum allowable accumulation is 10% of the maximum allowable working pressure or 3 psi (20.7 kPa), whichever is greater if a single pressure relief valve is provided. If multiple relief valves are provided the allowable accumulation is 16% of maximum allowable working pressure or 4 psi (27.6 kPa), whichever is greater, unless local codes dictate otherwise. For fire, the allowable accumulation is 21% of maximum allowable working pressure. Following a reduction of vessel pressure, the disc returns under the action of the spring but reseats at a pressure lower than set pressure by an amount termed the blowdown (4 to 8% of set pressure). The blowdown may be adjusted within certain limits, by various means recommended by the valve vendor or manufacturer, to provide a longer or shorter blowdown.

7.1.2

Valve Opening Characteristics for Vapor Service

Pressure relief valves for vapor service (i.e., safety valves and safety relief valves) are specifically designed for “pop" action. That is, they move to the full open position at only a slight overpressure, the valve remaining fully open as overpressure builds up to the permissible maximum, at which condition the rated quantity is discharged. This “pop" characteristic is achieved by a secondary annular orifice formed outside the disc-to-nozzle seat. This causes additional disc area to be exposed to the operating pressure as soon as a slight lift occurs, accelerating the opening movement. The kinetic energy of the flowing vapor, by action between the valve disc holder and the blowdown ring, adds to the opening force and causes the valve to “pop" open. This flowing kinetic energy also continues to act against the spring force as the fluid pressure returns to the pressure relief valve setting. This accounts for the fact that the PR valve reseats at a lower pressure than the set pressure, i.e., blowdown. As typically designed, vapor flow through a typical high-lift pressure relief valve is characterized by limiting sonic velocity and critical flow pressure conditions at the orifice (nozzle throat), and for a given orifice size and gas composition, mass flow is directly proportional to the absolute upstream pressure. Sizing calculation procedures are described in PART III of the Design Procedure. 7.1.3

ç

ç

Valve Opening Characteristics For Liquid Service

Pressure relief valves in liquid service (i.e., relief valves and safety relief valves) have the characteristic of progressively increasing lift with rising inlet pressure until the full open position is reached. The pressure required to achieve full lift varies depending on the PR valve design, as follows: 1. Relief valves, since 1985, are required by the ASME to have capacity certification and achieve full lift at no more than 10% overpressure. To avoid potential chattering problems, capacity certified relief valves are recommended for services in which the relieving fluid is either a non-flashing liquid or a sub-cooled liquid that flashes downstream of the PRV nozzle under all or some contingencies. They are also required by the ASME Code for vessels that operate completely filled with liquid, such as desalters or coalescers. These valves are not recommended for services in which all of the contingencies involve the flow of vapor or a vapor/liquid mixture through the PRV nozzle (gas/vapor, saturated liquid or slightly subcooled liquid at the PRV inlet). When capacity certified relief valves are used in services where some contingencies involve the flow of vapor or a vapor/liquid mixture through the PRV nozzle, the reseating pressure may be as low as 78 – 80% of the set pressure (20-22% blowdown). The long blowdown may not be acceptable in some installations since it would require dropping the system pressure significantly below operating pressure to achieve reclosure of the PR valve. The long blowdown is usually not a concern when the contingency requiring the relief of vapor/gas/twophases is fire, but it may be unacceptable for other contingencies involving vapor or vapor/liquid flow. Some valve manufacturers offer capacity-certified liquid-trim valves with reseating pressures in the range of 88 – 93% of set pressure (7 – 12% blowdown). For cases when the blowdown of a capacity-certified valve is not acceptable in vapor or vapor/liquid service, consideration should be given to the use of a modulating-action pilotoperated PRV.

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7.2

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Safety relief valves (and also relief valves built prior to 1985) are not capacity certified for liquid service and full lift (in liquid service) is achieved at 25% overpressure. Safety relief valves should be used in any service where the relieved material is a gas, vapor or gas/vapor/liquid mixture as it flows through the PRV nozzle under all contingencies. If a safety relief valve (or a relief valve built prior to 1985) is used for a service involving flow of liquid through the PRV nozzle, its rated liquid capacity at 25% overpressure must be multiplied by a correction factor to account for the difference between the 25% overpressure required for full lift and the maximum accumulation allowed by the vessel design code. This is discussed under DESIGN PROCEDURE – PART III. BALANCED BELLOWS PRESSURE RELIEF VALVE

Balanced bellows pressure relief valves are similar to conventional PR valves but incorporate a bellows as a means of minimizing the effect of back pressure on the PR valve performance. A typical balanced bellows PR valve is illustrated in Figure II-5. 7.2.1

Application

Balanced bellows PR valves should be specified where any of the following apply: 1. Excessive fluctuation in superimposed back pressures. (Where back pressures fluctuate on a conventional valve, the valve may open at too low a pressure or permit the vessel pressure to exceed the equipment rating, depending upon back pressure fluctuation and spring pressure adjustment.) 2. The built up back pressure exceeds 10% of the set pressure, based on psig; or it exceeds 21% of set pressure in the case of fire. 3. The service is fouling or corrosive, since the bellows shields the spring from process fluid. Note, however, that the bellows convolutions could corrode in corrosive service or foul in extremely viscous service, such as asphalt, limiting the lift of the valve unless the valve is heated and insulated. Although the bellows PR valve has the advantage of compensating for a higher back pressure than the conventional valve can, it should be recognized that the bellows is inherently a point of mechanical weakness which introduces some degree of additional risk, in case the bellows should fail and release process fluids through the vent. They should be avoided in services where the process temperature exceeds the auto-ignition point. ç

The use of balanced bellows valves is not recommended in cold or auto-refrigerating services due to the potential for ice formation around the spring, bellows and other internal components which could interfere with the opening and/or reseating of the valve. Since the valve bonnet on a balanced bellows valve must be open to the atmosphere, it is constantly exposed to atmospheric humidity, thereby creating the potential for condensation and ice formation in the event of a cold or autorefrigerating release. If a balanced bellows valve must be used for such services, a steamjacketed or equivalent heat-traced design should be considered. 7.2.2

Back Pressure Limitations

Balanced bellows PR valves may be used satisfactorily in vapor and liquid service with a back pressure (superimposed plus built-up) as high as 50% of set pressure. The back pressure must be incorporated in the sizing calculation as detailed in PART III - PRESSURE RELIEF VALVE SIZING AND SPECIFICATION PROCEDURES. In retrofits it may be acceptable for total back pressure to exceed 50% of set pressure. In such cases the valve manufacturer should be contacted to establish the reduction in capacity due to the high back pressure for the particular PR valve involved. In no case should the total back pressure exceed 75% of set pressure. In addition to the above back pressure limitations based on valve capacity, balanced bellows PR valves are also subject to back pressure limitations based on the mechanical strength of the bellows, bellows bonnet, or the valve outlet flange rating. The evaluation of these mechanical limitations is described in PART III of this Design Procedure, and the back pressure specified for the valve is governed by the lowest back pressure permitted by these various criteria. 7.2.3

Bonnet Venting on Bellows Valves

In order to achieve the required balancing of the valve disc, the interior of the bellows must be vented through the bonnet chamber to the atmosphere. A 3/8 to 3/4 in. (10 to 20 mm) diameter vent hole is provided in the bonnet for

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this purpose. Thus, any bellows failure or leakage will permit process fluid from the discharge side of the valve to be released through the vent. Venting arrangements must therefore be carefully selected and designed to meet the following requirements: 1. Manufacturer's shipping plugs must be removed from the bonnet vent holes before a new valve is commissioned. 2. Typical bonnet venting arrangements for bellows valves are presented in Figures 1-1 through 1-4 of GP 03-0204. Selection is based on the characteristics of the fluid released in the event of bellows failure as follows: Low Toxicity

3.

High Toxicity

Vapor

Figure 1-1

Figure 1-2

Liquid (Design Contingency)

Figure 1-3

Figure 1-4

Liquid (Remote Contingency)

Figure 1-1

Figure 1-2

Combined Vapor Plus Liquid

Figure 1-4

Figure 1-4

The design specification should include a note specifying the applicable figure for each specific service. Although venting to the atmosphere as described in Item 2 is preferred, an alternative is to tie into a closed lowpressure system, if available. This method may be used in the case of severely toxic fluids. Minimum length vent piping should be used. The effects of any back pressure must be thoroughly examined, since in such a case, superimposed back pressure is additive to the spring force and the PR valve may not be truly balanced. (Consult with the appropriate safety group.)

A guideline for calculation of the amount which can be released through a failed bellows is as follows: To calculate the amount which can be released from a balanced bellows PRV bellows failure, the limiting factor may be the space between the valve stem and guide. For example, on a Consolidated valve, J orifice, using the most conservative numbers, minimum stem diameter (0.993 in.) and guide maximum diameter (1.001 in.) the open area would be 0.0125 sq. in. Some other Consolidated valves are: M orifice, stem minimum 1.743 in., guide maximum 1.751 in.: area = 0.0219 in. sq. R. orifice, stem minimum 3.986 in., guide maximum 4.001 in.: area = 0.0941 in. sq. Using a “J" orifice as a conservative basis, the leakage rate through a failed bellows may be calculated using an orifice area = 1% of the selected valve's area. The rates from a failed bellows should be reviewed under other system blow-down cases as well as a relief from the PRV which has the assumed failed bellows. Other contingencies, especially any which might result in liquid out the bellows also need to be considered. S

7.3

PILOT-OPERATED PRESSURE RELIEF VALVE

7.3.1

Operating Characteristics

Pilot operated PR valves are characterized by having a main valve combined with and controlled by a self-actuated auxiliary PR valve (or pilot valve). A typical pilot-operated PR valve is illustrated in Figure II-6 and its operation is illustrated in Figure II-7. The major distinctive characteristic of pilot operated PR valves is that instead of a spring to keep the valve closed, the process pressure is used. Under normal operating conditions, the vessel pressure acts on the main valve seat at the bottom of the free-floating differential area piston or a flexible diaphragm, and by means of the pilot supply line is also applied to the top of the piston (or diaphragm) and under the pilot valve disc. Since the top area of the piston (or diaphragm) is larger than the nozzle area at the lower end of the piston (or diaphragm), there is a large net load holding the piston down on the nozzle. Under static conditions, this net downward sealing load increases as the vessel pressure increases and the valve approaches the set point. This is in contrast to the conventional spring-loaded valve, where the net force on the seat is reduced and the PR valve usually begins to simmer as the set point is approached. In spring operated PR valves, significant simmer occurs at about 95% of set pressure. Some simmer does occur in pilot operated PR valves as a result of the seating surfaces not being perfectly flat and mating with each other, but significant simmer does not occur until the pressure reaches about 98% of the set pressure. When the set pressure of the pilot is reached, it opens and depressurizes the volume above the piston (or diaphragm), either to the atmosphere or into the discharge header, thus reducing the load on the top of the piston (or diaphragm) to the point where the upward force on the seat can overcome the downward loading. This causes lifting of the piston (or diaphragm) to its full open position.

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The pilot valve itself is available in a variety of designs, all of which are essentially similar in operation to springloaded PR valves. The most common design is a non-flowing pilot valve which, once the top cavity of the piston (or diaphragm) is depressured, prevents continued venting of the process fluid. Earlier designs used flowing pilot valves in which there was continued venting of the process fluid through the pilot valve until the blowdown pressure was reached and the valve reclosed. The flowing type pilot is more prone to plugging and should not be used. In addition, the pilot valve can be designed for pop action, in which the pressure on top of the piston (or diaphragm) is vented fully when the pilot valve opens. This results in the main valve opening fully. Alternatively, the pilot may be designed for modulating action, in which the pilot valve only partially vents the top of the piston, enough to satisfy the required relieving capacity and the main valve may not reach full lift. In general, pop action is preferred in order to achieve the required relieving rate quickly. However, modulating action type valves can be used to reduce the chattering tendency as a result of a wide range of relieving rates from different contingencies. When the predetermined system blowdown pressure is reached which is adjustable at the pilot valve, the pilot valve closes, full system pressure is restored to the dome above the piston (or diaphragm), and the piston (or diaphragm) is quickly moved to the closed position. 7.3.2

Pilot Sensing Point Location

The pilot valve pressure sensing point may be located in the main valve inlet neck, or remote from the valve inlet neck such as on the shell of the vessel being protected. The valve is less affected by inlet piping pressure drop in the latter case, as described below. Some non-fire sizing basis examples of this type of an installation might be on the outlet of an air blower for a regenerator (sensor on regenerator with valve on blower outlet) or on a steam reboiler for a tower (sensor on tower, pilot-operated valve on steam inlet to reboiler). 7.3.3 ç

Pilot Sensing Point Lines

Pilot sensing lines should be adequately sized to prevent plugging and should be sloped such that they are self draining. Any valves on the sensing line shall be car-sealed open (CSO) and shall be of a design that minimizes the risk of accidental closure (i.e., avoid use of quarter-turn valves unless their handles are removed). 7.3.4

Pilot Operated Valve Accessories

A backflow preventer should be specified if the superimposed back pressure can exceed the pressure of the protected system during upsets or abnormal operation. In determining the need for a backflow preventer, consideration should be given to the possibility of abnormally low pressures or vacuum in the protected equipment, as well as to the variability of the discharge pressure. Details of accessories that may be included in a pilot-operated valve, such as backflow preventers, field testing connections, pilot line filters and purge, manual or remote opening for depressuring purposes, etc may be obtained from manufacturers' literature. 7.3.5

Advantages

The advantages of pilot-operated PR valves are as follows: 1. A pilot-operated valve is capable of operation at close to the set point and remains closed without simmer until the inlet pressure reaches above 98% of the set pressure. This relative freedom from simmer in the main valve may be taken advantage of in retrofit situations where a lower than a normal margin between operating and set pressures is desired. 2. Once the set pressure is reached, the valve opens fully if a pop action pilot is used. The valve remains open as long as the set point is exceeded. Because the pilot operated valve is slower acting, it may be less subjective to chattering during cyclic service. A modulating pilot valve may also be considered where chattering is a potential problem. 3. If the pilot valve pressure tapping is taken directly from the vessel being protected (upstream of any inlet piping restrictions) a pilot-operated valve is less subject to the chattering which is normally associated with high pressure drop inlet piping. However, it is still desirable to design inlet piping for a maximum frictional pressure drop of 3% of set pressure, since some instances have been reported of resonance and chatter when higher pressure drops have been measured.

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When the pilot exhausts to the atmosphere, a pilot-operated PR valve is fully balanced. Like the balanced bellows PR valve, its opening pressure is unaffected by back pressure, and high built-up back pressure does not result in chattering. No decrease in capacity occurs as long as flow through the valve is critical, (i.e., Kb = 1.0 for critical service see Par. III of this DP). When balanced (pilot valve discharges to atmosphere), pilot-operated PR valves may be satisfactorily used in vapor or liquid services up to a maximum back pressure (superimposed plus built-up) of 90% of set pressure, provided that the back pressure is incorporated into the sizing calculation, as detailed in PART III of this Design Procedure. At higher back pressures, capacity becomes increasingly sensitive to small changes in back pressure and is difficult to predict. Typical back pressure correction factors for use in preliminary sizing are presented in Figure III-2A. The value of the back pressure correction factor for use in final sizing should be obtained from the valve manufacturer. A pilot operated valve is sufficiently positive in action to be used as a depressuring device. By using a hand valve, a control valve or a solenoid valve to exhaust the piston chamber, the pilot-operated PR valve can be made to open and close at pressures below its set point from any remote location, without affecting its operation as a pressure relief valve. Pilot-operated PR valves can be specified for blowdown as low as 2%. This is an advantage for main gas pipeline and pressure storage applications, where the narrow range of pressure cycling minimizes product losses resulting from a release. For applications involving unusually high superimposed back pressure, a pilot-operated valve may be the only possible balanced valve that is commercially available, because of the mechanical limitations which apply to bellows.

7.3.6

Disadvantages

Pilot-operated PR valves are subject to the following disadvantages: 1. They are not recommended for dirty or fouling services, because of plugging of the pilot valve and small-bore pressure-sensing lines. If the pilot valve or pilot connections become fouled, the valve will not open. In special cases where fouling is a function of entrained solids, this limitation may be countered by the use of a non-flowing pilot valve and a pilot line filter. With a non-flowing pilot valve, there is no flow in the pilot system when the valve opens and, therefore, solids entrainment is reduced. Blowback with a suitable fluid can also be used to reduce solids entrainment in the sensing line. 2.

3. 4.

5. 6.

They are normally limited to a maximum inlet temperature of 450°F (280°C) by the “O" ring piston seals. Newer designs are available for a maximum inlet temperature of about 1000°F (538°C) in a limited number of valve sizes and for a limited range of set pressures. “O" ring piston seals must also be compatible with the process fluid. Vapor condensation and liquid accumulation above the piston (or diaphragm) may cause the valve to malfunction since it may interfere with adequate lift unless special designs are used. Back pressure, if it exceeds the process pressure under any circumstance (such as during start-up or shutdown), would result in the main valve opening (due to exerting pressure on the underside of the piston/diaphragm that protrudes beyond the seat) and flow of material from the discharge backwards through the valve and into the process vessel. To prevent this a special device (called a backflow preventer) must be installed in the pilot operated PR valve. In smaller sizes, pilot operated PR valves are more costly than spring operated PR valves. Pilot operated PR valves can be provided with a connection to permit both the pilot pop and reseat pressures to be checked while the valve is in service. As with spring operated PR valves, on-line tests are not recommended since opening the valve periodically is needed to verify that fouling will not limit relief.

7.3.7

Applications

Pilot operated PR valves are limited to reasonably clean services, where they are an acceptable alternative to bellows type PR valves if balanced characteristics are required. Most installations should use non-flowing pilot valves (to limit fouling and venting of process fluid), and be provided with backflow preventers if the PR valve discharges to a closed system.

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Venting of Pilot Vents

Where free flowing pilot vents or where there is a potential for a failure, i.e., diaphragm, “O" ring, etc., resulting in a release to the atmosphere with problems similar to balanced bellows vents, e.g., auto ignition, toxics release, vents should be installed as per balanced bellows vents. See GP 03-02-04. 7.4

EFFECT OF BACK PRESSURE ON PRESSURE RELIEF VALVE

Reference should be made to the beginning of this section for definitions of superimposed and built-up back pressure. 7.4.1

Back Pressure Effects on Valves

The effects of back pressure on PR valves and appropriate design considerations are described below. Figure II-3 illustrates the forces acting on the valve discs of typical conventional and balanced bellows pressure relief valves. 1. The existence of any superimposed back pressure on the top of a conventional PR valve disc exerts a closing force, in addition to the spring force, which opposes the opening force of the vessel pressure on the valve disc. The effect of superimposed back pressure would be to raise the set pressure if allowance for it were not made in the spring setting. 2. By acting on the top of a conventional PR valve disc while in an open or partially open position, the existence of any back pressure exerts a closing force and results in reduced valve lift, and hence reduced discharge rate, assuming that the other variables remain unchanged. 3. Excessive built-up back pressure acting on the top of the disc of a conventional PR valve may result in chattering, as described later in this section. 4. Back pressure reduces the pressure drop across the orifice of any type of PR valve. This results in reduced discharge rates in the case of vapors, if the back pressure exceeds the critical flow pressure. For liquids, any back pressure reduces the DP and results in a lower discharge rate. 5. A balanced bellows PR valve is one in which the closing force exerted by back pressure on the top of the valve disc and the pressure exerted on the bottom of the disc are approximately balanced, thus canceling each other. The bellows shields the top of the disc from back pressure and the bellows area is vented to the atmosphere (or a suitable low pressure closed system) via the bonnet vent (refer to detailed description under the heading, BALANCED BELLOWS PRESSURE RELIEF VALVE). 6. In the case of a pilot-operated valve, provided that the pilot valve exhausts to the atmosphere, the main piston is independent of back pressure and is thus also considered as a balanced valve (refer to discussion of PILOTOPERATED PRESSURE RELIEF VALVE). Balanced PR valves are, therefore, characterized by the following: 1. Opening pressure is unaffected by back pressure. 2. They are less susceptible to chattering from built-up back pressure. 3. Valve capacity is affected by back pressure similar to conventional PR valves. 7.4.2

Back Pressure Factors in Pressure Relief Valve Design

Back pressure is included as a factor in PR valve selection and sizing in accordance with the following: 1. Conventional PR valves subject to a constant superimposed back pressure are designed so that they will open at the required set pressure, by appropriate reduction in spring pressure. 2. Conventional PR valves that are exposed to variable superimposed back pressure will open at correspondingly variable pressure, since the superimposed back pressure is additive to the spring force. 3. Balanced PR valves need no reduction in spring pressure to compensate for superimposed back pressure, and they can tolerate variable superimposed back pressure without an effect on opening pressure. 4. Conventional PR valves and discharge systems must be designed such that built-up back pressure for non-fire contingencies, at the PR valve rated capacity (i.e., the capacity of the PR valve at the fully open position and the specified accumulated pressure) does not exceed 10% of set pressure (both measured in gage pressure), to avoid chattering problems. At higher levels of back pressure, the PR valve will, in general, be unstable in the

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open position and will tend to reclose. In the case where a pressure relief valve system is sized for fire conditions, with 21% overpressure, built-up back pressure at the PR valve design capacity up to 21% of set pressure is permissible. However, the lower rates resulting from other contingencies still must meet the 10% limitation. Balanced PR valves need not be restricted to the same built-up back pressure limit as are conventional valves, since they are not subject to chattering from this cause. However, maximum back pressure is limited by capacity requirements and in some cases by the mechanical design strength limitations of parts such as the outlet flange, bellows, or valve bonnet. Generally, the total back pressure on a balanced pressure relief valve (superimposed plus built-up at the PR valve rated capacity) should be limited to 50% of set pressure, because of the marked effect of higher back pressures on valve capacity, even when appropriate correction factors are used in sizing. In exceptional cases, such as retrofits, total back pressure up to 75% of set pressure may be used. In these cases, the manufacturer must be contacted for appropriate correction factors. The effect of back pressure on conventional PR valve capacity is taken into account in the sizing calculation procedures described later in this section. a. If the superimposed back pressure is less than the calculated critical flow pressure, the capacity of a conventional PR valve in vapor service is unaffected and back pressure is not a factor in sizing the PR valve. However, built-up back pressure on a conventional pressure relief valve will affect its flow capacity and operating characteristics, and should not exceed 10% of its set pressure at the PR valve rated capacity. b. If total back pressure (superimposed plus built-up at the PR valve rated capacity) is greater than the calculated critical flow pressure, the capacity of a conventional PR valve in vapor service is affected, and total back pressure is incorporated into the sizing procedure at the PR valve rated capacity. c. Any back pressure reduces the capacity of a conventional PR valve in liquid service, and the sizing calculation procedure is based upon the differential pressure across the valve, allowing for both superimposed and built-up back pressure at the PR valve rated capacity. Back pressure affects balanced PR valve capacities in a similar way (higher back pressures may be allowed) as described in paragraph 6 above for conventional valves, and appropriate factors are included in the sizing procedures. In the case of balanced bellows valves, mechanical considerations must also be evaluated, since they may limit the maximum permissible back pressure. The effect of back pressure on non-discharging PR valves tied into a closed system should be evaluated. The superimposed back pressure for non-discharging PR valves during a maximum system release (from either single or multiple valve releases under a design contingency) should not exceed the limits specified below. The reason for these limits is to permit the non-discharging PR valves to open (should opening be necessary) without exceeding the “1.5 Times Design Pressure Rule" in the equipment being protected by the these PR valves. For spring-loaded, conventional PR valves: Psi(max.) = 0.826 C Pset - Pd For balanced bellows and pilot operated valves: Psi(max.) = 0.50 C Pset Where: Psi(max.) =Maximum superimposed back pressure for non-discharging PR valves during a maximum system release. Pset = Pressure relief valve set pressure Pd = Differential spring pressure = Pset – Psi , where Psi = design superimposed back pressure. C = Multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01, dimensionless

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PRESSURE RELIEF VALVE CHATTERING

Chattering is the rapidly alternating opening and closing of a PR valve. This vibration may result in misalignment and leakage when the valve returns to its normal closed position. If chattering continues for a sufficient period, chattering may result in mechanical failure of valve internals or associated piping fittings. In addition, the vibration may loosen bolts and result in flange leaks around the PR valve. Chattering may occur in both liquid and vapor service PR valves. The principal identified causes of PR valve chattering are oversized valve, excessive inlet pressure drop, excessive built-up back pressure incorrect blow-down ring setting, and liquid surge. In addition, a further mechanism of chattering may be introduced in some liquid service PR valve installations if the response characteristics of a control valve in the same system are such that hunting between the two occurs. Generally, this can be eliminated by adjustment of instrument settings or by installation of two valves with staggered set points. The lower set valve should be sized to handle about 25% of the required capacity. 7.5.1

Oversized Valve

“Pop" action PR valves in vapor service open at the set point by the action of static process pressure on the valve disc, and move to full open position at only a small overpressure. Typically, a flow through the valve equal to at least 25% of its rated capacity is necessary to keep the disc in the open position. At lower rates, the kinetic energy of the vapor flow is insufficient to keep the valve open against the action of the spring and it returns to the closed position, only to reopen immediately since the static pressure within the system still exceeds the set pressure. Chattering results from continuous cycling in this manner. It can occur when a "pop" type PR valve is too large for the quantity of flow being discharged. In most cases, the use of multiple PR valves with staggered set points may be appropriate to eliminate this problem, as described later in this section. Liquid service PR valves are characterized by progressively increased lift with increasing inlet pressure, rather than the “pop" action of vapor service valves. Liquid service valves are, therefore, less likely to chatter at low relieving rates, and they will modulate down to about 10% of rated capacity before chatter becomes a problem. However, pumps with very flat capacity curves can (and have often) resulted in PR valve chattering when the PR valve is oversized. 7.5.2

Excessive Inlet Pressure Drop

A pressure relief valve starts to open at its set pressure, but under discharging conditions, the pressure acting on the valve disc is reduced by an amount equal to the pressure drop through the inlet piping and fittings. If this pressure drop is sufficiently large, the valve inlet pressure may fall below reseating pressure, causing it to close, only to reopen immediately since the static pressure is still above the set pressure. Chattering results from the rapid repetition of this cycle. To avoid this mechanism as the cause of chattering, inlet piping to PR valves should be designed for the lowest practical frictional pressure drop (including entrance loss and piping and isolation valve pressure drop). Experience as well as manufacturers' recommendations dictate an inlet pressure drop of no more than 3% of set pressure at the PR valve rated capacity. This 3% limit needs to be met for PR valves in both vapor and liquid service. In the case of PR valves in low-pressure vapor service where the set pressure is below 50 psig (340 kPa gage), 5% inlet pressure drop may be used if necessary. For remote contingencies, an inlet pressure drop of up to 10% of set pressure is acceptable. 7.5.3

Excessive Built-up Back Pressure

Built-up back pressure resulting from discharge flow through the outlet system of a conventional PR valve results in a force on the valve disc tending to return it to the closed position. If this returning force is sufficiently large, it may cause the valve to close, only to reopen immediately when the effect of built-up back pressure is removed. Chattering results from the rapid repetition of this cycle. To prevent chattering from this mechanism, conventional PR valve discharge systems must be designed for a maximum built-up back pressure of 10% of set pressure, at the PR valve rated capacity when relieving for non-fire contingencies. In cases where pressure relief design is controlled by fire conditions, with 21% overpressure, a built-

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up back pressures of 21% of set pressure at the PR valve design capacity is permissible as long as the 10% limit at rated capacity is met for all other contingencies. Where outlet pressure losses exceed 10%, balanced PR valves are often considered. However, substitution of a balanced PR valve for a conventional valve may not necessarily solve the chatter problem since debits associated with balanced PR valves (particularly the bellows type) may reduce the rated capacity of this type of valve. Hence, the PR valve has a tendency to become oversized depending on the amount of back pressure encountered. This may cause chatter for a smaller contingency release. For this reason, revision of outlet piping to reduce the back pressure to within the 10% limit is strongly preferred to the alternative of installing a balanced PR valve. (Hence, when designing new facilities, flare header sized should be increased instead of using balanced PR valves to reduce header size.) 7.5.4

Blowdown Ring Settings

Although not part of design, it should be recognized that in some cases, incorrect blowdown ring settings have resulted in valve chattering. The purpose of the blowdown ring is to assist the valve in opening fully to allow depressuring below the valve set points without chatter. Blowdown ring set points are available from the manufacturer and must be kept current. Where field performance/experience has proven to be acceptable, no changes are warranted. Where no experience is available, the manufacturer's recommended setting should be used. 7.5.5

Liquid Filled Systems

Chattering pressure relief valves have caused liquid filled piping system failures and loss of containment near the pressure relief valve. The following recommendations should be considered to reduce the associated pressure relief valve chatter (see Application Guide EE.35E.98 for additional details): 1. Use liquid trim, capacity-certified PR valves whenever possible. 2. If a liquid trim, capacity-certified PR valve cannot be used, consider using remotely sensed, modulating action pilot operated pressure relief valves if the service is non plugging (e.g., waxy or polymer deposits). 3. If neither 1 nor 2 above is applicable and the PR valve inlet line actual length exceeds 30 feet (9m) , evaluate the potential for chatter due to hydraulic surge using Section III-B of the Safety Technology Manual or Application Guide EE.35E.98. If the potential for chattering exists, consult EMRE’s Mechanical Engineering Section for assistance in developing an engineering solution to the problem. S

7.6

MULTIPLE PRESSURE RELIEF VALVE INSTALLATION

In certain cases it is necessary to install two or more PR valves in parallel for a single service. These applications are described below, together with appropriate guidelines for their design. 7.6.1

Large Release

The magnitudes of some large releases may be greater than the capacity of the largest single PR valve that is commercially available at the desired pressure rating, necessitating the use of two or more valves. Even when a single PR valve is available, the relative cost of multiple valves should be considered. Above a certain size (typically 8" x 10" or 200 x 250 mm), structural and piping engineering considerations associated with the large piping and valves may result in a lower installed cost for two smaller PR valves. When two or more PR valves are installed for these reasons, they should be specified with staggered set points as described below, to secure the additional advantage of minimizing chattering at low release rates. 7.6.2

Preventing Chattering

In PR valve sizing it is always necessary to select the next larger commercially available orifice above the calculated size. Furthermore, a PR valve may lift as a result of various contingencies, any one of which requires a lower relieving rate than the design contingency. Both these factors affect the likelihood of a vapor PR valve chattering in service, since chattering (as described previously) is more likely to occur when the quantity of fluid being discharged is less than about 25% of its rated capacity.

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Where different contingencies of equal probability require substantially different capacities, it is always best to use two or more PR valves with staggered settings. For example, if one contingency required a capacity of 25,000 lb/h (3 kg/s) and another 100,000 lb/h (12 kg/s), two PR valves would be used, with one of 25,000 lb/h (3 kg/s) and the other 75,000 lb/h (9 kg/s) minimum capacity. The lower capacity valve in this case would be at the lower staggered set pressure. When a fire contingency is the largest contingency and the next largest contingency is less than 25% of the fire relieving rate, multiple PR valves with staggered settings should always be used. However, when the fire contingency is the smallest load, it is generally ignored. This is because fire is a rare occurrence and chattering under fire conditions is not a significant concern. 7.6.3

Preventing Separation

In chattering prone service, e.g., liquid service, “Belleville" washers should be used to reduce the likelihood of bolt/nut separation. See GP 03-02-04. 7.6.4

ç

ç

S

Design of Multiple PR Valve Installation

When two or more PR valves are required in cases such as the above, capacities and set points should be specified in accordance with the ASME Code, as follows: 1. The ASME Code stipulates that when multiple valves are used, only one of them needs to be set at the maximum allowable working pressure (MAWP); the additional valves can be set at up to 105% of the MAWP. (For design purposes the maximum allowable working pressure is assumed to be the same as the design pressure.) In addition, 3% tolerance on set pressure is permitted for PR valves. Thus, careful adjustment of the set point in the field can provide some stagger, but this is not normally considered in the design. The matters of set point, stagger, tolerance, and overpressure are areas where other codes may differ from the ASME Code. Where local codes limit the maximum allowable accumulation to 10% of MAWP, it may be necessary to stagger the set points downward (for example, one or more PR valves set at 95% of MAWP and one or more PR valves set at 100% of MAWP). 2. If multiple valves are installed to handle a non-fire “operating contingency” then they may be designed to handle the required relieving rate at an accumulated pressure not exceeding the greater of 116% of the design pressure or the design pressure plus 4 psi (27.6 kPa), provided that local codes do not stipulate otherwise. It is accepted practice to size all valves at set pressure plus the allowable accumulation, and stagger the settings up to 105% of the design pressure. 3. Where fire is the governing situation, a supplemental valve designed to handle the additional fire load can be set as high as 110% of design pressure and the capacity is calculated with an accumulation in the vessel of 21% (refer to Figure II-4). 4. The total relieving rate for some PR systems can be very high, as in the case of a separator drum. This rate may be economically handled by one PR valve discharging liquid to a closed system; and another, set at a higher pressure, discharging vapor to the atmosphere. The configuration should ensure that liquid is preferentially discharged to the valve set at the lower pressure, and that the possibility of entrainment through the vapor valve is minimized by providing a vapor space equal to at least 30 minutes of liquid holdup above an independent high liquid level alarm, refer to LIQUID OVERFILL AS A CAUSE OF OVERPRESSURE in PART I. 7.7

SPECIAL FEATURES FOR SPRING-LOADED PRESSURE RELIEF VALVE

The additional feature described below, available as means of improving a spring-loaded PR valve tightness below set pressure, may be justified for some applications. 7.7.1

Soft Seat

(See Figure II-8) A synthetic “O" ring seal, or soft seat (e.g., of Viton or silicone rubber), may be incorporated into the valve disc seating area on either a conventional or a balanced bellows PR valve. With this device, tight shutoff may be achieved closer to set pressure than with typical metal-to-metal seating. It is particularly applicable to difficult services, such as:

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2. 3. 4. 5. 6.

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Operation close to set pressure, e.g., due to pressure fluctuations or pulsations. However, the normal 10% or 15 to 25 psi (100 to 175 kPa) between operating and set pressure should still be applied in new designs. (See DP II.) Light, hard-to-hold fluids, e.g., hydrogen. Presence of solids fines. Vibrating equipment. Corrosive fluids. Nozzle icing under relieving conditions.

The cost premium is approximately 50% for smaller valves, and 15 to 40% for larger valves. Soft seats are normally limited to about 450°F (230ºC) maximum temperatures and 1500 psig (10,000 kPa gage) maximum pressure. Another limitation is that "O" ring seals tend to deteriorate with age and thereby loose tightness. Further details may be obtained from manufacturers' literature. S 7.8

RUPTURE DISC

A rupture disc (RD) is a thin diaphragm (generally a solid metal disc) designed to rupture (or burst) at a designated pressure. The RD is used as a weak-point element for the protection of vessels and piping systems against excessive pressure (positive or negative). In contrast to pressure relief (PR) valves, a RD is non-reclosing. Thus, a RD provides a permanent open path into the discharge system. The discharge system may either be the atmosphere or a closed system such as a flare header. Rupture discs can be used as the only pressure relieving device or can be used in conjunction with PR valves either as a secondary (parallel) relief device or in series with the PR valve itself (either at the inlet or the outlet of the PR valve). (If the RD is used at the inlet of the PR valve, it serves to reduce fugitive emissions or corrosion of the PR valve. When used at the outlet of the PR valve it can only serve to reduce fugitive emissions.) Rupture discs are generally installed in specially designed disc-holder assemblies (or safety heads). The most common type of RD assembly used, fits between standard flanges. There are five major types of rupture discs available, as follows: ·

Conventional tension-loaded rupture disc.

·

Pre-scored tension-loaded rupture disc.

·

Composite rupture disc.

·

Reverse buckling rupture disc with knife blades.

·

Pre-scored reverse buckling rupture disc: cross-score and semi-circular score.

The major characteristics of these are summarized in Table II-1. Other types such as solid graphite and machined discs are also available, but they may have more limited applications. Since graphite is chemically inert, solid graphite discs are sometimes used in chemical plants. In general, graphite discs normally behave similarly to metallic conventional discs. 7.8.1

Advantages

When compared with PR valves, rupture discs have the following advantages: 1. No simmering or leakage prior to bursting. Unless damaged or corroded, rupture discs are not subject to simmer or leakage at pressures below their burst pressure, Pb. 2.

3.

More effective against overpressure caused by deflagration. Rupture discs can open fully within 1 millisecond for vapor/gas systems, thus making them more effective than PR valves when the overpressure is caused by an internal deflagration or sudden pressurization (for example as a result of a tube failure in a high pressure heat exchanger). Less expensive to provide corrosion resistance. Rupture discs can be made of, or coated with, a variety of corrosion resistant materials. This allows the RD manufacturers to provide the corrosion resistance at a lower cost than having to upgrade the materials in a PR valve.

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4.

5.

6.

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Less tendency to foul or plug. Rupture disc opening is essentially equal to the piping bore and results in a pressure relief path without changes in flow direction. This feature reduces the potential for fouling or plugging once the device has opened compared to a PR valve. Can provide both depressuring and overpressure protection. Since it is a non-reclosing device, a RD offers the possibility of simultaneous overpressure protection and depressuring, if the RD is oversized. This feature is not possible with PR valves and may be advantageous in some services. Lower initial cost than for an equivalent service PR valve.

Another reported advantage for reverse buckling type rupture discs is the possibility of on-line testing of a PR valve when the RD is installed upstream of the PR valve. However, this type of PR valve testing is not recommended since significant lift (“pop") can not be achieved on the valve (due to the small volume of test media employed), therefore, it is not possible to confirm PR valve opening. In addition, it is not possible to check for fouling, blockage or corrosion. All of these are important to ensure the long-term adequacy of overpressure protection. Therefore, RDs should not be installed or used for the purpose of carrying out on-line PR valve testing. 7.8.2

Disadvantages

Disadvantages common to all rupture discs regardless of type include: 1. Non-reclosing pressure relief device. Replacement of the burst rupture disc is required to allow continued operation if it is the only protective device. Alternatively, if the RD is used in series with a PR valve, operations can continue without replacement of the burst RD, but the extra protection that is afforded to the system by the RD is lost until it is replaced. 2. Non-destructive testing of the RD burst pressure cannot be accomplished. Unlike PR valves which can be adjusted, the accuracy of burst pressure is solely based on the manufacturer's tests on discs from the same lot. 3. Require periodic replacement. Rupture disc life is finite even when discs are installed with adequate margin between operating and burst pressure. Thus, rupture discs must be periodically replaced. As a result of cycling, the disc will eventually be weakened by fatigue, although the reverse buckling discs normally are less susceptible to fatigue. In addition, rupture discs are subject to corrosion especially along the score line of prescored discs. Both these factors limit the useful life of the RD. 4. Greater sensitivity to mechanical damage. Any denting or distortion of the rupture disc will affect the RD burst pressure. 5. Greater sensitivity to temperature. Since the burst pressure depends on disc material properties, the temperature at the time of burst will cause the burst pressure to vary. Choice of material has a great influence on the sensitivity to pressure (see Figure II-11). 6. Some types, as shown in Table II-1 will not function in liquid service. Even when they function, the opening achieved is not as large as in vapor services, typically being about one-half the nominal rupture disc flow area. Other disadvantages are specific to RD type and include among others: possible unsafe condition if installed upside down, possible fragmentation (which can restrict relief rates and also prevent PR valve closure if the RD is installed upstream of the PR valve), possibly having to provide a greater pressure margin to avoid fatigue failures, and a large manufacturing range which forces increases in equipment design pressure (or reduction in operating pressure). 7.8.3

Acceptable Types of Rupture Discs

To ensure the safety of the facility, rupture discs must be “fail-safe" and must be carefully selected and installed. To be “fail-safe," the rupture disc must not fragment and its design should limit the burst pressure when damaged or installed upside-down to less than 1.5 times the system's design pressure or proof test pressure whichever is lower. Considering these requirements, only three RD types are generally acceptable/recommended: 1.

Pre-scored (cross-score) reverse buckling RD for gas service. (Figure II-9)

2.

Pre-scored (semi-circular score) reverse buckling RD installed in holder with capture bar for gas or liquid service.

3.

Pre-scored tension-loaded RD for gas or liquid service (Figure II-10).

These RDs are available in a variety of sizes, burst pressures, burst temperatures and materials. Some of these are shown in Tables II-3 and II-4. Even though both these types satisfy the general “fail-safe" criteria, their installation and use must be carefully monitored to ensure adequate safety. For example, since these discs are only guaranteed

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to burst at no more than 1.5 times the burst pressure when installed upside-down or damaged, they can not be used to protect systems that are pneumatically tested or hydrotested to less than 1.5 times their design pressure. 7.8.4

Rupture Disc Certification and Testing

In order to ensure adequate performance, rupture discs should be ASME certified. To ensure the “fail-safe" characteristics of the RD, the manufacturer should also be required to stamp and rate the RD at the desired temperature and to test at least one disc upside-down. If this upside-down test shows the RD burst pressure to be higher than 1.5 times the stamped burst pressure (per the ASME certification) the complete lot of discs is unacceptable. 7.8.5

Rupture Disc Specification

Table II-3 presents a sample rupture disc specification sheet. 7.8.6

Manufacturing Range of Rupture Discs

Since it is not practical to make, or carry in inventory sheet metal in all possible thickness needed, the manufacturer uses the manufacturing range (MR) to compensate. Manufacturing range is defined as the allowable range of pressures, mutually agreed upon between the manufacturer and the buyer, within which the rupture disc can be rated and stamped. This range is generally defined as a percent of desired burst pressure (gauge). Thus, when specifying a RD it is not sufficient to list the desired burst pressure; the required manufacturing range must also be defined. The magnitude of manufacturing range differs between manufacturers and is a function of RD type and burst pressure. The complete range must be applied on the low side of the protected system's design pressure. Typical manufacturing ranges are listed below. Lower manufacturing ranges may be available at additional cost. (If the manufacturing range is zero, the RD burst pressure is stamped with a burst pressure equal to the requested burst pressure, usually the system design pressure.)

RUPTURE DISC TYPE PRE-SCORED REVERSE BUCKLING PRE-SCORED TENSION-LOADED

TYPICAL MANUFACTURING RANGE, % 0, -5, OR -0

Pb, psig (kPa gage) 20 to 45 (138 to 310) 46 to 90 (311 to 620) 91 to 270 (621 to 1860) 271 to 500 (1861 to 3450) above 500 (above 3450)

7.8.7

-7/+14 -6/+12 -5/+10 -4/+8 -3/+6

Rupture Disc Burst Pressure

For a new design, the type of RD to be used must be selected. The lowest allowed burst pressure is defined by using the appropriate spread between maximum operating pressure and RD burst pressure (Table II-1). The maximum possible burst pressure is defined by applying the corresponding total manufacturing range (positive plus negative manufacturing range) to the minimum allowed burst pressure. The system design pressure must be at least as high as the maximum possible burst pressure. To specify the RD itself, the lowest allowed burst pressure and the negative manufacturing range are used. After manufacture, each RD is stamped with its rated burst pressure (determined from burst tests of the lot in question). This stamped burst pressure will fall between the limits defined by the manufacturing range but will only match exactly the requested burst pressure if the manufacturing range is zero. For example: P= Maximum Normal Operating Pressure - 75 psig (515 kPa gage) RD type = pre-scored tension loaded (from Table II-1; maximum operating pressure = 0.85 Pb) MR = - 6%/+12%

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1. Pbmin 2.

3.

4.

The minimum burst pressure is defined by the required spread between operating and burst pressure: = 75 / 0.85 = 88 psig = 515 / 0.85 = 606 kPa gage The system design pressure (DP) must take into account the full manufacturing range to be requested: DP = Pbmin/ [1 – (| – MR| + |+ MR|) / 100] = 88 / [1 – (| – 6| + | + 12|) / 100] = 107 psig = 606 / [1 – | – 6| + | + 12|) / 100] = 739 kPa gage The RD specification must also take into consideration the manufacturing range. However, since the manufacturing range is defined in terms of desired burst pressure, only the negative manufacturing range is applied: = Pbmin /[1 – | – MR| / 100] = 88/[1 – | – 6| / 100] = 94 psig RD rating (Pb) = 606 / [1 – | – 6| / 100] = 645 kPa gage The engineer requests a disc with a burst pressure of 94 psig (645 kPa gage) at a -6/+12% manufacturing range. The resulting RD will be rated and stamped anywhere from 88 to 105 psig (606 to 722 kPa gage).

7.8.8

Rupture Disc Burst Temperature

The burst pressure of a rupture disc is a function of the temperature the disc experiences when it bursts. The sensitivity of the disc burst pressure to temperature depends on the material used and is illustrated in Figure II-11 for tension-loaded discs. Of the common disc materials shown, Inconel is the least sensitive to temperature followed by nickel and 316 SS. Aluminum is, in general, the most sensitive. Due to their design, reverse buckling discs are about half as sensitive to temperature as are tension-loaded discs. Rupture disc temperature is a critical parameter since, in most instances, the disc is installed at the end of a piping section where there is normally no flow. Unless very well insulated, and especially when discharge is to the atmosphere, the normal rupture disc temperature can be significantly different than the normal process temperature. (Heat loss from the static material below the RD is significant and can amount to 50 - 100°F (28 - 56°C) or higher depending on the length of piping). When an overpressure occurs, the RD will burst at its normal temperature rather than the ultimate relieving temperature. Thus, being able to accurately define the bursting temperature of the disc is vital to the safety of the system since at lower temperatures the RD may burst at higher pressure. When the actual RD temperature is not known, use of Inconel as the disc (not the disc assembly) material should minimize the variability of burst pressure. Alternatively, the disc can be specified for the most conservative temperature which is normally the discharge system temperature. The discharge system temperature is ambient when the RD discharges directly to the atmosphere or to the inlet of a PR valve. Utilizing the ambient temperature is conservative since this is likely to be lower than the process temperature and the disc will normally experience a temperature somewhere between these two. Designing the RD for the lower temperature may result in a lower (and safer) actual burst pressure. Only in very few cases, will use of process or emergency temperature be appropriate for RD rating. Whenever possible, the actual installation should be checked to verify that the actual disc temperature is reasonably close to the rated disc temperature. In cases where the rated RD temperature is higher than the actual temperature, the system must be further analyzed to determine if it is safe. Otherwise, a RD with the proper temperature rating should be retrofitted. In specifying disc-holder assembly materials of construction, the relieving temperature is used, since the safety head will ultimately be exposed to these conditions. 7.8.9

Rupture Disc Sizing

The RD must be sized to prevent the pressure within the protected system from exceeding the limits allowed by code. Once burst, the RD becomes a single component in the discharge piping and it is the complete piping system that has to be designed to allow the required relief without exceeding the accumulated pressure limits. Only limited tests have been carried out to define the frictional pressure drop across burst rupture discs. A conservative estimate of pressure drop can be obtained by assuming it has a pressure drop equivalent to the pressure drop in a pipe 75 nominal disc diameters in length. This approximation is used to compensate for the disc material protruding into the flow stream. Alternatively, if the RD is the only device and there is essentially no inlet or outlet piping (i.e., less than two pipe diameters), the RD can be sized as a PR valve with a discharge coefficient (Kd) of 0.62.

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When used in liquid service, an additional pressure drop (as discussed above) is introduced by the fact that the rupture disc is not likely to open fully. To account for partial opening in liquid service, a pressure drop equivalent to the pressure drop through a restriction orifice with area equal to one-half the nominal rupture disc flow area should be used. When the RD is used at the inlet of a PR valve, the RD must be at least equal in diameter to the PR valve inlet flange. In this situation, the ASME pressure vessel code requires that unless they have been flow tested together, the RD-PR valve combination must be derated by 10% from the PR valve capacity (i.e., the combination has a capacity factor of 0.9 relative to the PR valve itself). In practice, most tested combinations have a combined capacity factor of 0.95 or higher. Thus, in general, tested combinations are recommended, (refer to the National Board of Boilers and Pressure Vessel Inspectors publications for information on the tested combinations and the measured capacity factor). When rupture discs are used to relieve overpressure caused by an internal deflagration, equations such as those in NFPA-68 should be used to calculate the required relief area. In the case of reaction runaway, the relief area is usually determined from small scale tests. 7.8.10

Rupture Disc Installation

Rupture Disc Installed by Itself - A rupture disc not installed in series with a PR valve must comply with the following: 1. CSO block valves (when allowed by local codes) must be provided upstream of the RD (and also downstream if discharge is to a closed system) to allow isolation for inspection and replacement without shutting down the unit. (Block valves would not be required if the equipment on which the RD is installed can be isolated or taken out of service with the remainder of the facility onstream.) 2. The discharge piping must comply with PR valve installation requirements including size, bracing and maximum/minimum support, velocity, drainage of piping away from the PR device, elevation of discharge point, and snuffing steam connections. 3. In general, inlet piping will be equal in diameter to the rupture disc nominal size. Outlet piping will be at least equal in diameter but may be of larger diameter than the RD size. 4. Rupture discs need not comply with the inlet piping pressure drop limitation since these are only required to prevent chattering of PR valves, which cannot occur in a rupture disc. However, if significant, the inlet line pressure drop must be taken into account in establishing the system design pressure. In addition, the discharge piping must limit the accumulated pressure in the system being protected to 10% of the design pressure (or 21% in the case of fire contingency). Rupture Disc Installed at the Inlet of a PR Valve - Any RD installed at the inlet of a PR valve must be located immediately beneath the valve. Only a small (less than 2 ft or .6 m) section of piping with a “tell-tale" assembly should be provided between the PR valve and the RD. This “tell-tale" assembly is required to detect and relieve pressure buildup between the RD and the PR valve. Unless this requirement is complied with, pressure buildup caused by any leakage through the disc will increase the system (upstream) pressure at which the disc will burst. (The disc will continue to burst at its design differential pressure, but since the discharge side pressure has increased there is a corresponding increase on the upstream pressure at burst.) The preferred method to detect/relieve pressure buildup between the RD and PR valve, is an installation which includes a bleeder valve, a pressure gauge, and an excess flow valve piped to a safe location (as per GP 03-02-04). Under normal conditions any leakage through the disc is relieved through the excess flow valve. If leakage is large, the excess flow valve is forced closed and the pressure gauge will record a positive pressure. When the disc bursts due to overpressure, the excess flow valve will also close to prevent release of material. To make this “tell-tale" design effective, the operator must regularly (at least once a shift) verify that the RD has not failed. If a small leak is suspected, the CSO valve downstream of the pressure gage may be closed. Thus, the pressure gauge readout and CSO valve should be brought to an easily accessible location. In addition, a high-pressure switch and alarm may be used to alert the operator to a problem. Rupture Disc Installed at the Outlet of a PR Valve - A rupture disc can also be installed at the outlet of a PR valve to reduce fugitive emissions. This type of installation may also require venting of the volume between the PR valve and the RD to prevent pressure buildup. When used in this manner, the RD burst pressure must be very low (a few psig or kPa gage) to prevent a large back pressure on the PR valve prior to the disc bursting. In addition, the venting arrangement must go to a closed system to make feasible the reduction in fugitive emissions.

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Rupture Disc Replacement Program

Rupture discs should be controlled or regulated under a program similar to that used in most plants for PR valve maintenance. This program should include data on location, burst pressure, disc type, identification tags, replacement dates, condition of “old" disc at the time of replacement, verification of correct installation, etc. S

S

7.9

EXPLOSION HATCH

A vessel which operates at essentially atmospheric pressure and may be subjected to an internal explosion, such as an asphalt oxidizer, should be protected by an explosion hatch equivalent to at least 80% of the vessel crosssectional area. The hatch consists of a hinged metal cover fitted over an opening on top of the vessel and sealed by its own weight. For vessels which normally operate at a slight positive pressure, a tight seal is achieved by the use of hold-down brackets with shear pins, rather than by increasing the weight of the hatch which would increase inertia and prevent quick opening. One or more hatches may be provided for a single vessel. Figure II-12 illustrates a typical double hatch arrangement which can be designed to open up to 100% of the vessel cross-section area. 7.10

LIQUID SEAL

In some cases, a hydraulic loop seal may be used for relieving overpressure on equipment operating at pressures slightly above atmospheric. Examples are certain FCCU regenerator overhead systems upstream of CO boilers. 7.10.1

Description

The seal consists of a simple U-tube containing a suitable liquid (normally water) with the seal depth and diameter sized to pass the maximum relieving flow at the required design pressure. 7.10.2

Design Features

The following design features must be incorporated: 1. Continuous water makeup and overflow on the seal loop, to ensure that the seal is always maintained during normal operation, and reestablished after a blow. 2. Adequate winterizing, where necessary, to prevent freezing of the seal. 3. Safe disposal of the effluent seal water, considering possible contamination by process fluids. 4. The criteria which govern the acceptability of discharging process fluids to atmosphere, as described for PR valves later in this section, must be satisfied. 5. Contingencies by which liquid hydrocarbons could be discharged through the atmospheric vent must be positively eliminated. 6. The vent line must comply with the flashback and snuffing requirements described in DP XV-B, Minimizing the Risks of Fire, Explosion or Accident. Although liquid seals are relatively simple, reliable, and inexpensive, they are of limited application, because of the difficulty in meeting all of the criteria listed above. Also, they may not be practical where vacuum conditions are identified. S

7.11

VACUUM RELIEF VALVE

The conditions under which vacuum or under pressure relief valves are required on process equipment are detailed in DESIGN PROCEDURE, PART I, of this section. Information on the selection, sizing and installation of vacuum relief valves may be obtained from manufacturers' literature. However, it should be noted that pressure vacuum relief valves (or vents) do not open fully until the overpressure reaches about 50% of the set pressure. Hence, careful analysis and proper documentation of the system requirements is necessary to confirm the adequacy of the protection.

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7.12

Section XV-C

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RUPTURE PIN VALVES

Rupture pin valves are a new type of non-reclosing pressure relief device which utilizes a buckling pin instead of a rupture disk to relieve pressure. This buckling pin valve is a patented, ASME-coded device. The device is produced by Rupture Pin Technology (RPT). Several features of the Rupture Pinä valve (RPV) make it a candidate to replace rupture disks in selected services. The RPV is not subject to premature failure. It can be made more accurate than rupture disks at low pressures, below 40 psig. The RPV can be reset in minutes without tools and without breaking flanges. A typical RPV is offered in Figure II-13, and a balanced RPV is offered in Figure II-14. 7.12.1

Buckling Pin Concept

The buckling pin concept is derived from Euler's formula. Euler's formula relates the force or pressure need to buckle a long, thin column to the length2, diameter4, and modulus of elasticity of the column. Although the buckling pin concept is based on Euler's formula, the pin length and diameter are ultimately determined through testing to provide a specified set point within standard tolerances. The key to the accuracy of the buckling pin valve is the repeatability of the buckling pin. A patented buckling pin design by RPT incorporates design features to maximize repeatability from pin to pin. This produces valves with a standard tolerance of ± 5% for set points from 5 to 20,000 psig. Below 5 psig the tolerance increases to 9%. Valves are available to 0.1 psig. 7.12.2

RPV Design / Operation

The RPV is designed to be a non-reclosing pressure relief device, similar to a rupture disk. As noted in Figures II-13 and II-14, a piston, or valve, is held in the closed position with the buckling pin. An o-ring on the piston is used to make a bubble tight seal. At about 90% of the set pressure, the pin bows slightly. There is no simmering as the oring continues to seal. If the pressure is reduced, the pin returns to its original position. This compression of the pin does not fatigue it, and repeated bowing will not result in premature failure. When the set pressure is reached, the pin buckles, and the valve opens. The valve can be designed to be balanced or unbalanced, similar to reclosing pressure relief valves. When the piston is connected to a smaller shaft, as in Figure II-13, back pressure affects the set point (unbalanced), just like a conventional relief valve or rupture disk. When the piston diameter is constant all the way to the pin, see Figure II-14, back pressure has no effect (balanced). Resetting of the valve after a release usually requires no breaking of flanges. Once vessel pressure has been reduced to near zero, the valve stem is returned to its seat by hand. The pin retaining screw is removed, usually by hand and a new pin installed. Spare pins are stored in the valve supports. If the vessel cannot be depressured, e.g., when the valve is installed under a safety valve, the pressure is equalized up and down stream of the valve. Then a special device is used to force the piston into its seat and hold it in place while a new pin is installed. (A device which holds a relief valve shut has other safety implications.) In dirty service (sticky fluids or solids) it may be necessary to break flanges to clean the seat and get a good seal. However, the use of a clean wash fluid may eliminate the need to break flanges, even in dirty service. Rupture pin devices may be more costly to install than rupture discs. However, replacement costs including the pin and labor are lower than rupture discs. This may make rupture pin devices economically attractive in services which have a history of premature disk failure. Other advantages which may make them attractive are their accuracy below 40 psig and their balanced design, not available with discs. 7.12.3

RPV Sizing

Sizing of a RPV is similar to that of a rupture disk. When the RPV is a single relief device and there is essentially no inlet or outlet piping, it is sized as an orifice with a discharge coefficient of 0.62. When placed in series with a pressure relief valve, the pressure relief valve should be downrated by 10%, just like a rupture disk. However, like a rupture disk, this is very conservative and the combination of the RPV and pressure relief valve should be tested to determine the actual rating.

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7.13

Page 80 of 156

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PRESSURE RELIEF VALVE FOR FOULING SERVICE

Process systems handling polymers, resins slurries, coke residue, etc., are often subject to plugging at dead-end locations such as PR valve inlets. In extreme cases, complete blockage of inlet piping and valve nozzle can result. This problem can be eliminated by the application of a flush-seated PR valve, in which dead-end areas are eliminated by placing the valve disc flush with the vessel wall, in the flow pattern of the contents. This type of valve is manufactured by the Anderson Greenwood. S 7.14

OVERPRESSURE PROTECTION BY USE OF RESTRICTIONS AND ESCAPE PATHS

7.14.1

Restrictions

As an alternative to increasing the capacity of some pressure relief devices, items of process equipment may in some special cases be protected against overpressure by smaller PR valves by placing a physical restriction in any flow path by which the equipment is connected to a source of high pressure fluids. The basis for evaluation of pressurization paths, considering restriction by piping, check valves, restriction spool pieces or orifices, and control valves, is described in DESIGN PROCEDURE, PART I, of this section. 7.14.2

Escape Paths

As a further alternative to the addition of pressure relief devices, equipment may in some cases be protected against overpressure by the provision of an adequately sized and constantly available escape path. The basis for evaluating such escape paths, including interconnecting piping, CSO valves, control valves, orifice plates, paralleled equipment, etc., is described in DESIGN PROCEDURE, PART I, of this section. 8 DESIGN PROCEDURE, PART III: PRESSURE RELIEF VALVE SIZING AND SPECIFICATION PROCEDURES The required relieving rate for a pressure relief valve is determined from consideration of the contingencies which can cause overpressure, as described in DESIGN PROCEDURE, PART I, of this section. The calculation procedures for determination of the PR valve size required to pass the design relieving rate are described below. 8.1 8.1.1

SIZING FOR VAPOR SERVICE Critical and Subcritical Flow

The maximum vapor flow through a restriction, such as the nozzle or orifice of a pressure relief valve, will occur when conditions are such that the velocity through the smallest cross-sectional flow area equals the speed of sound in that vapor. This condition is referred to as “critical flow" or “choked flow." (This should not be confused with the “critical velocity" related to entrainment, referred to in DP III, Fractionating Towers; DP V, Drums; and DP XV-E, Flares.) See DP XIV, Fluid Flow Subsection C, Single-Phase Gas Flow, for a discussion of this subject. A simplified equation for sonic, or critical, velocity is: Vc = 68.1

kPx rx

(Customary)

Eq. (2)

Vc = 31.6

kPx rx

(Metric)

Eq. (2)M

where: Vc =

Critical flow velocity, ft/s (m/s)\

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K=

Ideal gas specific heat ratio, Cp / Cv, or ratio at the PR valve inlet temperature and atmospheric pressure. Published values of k at 60°F (15°C) and one atmosphere for many common substances are presented in Table III-1. If k is not known, a conservative value of 1.001 may be used. If correction for nonideal gas behavior is desired, Appendix B of API RP-520 can be used.

Px =

Pressure in restriction at critical flow, psia (kPa absolute) (i.e., the “critical flowpressure")

rx =

Density at critical flow temperature and pressure, lb/ft3 (kg/m3)

The pressure drop which corresponds to critical flow is called the “critical pressure drop,” i.e., P1 – Px, where P1 is the absolute upstream pressure. If the pressure P2 downstream of the restriction is less than the critical flow pressure, then the maximum obtainable flow which occurs at critical velocity is a function of P1 and Px but is unaffected by P2. If P2 is greater than Px, however, then the flow is termed “subcritical," and the rate is a function of P1 and P2. The impact of this is accounted for by the use of a correction coefficient, Kb, in the PR valve sizing equation. In PR valve design, it is desirable to select a PR valve discharge location at a low enough pressure to permit designing for critical flow conditions, so that the relieving rate will be independent of minor back pressure fluctuations. 8.1.2

Determination of Critical Flow Pressure

The first step in sizing a PR valve for vapor flow is to determine the critical flow pressure, Px from the following equation: k

Px P1

æ 2 ö k -1 = ç ÷ è k + 1ø

Eq. (3)

For hydrocarbon vapors, Px / P1 may be read directly from Figure III-1, which is sufficiently accurate under all conditions for PR valve calculations. Ideal gas k values for a range of common gases, with corresponding Px / P1 ratios, are listed in Table III-1. When the reduced pressure and temperature approach 1.0, Px / P1 approaches the limiting value of 0.606. 8.1.3

Sizing for Vapor Critical and Subcritical Flow

The following equation is used to calculate the required orifice area regardless if flow is critical or subcritical or PR valve type (conventional or balanced) provided that a back pressure correction factor and discharge coefficient are used: W A = 520 K d K b P1

A =

9.1 ´ 10 4 W K d K b P1

(k +1) /(k _ 1)

æ zT1 ö æ k + 1 ö ç ÷ ç ÷ è kM ø è 2 ø

æ zT1 ö æ k + 1 ö ç ÷ ç ÷ è kM ø è 2 ø

(Customary)

Eq. (4)

(Metric)

Eq. (4)M

(k +1) /(k -1)

where:

W=

Flow rate, lb/h (kg/s)

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Kd =

Orifice discharge coefficient. Recommended values by the selected PR valve manufacturer should be used for definitive PR valve sizing. Generally, a coefficient of 0.975 is used for conventional/bellows type PR valves such as those manufactured by Crosby or Crosby or Farris, and listed in Table III-2. Other PR valve designs and PR valves manufactured outside the US may have a significantly different coefficient. Hence, manufacturer's literature should always be consulted prior to the final coefficient selection and PR valve specification. Correction factor for total back pressure which depends on PR valve type and flow characteristics, as follows: Critical flow, conventional or pilot operated PR valve: 1 Subcritical flow, conventional or pilot operated PR valve: Kb may be estimated from Figure III-2A or calculated from Eq. (5) below

Kb= Kb =

Kb =

735 F C

æP ö 1 - çç 2 ÷÷ è P1 ø

Eq. (5a)

or after substituting expressions for F and C ç Kb =

æP ö 2çç 2 ÷÷ è P1 ø

2

(k -1) ù (k +1) k úæ k + 1 ö (k -1) æ P2 ö ç ÷ 1 ÷ ç ê çP ÷ úç 2 ÷ ø ê è 1ø úè ë û k -1 é

kê

Eq. (5b)

Critical flow, balanced bellows PR valve: Kb may be significantly lower than 1.0 and should be obtained from the manufacturer of the specific PR valve to be used. For preliminary sizing prior to vendor selection, Figure III-2B may be used to estimate Kb, since this figure presents an average of the back-pressure correction coefficients recommended by a number of PR valve manufacturers. Note that Figure III-2B is only valid for total back pressures less than 50% of set pressure and for set pressures greater than 50 psig (345 kPa gage). For back pressure greater than 50% of set pressure, the manufacturer must be consulted. Recommended values of Kb by the selected PR valve manufacturer should be used for final PR valve sizing. Subcritical flow, balanced bellows PR valve: Kb must be obtained from the vendor.

C=

ç

ASME Unfired Pressure Vessel Code constant for vapor which is a function of the specific heat ratio, k. Values of C can be determined from Eq. (6). In addition, values of C for different k are tabulated in Table III-4. æ 2 ö C = 520 k ç ÷ è k + 1ø

F = PR valve (7). F =

(k + 1)

(k -1)

Eq. (6)

Subcritical flow coefficient which is a function of the specific heat ratio, k, and the inlet pressure and total back pressure. Values of F can be determined from Eq.

æ 1 - (P / P ) (k - 1) / k æ k ö 2 1 çç ÷÷ (P2 / P1) 2 / k ç ç 1 ( P / P1) 2 è k - 1ø è

ö ÷ ÷ ø

Eq. (7)

A=

Effective orifice area, in.2 (mm2) This is the area corresponding to the API orifice designation, which is shown in Table III-2, and is to be used in PR valve selection. Actual orifice areas in PR valves from US manufacturers are at least 10% greater than the effective area to meet ASME Code requirements (Section I, Par. 69.4 and DP VIII, Par. UG-131). No credit may be taken for this additional area.

P1 =

PR valve flange inlet pressure at relieving conditions (including accumulation ), psia (kPa absolute)

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P2 =

PR valve total back pressure, superimposed plus built-up, psia (kPa)

M=

Molecular weight of the relieved vapor

Z=

Compressibility factor of the relieved vapor at PR valve inlet conditions. This factor can be determined from vapor-liquid equilibrium calculations, from the Exxon Blue Book, or from other sources.

T1 =

PR valve flange inlet temperature at relieving conditions, °R (°K) For special cases where a PR valve is being sized for fire, T1 may be estimated by determining the mid-boiling point of the liquid at the PR valve flange inlet pressure, P1. For heavier materials/cuts, it may be necessary to separate the system and evaluate T1(s) at various segments in the boiling range.

K=

Ideal gas specific heat ratio, Cp / Cv, or ratio at the PR valve inlet temperature and atmospheric pressure. Published values of k at 60°F (15°C) and one atmosphere for many common substances are presented in Table III-1. If k is not known, a conservative value of 1.001 may be used. If correction for non-ideal gas behavior is desired, Appendix B of API RP-520 can be used.

Sizing of Hydrocarbon Vapor / Hydrogen / Steam Mixtures

Sizing of PR valves for hydrocarbon vapor/hydrogen/steam mixtures at critical flow conditions may, in most cases, be based upon the average molecular weight for the mixture and the use of Figure III-1 to obtain the critical flow pressure ratio, followed by the use of Eq. (4) to determine the required orifice area. This procedure is sufficiently accurate for PR valve sizing purposes. However, if the average molecular weight is less than 10, Figure III-1 is not valid and the critical pressure ratio has to be calculated using an average value of k and Eq. (3). For situations that result in subcritical flow, the average k can be used in Eq. (4)) to determine the required relief area.

S

When the average k for the hydrocarbon vapor/hydrogen/steam mixture is required, a vapor-liquid equilibrium routine (such as EDL-3 or PROCESS) or the following procedure can be used to determine the value of k: 1. Blend the specific heats at constant pressure on a weight basis. 2. Blend the specific heats at constant volume on a weight basis. 3. The average k is calculated as the ratio of the blended average specific heats from Steps 1 and 2 above. 8.2

SIZING FOR NON-FLASHING LIQUID SERVICE

There is no critical pressure limiting the flow of liquid through a PR valve orifice as is the case for vapor service. The discharge rate for non-flashing liquid flow through the PR valve is a function of the pressure drop across the PR valve, but sizing equations depend on the valve type. 8.2.1

Sizing Capacity Certified Relief Valves

Certified liquid trim valves are not recommended for vapor service because the blowdown is in the range of 20 22% of set pressure. For relief valves that are capacity certified and achieve full lift at no more than 10% accumulation (and which are to be used in all services when the relieving fluid is a non-flashing liquid under all contingencies except fire), the following equation is used to calculate the required orifice area: A =

L 38 K d K u K w

A =

710 L K d Ku K w

S P1 - P2

S P1 - P2

(Customary)

Eq. (8)

(Metric)

Eq. (8)M

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where:

Flow rate, gpm (dm3/s or I/s) Effective orifice area, in.2 (mm2) Discharge coefficient for the PR valve. Recommended values by the PR valve manufacturers should be used for definitive PR valve sizing. For conventional/bellows type relief valves API RP 520 recommends a discharge coefficient of 0.65 if the manufacturer has not been selected. Correction factor for viscous liquids, determined from Figure III-3. Note that a trial-anderror selection of the orifice size is necessary in the determination of Ku.

L= A= Kd =

Ku = Kw =

P2 =

Correction factor for back pressure. For conventional and pilot operated PR valves the correction factor is 1.0. For balanced bellows type PR valves the correction factor is determined from manufacturers' charts, corresponding to the total back pressure (superimposed plus built- up). Significant variations exist in the correction factor for relief valves from different manufacturers. Figure III-4 represents an average correction factor covering the most common relief valves from US vendors and may be used to determine Kw when the manufacturer has not been selected. Definitive PR valve sizing should use the correction factor from the manufacturer of the PR valve selected. PR valve flange inlet pressure at relieving conditions (including accumulation), psia (kPa absolute). Total back pressure (superimposed plus built-up), psia (kPa absolute).

S=

Specific gravity of the liquid at inlet conditions, referred to water at 60°F (15°C).

P1 =

8.2.2

Sizing Safety Relief Valves Not-Capacity Certified

For safety relief valves (and also for relief valves built prior to about 1985) which are not capacity certified for liquid service and which achieve full lift at 25% overpressure, (and which are to be used in any service where the relieved material may be liquid under some contingencies and vapor or mixed phase under others), the following equation is used to calculate the required orifice area: A =

L 38 K d K u K w K p

A =

710 L K d Ku K w Kp

S

(1.25 Pset ) - Pb S

(1.25 Pset ) - Pb

(Customary)

Eq. (9)

(Metric)

Eq. (9)M

where:

L=

Flow rate, gpm (dm3/s or I/s)

A = Effective orifice area, in.2 (mm2) Kd = Discharge coefficient for the PR valve. Recommended values by the PR valve manufacturers should be used for definitive PR valve sizing. For conventional/bellows type relief valves API RP 520 recommends a discharge coefficient of 0.62 if the manufacturer has not been selected. Kp= Correction factor obtained from Figure III-5 for overpressures less than 25%. This factor is necessary since liquid service safety relief valves require 25% overpressure to achieve full lift but the ASME Code limits overpressure for operating failure contingencies to 10% (16% if multiple valves); and the sizing formula is based on full lift in the safety relief valve. Kp accounts for the reduced capacity resulting from the reduced lift, reduced overpressure and changed discharge coefficient needed to meet the ASME Code.

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Ku = Correction factor for viscous liquids, determined from Figure III-3. Note that a trial-and-error selection of the orifice size is necessary in the determination of Ku. Kw=Correction factor for back pressure. For conventional and pilot operated PR valves the correction factor is 1.0. For balanced bellows type PR valves the correction factor is determined from manufacturers' charts, corresponding to the total back pressure (superimposed plus built-up). Significant variations exist in the correction factor for relief valves from different manufacturers. Figure III-4 represents an average correction factor covering the most common relief valves from US vendors and may be used to determine Kw = When the manufacturer has not been selected. Definitive PR valve sizing should use the correction factor from the manufacturer of the PR valve selected. Pset = PR valve set pressure, psig (kPa gage). Pb = Total back pressure (superimposed plus built-up), psig (kPa gage). S = Specific gravity of the liquid at inlet conditions, referred to water at 60°F (15°C). ç

S

8.3

SIZING FOR FLASHING MIXED-PHASE (VAPOR AND LIQUID) AND FLASHING LIQUID SERVICE

A significant aspect about flashing flow through a nozzle (such as those in PR valves) is the ease with which the choking (or critical) condition is attained. At this condition, maximum flow occurs through the nozzle and further lowering of the downstream pressure will not result in increasing the flow. For vapor or gas flow the choking condition is reached when the downstream pressure is less than 55 to 65% of the upstream value (in absolute terms). However, for saturated liquids and flashing two-phase mixtures, the choking condition can be attained as early as when the downstream pressure is 80 to 90% of the upstream pressure. Hence, even a small amount of flashing is sufficient to significantly limit the flow through the valve. For sizing the PR valve, based on the homogenous equilibrium model (HEM), flashing liquids and flashing two-phase mixtures are treated as classical compressible fluids undergoing an adiabatic expansion through the PR valve nozzle. During the expansion, both phases are considered to have equal velocities, have the same temperature, and to be at thermodynamic equilibrium with each other at that temperature and pressure. These conditions define the homogenous equilibrium model flow. The resulting flow through the PR valve can fall in any of three broad regimes, depending on the inlet conditions and where the flashing occurs, as follows: 1. Flashing two-phase mixture at the inlet (for which the flow could be critical or subcritical). 2. Saturated or subcooled liquid at the inlet with flashing within the PR valve nozzle. 3. Subcooled liquid at the inlet with flashing downstream of the PR valve nozzle.

ç ç ç

Since equilibrium may not be attained in the valve, more material may flow through the valve than would be experienced under equilibrium conditions. Should this condition develop, the built-up back pressure in the discharge piping will be higher than design and may result in valve chattering. This is more likely to occur whenever the quality (mass fraction vapor) at the inlet of the PR valve is less than 0.10 and flashing is predicted to occur within the PR valve nozzle (see Reference 25, page 171) To alleviate this condition, a balanced bellows or balanced pilot-operated pressure relief valve should be considered for services in which the sizing contingency, or any other contingency requiring a relief area within 20% of the sizing contingency, involves a fluid that flashes within the PR valve nozzle and for which the quality at inlet conditions is less than 0.10 (all cases of regime 2 and some cases of regime 1 above). Note that no Kd data are available for flashing flow through PR valves. Experiments on nozzles indicate that during flashing two-phase flow the frictional losses are similar to those for vapor/gas service. Thus, for conservatism a Kd of 0.85 is recommended. (In the case where the inlet is subcooled but flashing occurs downstream of the PR valve nozzle, the flow through the PR valve nozzle will be liquid and the liquid valve Kd of either 0.65 or 0.62 should be used depending on whether or not the PR valve is capacity certified or not.) ç

Note also that the values of the discharge coefficient, Kd, and back pressure correction factors, Kb and Kw (where applicable) listed in the following procedures are intended only for preliminary sizing. The definitive values of these constants should be obtained from the valve manufacturer once the vendor has been selected.

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Two-Phase Flashing Flow

ç

PR valves handling mixtures of vapor and liquid at inlet conditions should be sized using the following procedure/steps: 1. Determine the accumulated pressure P1, psia (kPa absolute). 2.

ç

Calculate the pressure equivalent to 90% of P1, P9 = 0.9 P1 psia (kPa absolute).

3.

Flash the inlet stream at P1, T1 and also isenthalpically (constant enthalpy) from P1, T1 to P9. Determine the liquid and vapor specific volumes and the vapor mass fraction at P1 and P9.

4.

Calculate the two-phase specific volume at P1 and P9 using the following equations:

ç

v1 = two-phase specific volume at P1, ft3/lb (m3/kg) = vf1 + x1 vfg1

Eq. (10)

v9 = two-phase specific volume at P9, ft3/lb (m3/kg) = vf9 + x9 vfg9

Eq. (11)

where:

5.

vf1 =

Liquid specific volume at P1, ft 3/lb (m3/kg) = 1/rf1

vg1 =

Vapor specific volume at P1, ft3/lb (m3/kg) = 1/rg1

vfg1 =

v91 – vf1

x1 =

Vapor mass fraction at P1

vf9 =

Liquid specific volume at P9, ft3/lb (m3/kg) = 1/rf9

vg9 =

Vapor specific volume at P9, ft3/lb (m3/kg) = 1/rg9

vfg9 =

vg9 – vf9

x9 =

Vapor mass fraction at P9

Calculate the correlation parameter w using the following equation: éæ v ö ù w = 9 êçç 9 ÷÷ - 1ú úû ëêè v1 ø

Eq. (12)

where: v1 and v9 are the two-phase specific volumes at P1 and P9 ç

6.

Calculate Px, the critical flow pressure using the following equation: Px = P1 hc

ç

ç

ç

where: Px = P1 = hc = hc = w=

7.

Eq. (13)

The two-phase critical flow pressure, psia (kPa absolute) The PR valve accumulated pressure, psia (kPa absolute) The two-phase critical pressure ratio, dimensionless 2 3 0.60 + 0.287 log w - 0.0152 (log w) – 0.0197 (log w) Correlation parameter, dimensionless

Eq.(13A)

If Px is greater than (or equal to) the total back pressure, P2 (in psia or kPa absolute), flow through the PR valve is critical and the following equation is used to calculate the required orifice area

A=

W 1702 K d K b K c

A=

31,623 W K d K bK c

v1 w P1 h c

v1 w P1 h c

(Customary)

Eq. (14)

(Metric)

Eq. (14)M

where:

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ç

8.

Page

87 of 156

June, 2004 2

2

A

=

PR valve effective orifice area, in (mm )

Kd

=

Kb

=

Kc

=

P1

=

Effective coefficient of discharge, dimensionless = 0.85 for preliminary sizing Back pressure correction factor (for vapor), dimensionless For conventional or pilot operated valves, Kb = 1.0 For balanced bellows valves, use Figure III-2B. Consider use of balanced bellows or balanced pilot-operated valves if x1 < 0.10. Balanced bellows or balanced pilot-operated valves must be specified if the estimated built-up back pressure exceeds 10% of set pressure. Combination correction factor for installations with a rupture disk upstream of the pressure relief valve. Kc = 1.0 if no rupture disk is installed. Kc = 0.9 if a rupture disk is installed. PR valve accumulated pressure, psia (kPa absolute).

P2

-

v1

=

PR valve total back pressure (superimposed plus built-up), psia (kPa absolute). 3 3 Two-phase specific volume at P1, ft /lb (m /kg).

W

=

PR relieving rate, lb/h (kg/s)

w

=

Correlation parameter, dimensionless

If Px is less than the total back pressure, P2 (in psia, kPa absolute) flow through the PR valve is subcritical and the following equation is used to calculate the required orifice:

A=

W 1702 × K d K bK c

A=

31623 × W K d K bK c

æP ö w çç 1 - 1÷÷ + 1 è P2 ø - 2 [w ln(P2 / P1) + (1 - P2 / P1)(w - 1) ]

v1 P1

v1 P1

æP ö w çç 1 - 1÷÷ + 1 è P2 ø - 2 [w ln(P2 / P1) + (1 - P2 / P1)(w - 1)]

Customary)

Eq. (15)

(Metric)

Eq.(15)M

where:

ç

A = Kd = Kb =

P1 = P2 = v1 = W = w=

PR valve effective orifice area, in.2 (mm2) Discharge coefficient, fraction = 0.85 PR valve correction factor (for vapor), fraction for conventional or pilot operated PR valves Kb is 1.0; for bellows type PR valves the value of Kb must be obtained from the valve manufacturer. The PR valve accumulated pressure, psia (kPa absolute). The PR valve total back pressure (superimposed plus built-up), psia (kPa absolute) Two-phase specific volume at P1, ft3/lb (m3/kg) PR valve relieving rate, lb/hr (kg/s) Correlation parameter, dimensionless

The use of the omega correlation for two-phase physical properties is based on specific assumptions about twophase fluid behavior that may not be applicable to all fluids. For such cases, or whenever increased accuracy is desired, the use of alternative, generally accepted physical property models or rigorous thermodynamic computation based on the Homogeneous Equilibrium Model (HEM) may be considered. Consultation with EMRE’s Safety & Risk Section is recommended before such methods are used.

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Subcooled or Saturated Liquid Inlet

PR valves handling a subcooled or saturated liquid at inlet conditions but which is partially vaporized at the PR valve outlet, should be sized using the following procedure: 1. Determine the accumulated pressure P1, psia (kPa absolute). 2. 3. 4. 5.

Calculate the subcooled liquid saturation pressure, Ps, psia (kPa absolute). This is the pressure at which vaporization starts as the pressure is reduced isenthalpically from the PR valve inlet conditions (P1 and T1). Flash the stream isenthalpically at 0.9×Ps Determine the liquid specific volume, vapor specific volume and vapor mass fraction at 0.9×Ps. Calculate the two-phase specific volume at 0.9×Ps using the following equation: v9 = x9vg9 + (1-x9) vf9

Eq. (16)

where: 3 3 v9 = two-phase specific volume at 90% of saturation pressure, ft /lb (m /kg) 3 3 vg9 = vapor specific volume at 90% of saturation pressure, ft /lb (m /kg) 3 3 vl9 = liquid specific volume at 90% of saturation pressure, ft /lb (m /kg) 3 3 x9 = mass fraction vapor at 90% of saturation pressure, ft /lb (m /kg)

Calculate the saturated correlation parameter, ws, using the following equation

6.

æv ö w s = ¶ çç 9 - 1÷÷ v è 1 ø

Eq. (17)

where: ws = saturated correlation parameter, dimensionless v9 = two-phase specific volume at 90% of saturation pressure, ft3/lb (m3/kg)

v1 = liquid specific volume at PR valve inlet conditions, ft3/lb (m3/kg) 7. a.

Determine if the flashing occurs within the PR valve nozzle in the following manner: Calculate hst, the transition saturation pressure ratio using the following equation: hst =

b. c.

2w s 1 + 2w s

Eq. (18)

Calculate hs = Ps / P1, the saturation pressure ratio Determine the critical pressure ratio,hc, and the critical flow pressure, Px, using equations (20) and (21) OR equations (22) and (23) respectively, depending on the value of hs.

If hs ³ hst, flashing occurs within the PR valve nozzle. In this case, calculate the critical pressure ratio, hc, using Figure III-6 or by solving the following implicit equation (Reference 29) by trial-and-error: æh ö h2 æ 1 çw s + - 2 ÷÷ c - 2(w s - 1)h c + w sh s lnçç c ç 2 w h s è hs ø s è

Px = hc P1

ö ÷ + 1.5w sh s = 1.0 ÷ ø

Eq. (19)

Eq. (20)

Proceed to Step 8.

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If hs < hst, flashing occurs downstream of the PR valve nozzle. In this case: hc = hs

Eq. (21)

Px = hc P1 = hs P1

Eq. (22)

Proceed to Step 9. ç

8. Subcooled or Saturated Liquid Inlet with Flashing Within the PR Valve Nozzle - When the PR valve inlet is saturated or subcooled with flashing occurring within the PR valve nozzle, the flow through the PR valve will be limited by the flashing similar to what occurs with a two-phase flashing fluid, and the PR valve area required is calculated as follows:

A=

W 1702 × K d K w K c

v1 P1

31,623W A= Kd Kw Kc

æh ö w s çç s - 1÷÷ + 1 èh ø 2(1 - h s ) + 2[w sh s ln(h s / h ) - (w s - 1)(h s - h )]

v1 P1

æh ö w s çç s - 1÷÷ + 1 h è ø 2(1 - h s ) + 2[w sh s ln(h s / h ) - (w s - 1)(h s - h )]

where:

ç

9.

Eq. (23)

Eq. (23) M

2

2

A

=

PR valve effective orifice area, in (mm )

Kd

=

Kw

=

Kc

=

P1

=

Effective coefficient of discharge, dimensionless = 0.85 for preliminary sizing Back pressure correction factor balanced bellows valves (liquids) from Figure III-4, dimensionless. Balanced bellows or balanced pilot-operated valves are recommended for this service. Balanced bellows or balanced pilot-operated valves must be specified if the estimated built-up back pressure exceeds 10% of set pressure. For balanced pilot-operated valves Kw = 1.0. Combination correction factor for installations with a rupture disk upstream of the pressure relief valve. Kc = 1.0 if no rupture disk is installed. Kc = 0.9 if a rupture disk is installed. PR valve accumulated pressure, psia (kPa absolute).

P2

-

v1

=

PR valve total back pressure (superimposed plus built-up), psia (kPa absolute). 3 3 Liquid specific volume at P1, ft /lb (m /kg).

W

=

PR relieving rate, lb/h (kg/s)

ws

=

Saturated correlation parameter, dimensionless

hc

=

hs

=

Critical pressure ratio, dimensionless (Equation 20 or Figure III6) Saturation pressure ratio, dimensionless

h

=

hc if Px ³ P2 (Critical flow) P2 / P1 if Px < P2 (Sub-critical flow)

Subcooled Liquid Inlet with Flashing Downstream of the PR Valve Nozzle - When the PR valve inlet is subcooled but flashing occurs downstream of the PR valve nozzle, the flow through the PR valve nozzle is all

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liquid. Flashing will occur within the PR valve body if Ps ³ P2 or in the outlet piping if Ps < P2.. The sizing equation in this case is similar to the equation for all-liquid PR valves, but the flow through the PR valve is a function of either the total back pressure at the PR valve outlet flange, P2, or the saturation pressure, Ps whichever is greater. The PR valve area required is calculated from the following equations, depending on the type of PR valve being used. When flashing occurs after the PR valve nozzle, a capacity certified PR valve is recommended and the PR valve required orifice area is calculated from the following equation: ç

A =

W 305 r f1 K d K u K w K c

A =

W 10 6 r f 1 K d Ku Kw K c

( )

ç

S P1 - P

S 2 (P1 - P )

(Customary)

Eq. (24)

(Metric)

Eq. (24)M

where: 2

2

A

=

PR valve effective orifice area, in (mm )

Kd

=

Km

=

Kw

=

Kc

=

P1

=

Effective coefficient of discharge, dimensionless = 0.65 for preliminary sizing Correction factor for viscous liquids from Figure III-3, dimensionless Back pressure correction factor balanced bellows valves (liquids) from Figure III-4, dimensionless. Balanced bellows or balanced pilot-operated valves must be specified if the estimated built-up back pressure exceeds 10% of set pressure. For balanced pilot-operated valves Kw = 1.0. Combination correction factor for installations with a rupture disk upstream of the pressure relief valve. Kc = 1.0 if no rupture disk is installed. Kc = 0.9 if a rupture disk is installed. PR valve accumulated pressure, psia (kPa absolute).

P2

=

Ps

=

S

-

Total back pressure (superimposed plus built-up), psia (kPa absolute) Subcooled liquid saturation pressure at inlet temperature, psia (kPa absolute) Inlet specific gravity, dimensionless

W

=

PR relieving rate, lb/h (kg/s)

rf1

=

Liquid density at inlet conditions, lb/ft (kg/m )

P

=

If Px ³ P2, P = Ps (critical flow) If Px < P2, P = P2 (sub-critical flow)

3

3

For non-capacity certified safety relief valves, the PR valve area required is calculated from the following equation: ç ç

A =

W 305 r f1 K d K u K w K p K c

A =

W 10 6 Kd Ku Kw K pKc

rf1

( )

S

(1.25 Pset ) - (P - Pa )

S 2 { (1.25 Pset ) - (P - Pa )

}

(Customary)

Eq. (25)

(Metric)

Eq. (25)M

where:

A

=

2

2

PR valve effective orifice area, in (mm )

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Effective coefficient of discharge, dimensionless = 0.62 for preliminary sizing Capacity correction factor due to overpressure from Figure III-5, dimensionless Correction factor for viscous liquids from Figure III-3, dimensionless Back pressure correction factor balanced bellows valves (liquids) from Figure III-4, dimensionless. Balanced bellows or balanced pilot-operated valves must be specified if the estimated built-up back pressure exceeds 10% of set pressure. For balanced pilot-operated valves Kw = 1.0. Combination correction factor for installations with a rupture disk upstream of the pressure relief valve. Kc = 1.0 if no rupture disk is installed. Kc = 0.9 if a rupture disk is installed. PR valve set pressure, psig (kPa gauge)

Kd

=

Kp

=

Km

=

Kw

=

Kc

=

Pset

=

P2

=

Pa

=

Ps

=

S

-

Subcooled liquid saturation pressure at inlet temperature, psia (kPa absolute) Inlet specific gravity, dimensionless

W

=

PR relieving rate, lb/h (kg/s)

rf1

=

Liquid density at inlet conditions, lb/ft (kg/m )

P

=

If Px ³ P2, Ps (critical flow) If Px < P2,, P2 (sub-critical flow)

Total back pressure (superimposed plus built-up), psia (kPa absolute) Atmospheric pressure, psia (kPa absolute)

3

3

SIZING OF PILOT-OPERATED PRESSURE RELIEF VALVES

Sizing methods for pilot-operated pressure relief valves are in accordance with the accepted formulas described above, utilizing the appropriate discharge coefficients and effective orifice areas as recommended by the valve manufacturer. The following points should be noted: 1. Typical discharge coefficients of pilot-operated valves depend on the manufacturer, but are in the range 0.80 to 0.92. The manufacturer value for the valve to be installed should be used in definitive PR valve sizing. For preliminary designs, before the manufacturer is selected, a value of 0.80 can be used. 2. If the pilot valve exhausts to the atmosphere, a pilot-operated valve may be considered a balanced valve. The back pressure correction factor, Kb is 1.0 for critical vapor flow since these PR valves are fully balanced. Unlike a balanced bellow valve, there is no reduction in capacity at increasing back pressure while the flow is critical. 3. Pilot-operated valves have limitations in liquid service and reference should be made to the manufacturer for advice on sizing procedures. 8.5

PREPARATION OF DESIGN SPECIFICATION FOR PRESSURE RELIEF VALVES

Table I-1 represents a typical Pressure Relief Valve specification sheet. The following notes indicate the basis for some of the items which are required in the Design Specification. 8.5.1

Summary of Contingencies

A summary of the relief loads for each of the contingencies considered is provided for each pressure relief valve. This summary should be as complete as possible to ensure proper follow-up later. The contingencies listed include general loss of a utility to one or more operating units, fire and individual equipment operating failure. The loss of a utility to an individual equipment item should be reported as an operating failure. The loss of a utility to one or more operating units should be reported as a utility failure. The relief loads reported under utility failures are used in the design of closed relief systems (see Subsection D and Subsection E) to generate a first-pass estimate of the total

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relief load arising from a site-wide loss of that utility. Refer to Utility Failure as a Cause of Overpressure elsewhere in this Subsection. 8.5.2

Critical Condition

The “critical condition" in the specification sheet is the contingency which determines the valve size, e.g., fire, utility failure or operating failure. 8.5.3

Emergency Temperature

Emergency operating temperature is the inlet fluid temperature under relieving conditions. This temperature is used for sizing the orifice for vapor service. 8.5.4

Design Temperature

The design temperature of the vessel is used to select the PR valve body from manufacturers' temperature and pressure rating tables. During relief the PR valve will be exposed to the emergency operating temperature which may be much higher than the vessel design temperature. Nevertheless the PR valve body selection is not based on the emergency operating temperature since the emergency exposure is an infrequent, short-term stress. An example is a PR valve sized for relief during fire exposure of a vessel containing a high boiling point hydrocarbon. The emergency operating temperature which is equal to the mid-boiling point of the hydrocarbon at the relieving pressure may be considerably higher than the design temperature used to specify the vessel and the PR valve body. For heavier materials/cuts, it may be necessary to separate the system and evaluate T1(s) at various segments in the boiling range. The discharge temperature of the fluid, which may be higher or lower than the design temperature of the PR valve, must be used in the analysis of the collection system, particularly in regard to thermal expansion effects. 8.5.5

Set Pressure

The set pressure (the pressure at which the PR valve is designed to open) is specified in accordance with Code requirements, as covered in Section II, Design Temperature, Design Pressure and Flange Rating. In most vessel applications, the set pressure of at least one PR valve is equal to the design pressure. However, this set pressure must be adjusted downwards, if necessary, for any effect of static head and friction pressure drop that may apply when the valve is installed somewhere other than directly on the vessel it is intended to protect. For example, if a PR valve is installed in a non-flowing line above a liquid-filled vessel, the PR valve set pressure must be reduced sufficiently to allow for the liquid static head between the PR valve and the vessel. It is never permissible, however, to adjust the set pressure upwards to account for static head or frictional pressure drop, since the ASME Code Section VIII requires the set pressure of a single PR device not to exceed the MAWP of the protected equipment. 8.5.6

Allowable Overpressure

The pressure increase over the set pressure of the relieving device allowed to achieve rated flow, expressed as a percentage of set pressure. Overpressure is the same as accumulation (see DEFINITIONS) only when the relieving device is set to open at the maximum allowable working pressure (MAWP) of the vessel. 8.5.7

Estimated Superimposed Back Pressure

Specify the highest expected constant or variable superimposed back pressure at the PR valve discharge flange just before the PR valve opens. The estimated superimposed back pressure is always atmospheric pressure (i.e., zero gauge pressure) for PR valves discharging to atmosphere. For PR valves discharging to a flare or other closed system, the estimated superimposed back pressure may be greater than atmospheric, depending on the conditions prevailing on the discharge system just prior to release. The superimposed back pressure specified in the PR valve data sheet is used to determine the required differential spring pressure for conventional (non-balanced bellows), spring-loaded PR valves. It should not be confused with the maximum allowable superimposed back pressure for non-blowing pressure relief valves, discussed under “EFFECT OF BACK PRESSURE ON PRESSURE RELIEF VALVE”.

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Estimated Built-Up Back Pressure

Specify the maximum estimated built-up back pressure resulting from flow in the discharge system after the PR valve opens. When the actual built-up back-pressure is not known or cannot be estimated, specify the maximum allowable for the type of PR valve being specified. Refer to “DESIGN OF PR VALVE OUTLET PIPING” for limitations on builtup back pressure affecting conventional, spring loaded PR valves. 8.5.9

Estimated Total Back Pressure

Specify the maximum total back pressure when the PR valve is blowing. This is the sum of the estimated superimposed back-pressure and the estimated built-up back pressure. Refer to “DESIGN OF PR VALVE OUTLET PIPING” for limitations on total back pressure affecting balanced bellows, spring loaded PR valves. 8.5.10

Number of Valves Required

Normally a manufacturer's standard PR valve with orifice area equal to or larger than the calculated requirement is specified. In some cases, large relieving rates or to prevent chattering for example, two or more valves are necessary. Likewise, if there is an appreciable difference between the calculated orifice size and the available size, multiple PR valves are desirable to more nearly match the available area to the required orifice area. The determination of set pressures and permissible accumulations for these multiple valve installations is described in PART II of the Design Procedure. The space for “spares" indicates the requirement, if any, for spare PR valves installed on the equipment. Normally, this applies only in the case of refinery preference or local regulations, but is required in many European countries. In some instances, the cost of providing installed spares may be justified by maintenance credits. Unless required by local regulations or justified on maintenance credits, installed spares need not be provided if any one of the following criteria is satisfied: 1.

The PR valve is intended only for the relief of liquid thermal expansion

2.

The PR valve provides overpressure protection only for a fire contingency and there is an alternative overpressure protection plan that includes explicit instructions not to block the equipment in the event of a fire when the PR valve is removed.

3.

The PRV protects only against an exchanger tube split contingency and the ratio of the high-pressure side operating pressure to the low-pressure side design pressure is 3 or less.

4.

The maximum pressure that can be reached in the protected equipment with the PR valve removed under any contingency does not exceed 1.5 times design pressure or the proof test pressure, whichever is lower. In the case of equipment protected by multiple PR valves, credit may be taken for the relief capacity of the PR valves remaining in service when one (or more) PR valves are isolated or removed for maintenance. For PRV’s having a relief rate that is throughput dependent, it is permissible to reduce unit throughput to meet this criterion provided that administrative controls and written procedures are available specifying the need for and extent of throughput reduction required when PR valves are out-of-service.

5.

With the PR valve removed, there is an alternative overpressure protection plan that includes one or more of the following: a.

A permanent or temporary CSO path to an acceptable relief device. Temporary tagging of block valves that must remain open to ensure a relief path is an acceptable alternative to temporary car-seals. The tagging system must be controlled by administrative procedures similar to those applicable to electrical lock-out tagout (LOTO) procedures.

b.

Taking the protected equipment out-of-service

c.

Operator actions that will remove the source of pressure or depressure the equipment before the MAWP can be exceeded. Examples of such actions include locally or remotely shutting down pumps or compressors, or opening PR valve bypasses. However, consideration should be given to how fast an operator can respond relative to the rate of pressure rise. As a general rule, no credit should be taken for operator action if the time it takes to reach the MAWP of the equipment is 2 minutes or less. This situation typically applies to vapor blow-through from a high-pressure to a low-pressure system and to liquid filled systems where closure

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of an automatic control valve or loss of a downstream pump can result in rapid pressure rise above the MAWP. For situations not covered above, installed PR valve spares should be provided. 8.5.11

Differential Spring Pressure

For conventional valves, the differential spring pressure equals the set pressure minus the estimated superimposed back pressure. The estimated superimposed back pressure should not be confused with the maximum allowable superimposed back pressure for non-discharging PR valves discussed under EFFECT OF BACK PRESSURE ON PRESSURE RELIEF VALVE. The estimated superimposed back pressure is the highest anticipated static pressure that exists at the PR valve outlet flange just before the PR valve opens. For balanced PR valves, the opening pressure is not affected by back pressure, and the differential spring pressure equals the set pressure. ç

8.5.12

PR Valve Type and Size

For convenience, valves are specified “Crosby or Farris valves - equivalent accepted." The appropriate valve should be selected from the latest Crosby or Farris (or other vendor) PR valve catalog. If these are not available, Table III-2 or API RP-526 may be used. This table is based on data extracted from Crosby Catalog 310 (1995), and Farris Catalog 193C (1996) and covers the normally available range of conventional and balanced bellows valves which will meet most refinery and chemical plant applications. Table III-3 lists the available range of PR valves for lowtemperature service for both Crosby and Farris. ç

Some valve manufacturers also offer valves in larger areas than those noted in Table III-2. For example, Crosby offers the following (Ref., Crosby Cat. #CROMC-0290, 2002): ç

ç

ç

ORIFICE DESIGNATION

EFFECTIVE ORIFICE AREA in.2 (mm2)

PRESSURE LIMITS, psig (kPa) -20° TO 450°F (-30° TO 230°C)

V W Y Z Z1 Z2 AA BB BB2

42.19 (27219) 60.75 (39193) 82.68 (53342) 90.95 (58677) 96.98 (62568) 108.86 (70232) 136.69 (88000) 168.74 (108864) 185.00 (119355)

300 (2068) 300 (2068) 300 (2068) 300 (2068) 300 (2068) 300 (2068) 300 (2068) 300 (2068) 225 (1551)

As another example, Anderson Greenwood also has a Type 463 pilot operated pressure relief valve with an effective relief area of 38.96 in.2 (25,135 mm2). This model has a single inlet of 8 in. (203 mm) and is available with either one or two 10 in. (254 mm) outlets. This valve can relieve at set pressures between 15 and 1480 psig (103 and 10,200 kPa) within -65 to 500°F (-54 to 260°C) (Ref., Anderson Greenwood Crosby Catalog POPRV-US.96, 2000). For pilot-operated valves and other specialized PR valves, reference should be made to manufacturers' catalogs (for example AGCO). Where possible, soft seal valves should be used to reduce leakage. Sizes or ratings of PR valves that are not normally available are often obtainable by special order, and manufacturers should be consulted in such cases.

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ç

The nomenclature used by Crosby and Farris to identify valve type, and which should be used on the specification sheet, is as follows: Valve Type Designations

Item Construction

Inlet ASME / ANSI Flange Rating

Temperature Range, °F (°C)

Crosby Flanged Full-Nozzle Pressure Relief Valves (Catalog 310, 1995) Designation Description

JOS JBS JBS-BP JLT-JOS JLT-JBS JLT-JBS-BP JOS-H 1 2 3 4 5 6 7 2 4 5 6 7

Conventional Balanced Bellows Bellows with back pressure balancing piston Conventional with liquid trim Bellows with liquid trim Bellows with liquid trim and back pressure balancing piston Conventional open bonnet for ASME Section VIII steam service 150 300 (Light Weight Valve) 300 (Heavy Weight Valve) 600 900 1500 2500 -450 to –76 (-286 to –60) -75 to –21 (-59 to –30) -20 to 450 (-29 to 232) 451 to 800 (233 to 427) 801 to 1000 (428 to 538)

Notes

1

Notes: 1.

The use of “light weight” valves in new construction is not allowed by GP03-15-01.

Valve Type Designations

Item

Farris Series 2600 Cast Steel Flanged Pressure Relief Valves (Catalog 193C, 1996) Designation Description

Prefix

H

Set pressures beyond the scope of ANSI/API Standard 526 (Q, R and T orifices only)

A B C D E F 1/S4 1/S3 1 2 3 4 5

Conventional Bellows Conventional with O ring seat pressure seal Bellows with O ring seat pressure seal Bellows with auxiliary balancing piston Bellows with auxiliary balancing piston and O ring seat pressure seal --450 to –76 (-286 to –60) -75 to –21 (-59 to –30) -20 to 450 (-29 to 232) 451 to 800 (233 to 427) 801 to 1000 (428 to 538) 1001 to 1200 (539 to 649) 1201 to 1500 (650 to 816)

Notes

(if applicable) Construction

Temperature Range, °F (°C)

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Valve Type Designations Farris Series 2600 Cast Steel Flanged Pressure Relief Valves (Catalog 193C, 1996) 0 150 Inlet ASME / 1 300 (Light Weight Valve) ANSI Flange 2 300 (Heavy Weight Valve) Rating 3 600 4 900 5 1500 6 2500 Notes: 1. 2. 3.

ç ç

1

The use of “light weight” valves in new construction is not allowed by GP03-15-01. Use special materials designation S4 for valves operating in this temperature range. Use special materials designation S3 for valves operating in this temperature range.

Additional letters / numbers may be used to indicate additional valve features such as special construction types, inlet flange facing, cap construction, test gag, or special body and trim materials. A different numbering system is used for pilot-operated PR valves (refer to vendors’ catalogs). 8.5.13

Effect of Temperature on Back Pressure Limits of PR Valves

It should be noted that the maximum back pressure limits given in Table III-2 are valid only at 100°F (38°C), for both conventional and bellows type PR valves. These limits must be reduced for higher temperatures, as follows: 1. To the maximum pressure permitted for the outlet flange rating by ANSI B16.5. This applies to both conventional and bellows valves. 2. In the case of a balanced bellows pressure relief valve, to the maximum pressure permitted by considerations of bellows and bellows bonnet flange mechanical strength. This maximum pressure may be obtained by applying the following correction factor to the maximum back pressure listed for 100°F (38°C).

TEMPERATURE

MULTIPLY MAXIMUM BACK PRESSURE AT 100°F BY:

400°F 500°F 600°F 800°F

1.00 0.91 0.83 0.66

TEMPERATURE

MULTIPLY MAXIMUM BACK PRESSURE AT 38°C BY:

200°C 300°C 400°C

1.00 0.85 0.70

[Interpolation is permissible. No correction is required below 400°F (205°C).] In the case of bellows type PR valves, the lower figure obtained from paragraph (1) or (2), above, governs the maximum permissible back pressure. Notes - The “Notes" Should Include Any Relevant Special Factors Such as the Following: 1.

The presence (and concentration, if known) of corrosive materials, other than the typical concentrations of sulfur compounds in petroleum hydrocarbon streams.

2.

Requirements for any special valve features, e.g., non-standard inlet or outlet connections, valve lifting gear, etc.

3.

Requirements for special materials of construction. Standard materials requirements are defined in GP 03-15-01.

4.

Basis for specifying any non-standard or special features.

5.

Autorefrigeration if it affects materials of construction of the collection system.

6.

Clarification of set pressure if different from design pressure of equipment.

7.

Definition of thickness of insulation when sizing the fire load.

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9 DESIGN PROCESS PART IV: PRESSURE RELIEF VALVE SIZING INSTALLATION

This part of the Design Procedure covers the requirements for the design and installation of pressure relief valve inlet and outlet piping manifolds and valving, including PR valve and flare headers. Refer to DP XV-D for flare and blowdown system(s) design. 9.1

PRESSURE RELIEF VALVE LOCATION

A pressure relief valve is normally installed at or near the top of the vessel which it is protecting. However, if local codes do not prohibit, it is permissible to mount the PR valve on the process piping connected to the vessel, provided that the relieving path from the vessel to the PR valve is free of restrictions and permissible pressure drop is not exceeded, in accordance with the requirements listed below. On the same basis, it is also permissible to protect one or more vessels which are connected by piping by a single PR valve (or group of PR valves) mounted on one of the vessels or on the interconnecting piping, provided that: 1. The pressure relieving path between any vessel and a PR valve which protects it must meet the requirements specified in PART I of this Design Procedure under EVALUATION OF ESCAPE PATH IN PRESSURE RELIEF DESIGN. 2. The pressure drop between a vessel or piping on which the PR valve is installed must not exceed the maximum permissible value defined below or the pressure drop must be incorporated into the vessel design pressure. Where a PR valve on a fractionator is used to protect a distillate drum with submerged inlet, the PR valve must be located on the tower itself, rather than on the overhead piping, or it must be discharged to a closed system. This is to preclude liquid release, should the PR valve discharge under fire conditions at the distillate drum. 9.2

SELECTION OF ATMOSPHERIC OR CLOSED DISCHARGE FOR PRESSURE RELIEF VALVES

Routing of PR valve discharges to the atmosphere or to a closed system is determined in accordance with the following criteria: 9.2.1

Discharge to a Closed System

Discharge to a Closed System is Required for PR valves in the following categories:

1. 2. 3. 4. 5.

PR valves handling materials which are liquid or partially liquid at the valve inlet. An exception to this is made for certain thermal expansion relief valves as described below. PR valves normally in vapor service, but which under any design contingency may discharge flammable, corrosive or hazardous liquids. PR valves located in the vapor space of partially liquid-filled vessels when liquid overfill as a cause of overpressure is a design contingency. PR valves handling, flammable, toxic or corrosive vapors which condense at ambient conditions, e.g., phenol or flammable vapors with an average molecular weight greater than 100 (since they may condense). PR valves in toxic vapor services where discharge to the atmosphere would result in the calculated concentration at any working area (either at grade or an elevated platform) exceeding the Short Term Exposure Limit (STEL). Refer also to GP 03-02-04.

6.

Release of flammable vapors which would result after dilution with air in a fuel-air mixture with a concentration above 50% of Lower Flammability Limit (LFL) at grade or any frequently accessed platform or equipment. Refer to DP XV-A for a definition of Flammability Limits.

7.

Releases of flammable vapors which, if discharged to the atmosphere, would in the event of inadvertent ignition, result in radiant heat densities in excess of the permissible exposure level (6000 Btu/h ft2 or 19 kW/m2) for personnel at grade or a frequently manned platform. Note that increasing the height of the riser to reduce radiant heat densities is an acceptable alternative to discharge to a closed system.

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Discharge to a Closed System is Desirable for the following:

1.

2.

PR valves discharging vapors which do not fall into the above categories but which would be significant contributors to atmospheric pollution. Such releases should not normally be used to size the closed system but should be tied into the closed system up to the limit of its capacity. The order of preference for tying in is: (1) malodorous vapors, (2) unsaturated hydrocarbons, and (3) saturated hydrocarbons. If local requirements do not permit such atmospheric discharges, it will be necessary to include these releases in sizing the closed system. PR valves where atmospheric discharge is permissible, but connection to an adjacent closed header (provided that capacity is available) is less costly than an atmospheric discharge line to an acceptable location.

9.2.2

Discharge to Atmosphere

Discharge to Atmosphere is Permitted only if All of the following conditions are satisfied:

1. 2. 3. 4.

PR valves handling only vapor at the valve inlet. For partially liquid-filled vessels, liquid overfill is a remote contingency (see LIQUID OVERFILL AS A CAUSE OF OVERPRESSURE). Discharge to a closed system is not otherwise required. Local regulations regarding atmospheric releases are complied with.

9.2.3

Discharge Paths for Multiple Valves

Some equipment operating in two modes, such as reactors which are periodically regenerated, will require separate PR protection for each service. Special precautions are necessary where the PR valve in normal service discharges hydrocarbons and the valve for the regeneration cycle would discharge air. Where both valves discharge to atmosphere, a caution sign should be posted by the PR valves, and appropriate procedures clearly spelled out in the operating instructions. If the PR valve for hydrocarbon service discharges to a closed system, interlocks should be provided so that only one PR system can be in service at a time, and air from the regeneration cycle is kept out of the closed system. In addition appropriate caution signs and proper instructions and training should be provided. 9.2.4

Application of Criteria for Routing of PR Valve Discharge

The application of the above criteria for routing PR valve discharges in a number of representative plant installations is described below: 1. Fractionating Tower - A pressure relief valve on a fractionating tower in hydrocarbon service can be discharged to the atmosphere, provided that it meets the criteria for atmospheric discharge. Although the PR valve location in the tower top or overhead line is normally exposed to vapor-phase material so that atmospheric discharge is acceptable, liquid may be entrained overhead under certain upset conditions, such as tower flooding, abnormally high liquid level, or backflow from the distillate drum. Analysis of the fractionator design should take into account the possible entrainment rate, the degree of risk, the predicted dispersion, the available holdup before entrainment is a concern, and the time required to recognize and correct the problem. Some entrainment into the PR valve is not a safety concern as long as there is adequate dispersion. Tower overpressure and liquid entrainment should be considered to be a design contingency if both effects result from a single cause. An example is the loss of heat in a series fractionation system. Loss of the upstream reboiler can cause downstream tower overpressure due to lack of condensing capacity as outlined under EVALUATION OF OVERPRESSURE RESULTING FROM EMERGENCY CONDITIONS. This could also lead to jet flooding in the downstream tower's stripping section if the downstream tower's reboiler has sufficient capacity and the control system automatically responds to generate excess vapor. This in turn could result in a vaporliquid mix filling the tower and being carried out of the PR valve. For such a case, the PR valve should discharge to a closed system. When a tower overhead release is all vapor at the PR valve inlet, the possibility of condensation of high molecular weight vapors (molecular weight greater than 100) after release is a concern. Condensation may occur in air, if the lowest atmospheric temperature is below the condensing temperatures of the released hydrocarbon vapors. Based on experience these releases should be tied into a closed system.

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2.

3. 4.

5.

9.3

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Pumps and Fired Heaters - It is not always necessary for a PR valve which must discharge to a closed system to be tied into a flare header. For example, PR valves on fired heaters frequently discharge to the vessel downstream of the fired heater, and PR valves on pumps normally discharge to the pump suction vessel. When pressure variations on the pump suction could result in overpressure on the discharge side, the PR valve must discharge to some safe place other than the suction. As an illustration of a case where a PR valve cannot discharge back into the suction, assume a pump taking suction at 20 psig (150 kPa gage) from the bottom of a tower whose PR valve setting is 60 psig (400 kPa gage). The normal pump discharge pressure is 125 psig (800 kPa gage) and the discharge line PR valve is set at 150 psig (1000 kPa gage). Normal procedure would be to specify the pump PR valve differential spring pressure equal to the required popping pressure minus the maximum suction pressure, or 150 – 60 = 90 psi (1000 – 400 = 600 kPa gage). At normal operating suction pressure this valve would blow at 90 + 20 = 110 psig (600 + 150 = 750 kPa gage). Since the normal pump discharge pressure is 125 psig (800 kPa gage), the PR valve would blow continuously. If the differential spring pressure were based on normal suction pressure, the differential spring pressure would be 150 – 20 = 130 psig (1500 – 120 = 850 kPa gage). Under conditions of maximum suction pressure, this valve would not blow until 130 + 60 = 190 psig (850 + 400 = 1250 kPa gage) pump discharge pressure had been reached. This would exceed the downstream safe working pressure. As an alternative, a balanced bellows valve could be used since it is not affected by a variable superimposed back pressure (see PART II of this Design Procedure for bellows vent). Thermal Expansion Relief Valves - Routing of thermal expansion relief valve discharges is covered in PART I of this Design Procedure, under OVERPRESSURE CAUSED BY THERMAL EXPANSION. Waste Heat Boilers - A PR valve installed on the generating exchanger shell of a waste heat boiler (as opposed to installation on the steam drum) will in most designs discharge a mixture of boiling water and steam. This mixture cannot be safely discharged to the atmosphere, either at grade or at an elevated location, and a means of separating water from steam, such as a blowdown drum, must be provided to enable the two phases to be safely discharged. Heat Exchangers and Condensers - PR valves installed on heat exchangers and condensers for protection against a split tube should be discharged into a closed system if liquid can be discharged. PREVENTION OF PLUGGING IN PR VALVE INLETS OR OUTLETS

(Refer also to GP 03-02-04) 1. Heat tracing of PR valve inlet and/or outlet piping should be provided where plugging by icing, salt formation, hydrate formation, deposition of wax or congealing of viscous liquids may occur at ambient temperatures. Tracers used for this purpose are considered safety critical since loss of the tracers can render the PR valve useless. Such tracers should be clearly identified in the field, periodically checked to ensure their correct operation and promptly repaired when necessary. Consideration should be given to providing redundant tracers fed from independent sources in these applications. 2. Where inlet and/or piping plugging may occur as the result of coke formation, solids deposition, etc., from the process stream, a continuous purge or blowback injection of clean fluid (e.g., steam or flushing oil) should be provided. The effectiveness of the purge is dependent on the choice of clean fluid and the rate at which it is injected. Flow of purge fluid is normally controlled by a restriction orifice sized to provide the following minimum velocities in the inlet line: 3.0 ft/s (1 m/sec) if steam, treat gas or other gases are used as the clean fluid; 1.0 ft/s (0.3 m/s) if flushing oil is used and the fouling stream is otherwise in direct contact with the PR valve; 0.1 ft/s (0.03 m/s) if flushing oil is used and the fouling stream would not be in direct contact with the PR valve. When the fouling stream is a viscous liquid or a slurry the preferred purge medium is flushing oil. Clean fluid for PR valve purging must be provided from a reliable source. All purge connections must comply with GP 03-06-03. In addition, in critical services where likelihood of fouling is high (i.e., resid.) or where the purge media may not be reliable, the purge connections must be provided with a low flow alarm. 3. In the particular case of catalytic cracking reactor PR valves, experience has demonstrated that the inlet lines can be kept free of plugging by catalyst and coke if they are provided with an internal extension elbow within the reactor facing horizontally toward the vessel centerline. Any internal connection must be equal to or larger than the diameter of the pressure relief valve inlet. This is in addition to the steam purge.

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ç

9.4

DESIGN OF PR VALVE INLET PIPING

9.4.1

Inlet Piping Pressure Drop

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The total inlet frictional pressure drop between a vessel and the inlet of the pressure relief valve should be less than 3% of the set pressure (gage) for set pressures 50 psig/345 kPa gage or higher; or less than 5% for set pressures below 50 psig/345 kPa gage. The limitation on inlet pressure applies to conventional, pilot operated and balanced bellows PR valves. Where differential spring pressure is less than set pressure, pressure drop is based on set pressure. For remote contingencies, the maximum permissible inlet piping pressure drop is 4% of set pressure for set pressures 50 psig (345 kPag) or higher and 7% for set pressures lower than 50 psig (345 kPag). The limiting pressure drop is that calculated for the maximum (rated) capacity, based on selected orifice size, of the valve installed for the contingency that results in the maximum frictional pressure drop, considering the effects of temperature and molecular weight or specific gravity. Rated capacity shall be used except for cases involving either fire load relief, or relief of fluids that are 100% liquid at the pressure relief valve inlet (regardless of whether or not flashing occurs across the PR valve and regardless of whether or not the PR valve is liquid capacity certified). In these two cases, the design relief load shall be used. Note that the contingency that sets the PR valve size is not always that which results in the maximum inlet line pressure drop. Therefore, the sizing contingency and any other valid contingency that results in a required relief area equal to or greater than 75% of the relief area required for the sizing contingency should be checked.. The limiting pressure drop is that calculated for friction only, including contraction and expansion losses, and does not include the effect of fluid acceleration on static pressure. The purpose of this limitation is to prevent chattering as described in detail in PART II of this Design Procedure. Chattering caused by undersized inlet piping may sometimes be minimized on pilot-operated PR valves if the pilot valve pressure tapping is taken directly from the vessel being protected. However, it is recommended that the above inlet pressure drop limitations still be applied, to avoid the capacity reduction that would result from excessive inlet losses and to ensure freedom from chatter. ç

9.4.2

Inlet Pipe Sizing

The entire inlet line must be at least the size of the PR valve inlet. When multiple safety valves are manifolded on the inlet side, the cross-sectional area of the manifold piping should be equal to or greater than the sum of all the inlet areas of valves open to the manifold. However, existing inlet manifolds that do not meet the cross-sectional area requirement are acceptable, provided that the pressure drop limitations discussed above are met. 9.4.3

Inlet Pipe Layout

Inlet piping to PR valves should be continuously sloped upwards from the vessel, to avoid liquid traps. 9.5

DESIGN OF PR VALVE OUTLET PIPING

9.5.1

Discharge to Atmosphere

When discharge of a PR valve to the atmosphere is acceptable (see SELECTION OF ATMOSPHERIC OR CLOSED DISCHARGE FOR PRESSURE RELIEF VALVES elsewhere in this Subsection), the following guidelines are applicable. 1. The requirements of GP 03-02-04 under the heading Discharge to Atmosphere, covering discharge risers for PR valves, including bracing and supports, elevation, snuffing steam connections, toroidal rings and drainage, must be satisfied. 2. The built-up back pressure limitations defined in GP 03-02-04 must be met. See also PREPARATION OF DESIGN SPECIFICATION FOR PR VALVES under PART III of this Design Procedure. 3. The radiant flux at grade level (or frequently occupied platforms), resulting from inadvertent ignition shall not exceed 6000 Btu/h ft2 (19 kW/m2). The criterion for application to inadvertently ignited atmospheric releases 2 2 from pressure relief valves or vents is less restrictive than that used for flare design (3000 Btu/h ft (9.5 kW/m )) because a flare is a continuous source of ignition, but accidental ignition of an atmospheric release is a lowprobability event. In addition, the area surrounding a flare is open and offers no protection, while within a process unit access to shelter is usually available. Calculation of radiant heat density follows the procedure

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detailed for flares in Appendix B of DP XV-E, with the exception that lower values are used for F, the fraction of the heat release radiated, because of the generally higher exit velocities associated with PR valve discharges: F FOR PR VALVE RELEASES Hydrogen, methane

0.1

C2 and heavier hydrocarbons

0.25

For releases containing hydrogen at a concentration exceeding 50 mole %, or for releases above their autoignition temperature of above 600°F (315°C), whichever is less, the probability of accidental ignition is higher 2 2 and the radiant flux at grade or frequently occupied platforms shall not exceed 3000 Btu/h ft (9.5 kW/m ), unless safety critical instrumentation is provided to reduce the probability of a PR valve release. 4. 5.

6.

7.

8.

No restrictions such as check valves, flame arresters, orifice plates, etc. are permitted in the outlet piping. The maximum exit velocity at design capacity shall not exceed 75% of sonic to limit noise problems and avoid choked flow. If a section of enlarged diameter piping is used to limit the exit velocity, its length shall be at least 10 diameters of the enlarged piping. In flammable vapor service, the minimum exit velocity shall be 100 ft/s (30 m/s) at the lowest anticipated relief rate or at 25% of the rated capacity of the PR valve, whichever is greater. If this criterion is not satisfied, dispersion calculations are required to confirm that the concentration of flammable vapor at grade or any frequently accessed platform is below 50% of the LFL. The design temperature of outlet piping from PR valves discharging to the atmosphere is typically ambient. However, autorefrigeration and need for brittle-fracture-resistant materials (see DP II and GP 03-07-01) or thermal expansion forces should be examined if the release pipe is unusually long or unusually hot/cold. Where two or more PR valves are manifolded into a single riser discharging to the atmosphere, the following additional requirements apply: a. Isolation valves in the individual PR valve outlet lines should be provided in accordance with the requirements of GP 03-02-04, to permit safe removal of one PR valve for maintenance during plant operation. b. The combined atmospheric discharge system must be designed to comply with the back pressure limitations defined in GP 03-02-04 for blowing and non-blowing PR valves c. The maximum velocity in the combined discharge header at design capacity shall not exceed 75% of sonic. d.

9.

In flammable vapor service, the minimum exit velocity from the combined riser shall be 100 ft/s (30 m/s) at the lowest anticipated relief rate or at 25% of the rated capacity of the PR valve having the least relief area, whichever is greater. If this criterion is not satisfied, dispersion calculations are required to confirm that the concentration of flammable vapor at grade or any frequently accessed platform is below 50% of the LFL. Outlet pipe sizing shall be as described below for Discharge to a Closed System.

9.5.2

Discharge to a Closed System

Pressure relief valves that do not meet the criteria for discharge to atmosphere (see SELECTION OF ATMOSPHERIC OR CLOSED DISCHARGE FOR PRESSURE RELIEF VALVES elsewhere in this Subsection) or for which discharge to a closed system is otherwise desirable are manifolded into a closed system. The closed system typically consists of collection headers leading into a blowdown drum where vapor and liquid are separated. The liquid portion is recovered as slop and the vapor portion is routed to a flare via a seal drum or equivalent device. Details of various types of closed collection systems, blowdown drum, seal devices and flares are included in DP XVD and DP XV-E of these Design Practices. ç

The following guidelines apply to the design of PR valve outlet piping discharging to a closed system: 1.

The discharge line nominal diameter shall not be less than the nominal diameter of the PR valve outlet flange. When two or more PR valves in the same service are manifolded together into a common discharge line, the cross-sectional area of the common discharge line should not be less than the sum of the cross sectional flow area of the outlet flanges of the PR valves discharging into it. However, existing discharge manifolds that do not meet the cross-sectional area requirement are acceptable provided that the built-up back pressure limitations discussed elsewhere are met.

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2.

The discharge piping for each individual PR valve shall be sized using the PR valve rated capacity for all contingencies except those involving either fire load relief, or relief of fluids that are 100% liquid at the pressure relief valve inlet (regardless of whether or not flashing occurs across the PR valve and regardless of whether or not the PR valve is liquid capacity certified). In these two cases, the design capacity may be used. This sizing basis also applies to any manifold that collects the discharge from two or more PR valves in the same service. Note that the contingency that sets the PR valve size is not necessarily that which results in the maximum builtup back pressure. This is particularly true if different contingencies result in the relief of different phases or greatly different molecular weight or specific gravity fluids. Therefore, the sizing contingency and any other valid contingency that results in a required relief area equal to or greater than 75% of the relief area required for the sizing contingency should be checked.

3.

Piping that collects the discharge from two or more PR valves in different services that relieve simultaneously during a design contingency shall be sized for the sum of the individual PR valve relief loads for that contingency (not necessarily the sum of their rated capacities). See also DP XV D, Disposal Systems.

4.

For a design contingency (including fire), the built-up back pressure for conventional spring-loaded pressure relief valves shall not exceed the following: ç

Vessel Type

Type of Contingency

No. of PR Valves in Parallel

Allowable Built-Up Back Pressure, % of MAWP

Fired boiler

Any

Any

6

Design (except fire)

1

10 or 3 psi (20.7 kPa)

2 or more

whichever is greater

(ASME Section I) ç

Unfired Pressure Vessel (ASME Section VIII)

16 or 4 psi (27.6 kPa) whichever is greater Fire

Any

21

For a remote contingency, the maximum allowable built-up back pressure for conventional spring-loaded pressure relief valves shall be: Pbu(max.) = 0.173 C Pset Where: Pbu(max.) = Maximum built-up back pressure Pset = PRV set pressure C = Multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01, dimensionless 5.

For a design contingency (including fire),the total back pressure for balanced bellows pressure relief valves shall not exceed 50% of set pressure. For total back pressures in excess of 30% of set pressure for valves in vapor service or 15% of set pressure for valves in liquid service, a back pressure correction factor shall be applied as recommended by the manufacturer or as obtained from Figure III-2B or Figure III-4. For pilot operated PR valves, the total back pressure shall not exceed 75% of set pressure. For a remote contingency, the maximum allowable total back pressure for balanced bellows and pilot operated pressure relief valves shall be: Pb(max.) = 0.50 C Pset Where: Pb(max.) = Maximum built-up back pressure

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Pset = PRV set pressure C = Multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01, dimensionless The back pressure correction factor for balanced bellows pressure relief valves for a remote contingency may be obtained from Figure III-2B or Figure III-4 using the effective set pressure in place of the set pressure in the calculation of % Gauge Back Pressure. The effective set pressure is defined as follows: ç

Pse = C Pset / (1 + Allowable Accumulation/100) Where: Pse = effective set pressure Pset = actual set pressure C = Multiplier applied to design pressure to obtain hydrostatic test pressure per GP 05-03-01, dimensionless 6.

No restrictions such as check valves, flame arresters, orifice plates, etc. are permitted in the outlet piping.

7.

The maximum exit velocity at design capacity shall not exceed 75% of sonic to minimize potential vibration problems and avoid choked flow.

8.

The design temperature of all piping, headers, blowdown drums, etc., in a closed release system must consider the most extreme actual release conditions associated with any design contingency. The application of this design basis includes the following considerations:

9.6

a.

Low temperatures which may result from autorefrigeration or expansion as process fluids are discharged through PR valves. See DP II and GP 03-07-01.

b.

Expansion temperature drop in the case of hot releases, and atmospheric cooling of the header if this can be realistically calculated

c.

An in-line heater on the vapor outlet of a blowdown drum is a permissible means of protecting the downstream header and flare against low temperatures that could result from cold vapor releases, or from the weathering of cold liquids in the drum. Normally, the in-line heater consists of a section of steam jacketing on the header, with a continuous steam supply and an independent low temperature alarm. The design must also provide positive means for condensate removal, so as to avoid loss of heat transfer and possible ice formation. Acceptable designs include a barometric seal leg (where steam pressure is low enough) or a steam condensate drum with 15 minutes holdup between a normal high level and an emergency high level with independent dump system. It is important that no condensate appears in the inline heater at any time. However, flare line heaters are not permissible in lines subject to liquid shock chilling where the possibility of heater failure could result in brittle fracture.

d.

Flare system designs must also include means of preventing freezing of seal water in the flare seal drum, if entering vapors may be below 32°F (0°C), as described in DP XV-E. ISOLATION VALVES FOR PRESSURE RELIEF SYSTEMS

Block valves for maintenance isolation purposes (line size for flare header, or flange size for PR valve inlet and outlet) are permissible in pressure relieving systems, provided that they are car-sealed open and comply with the requirements of CSO valves defined in this Design Procedure PART I of this section and in GP 03-02-04. The particular locations where such CSO valves are permitted are: a. PR valve inlets, where isolation of the PR valve for onstream maintenance is required, subject to compliance with local codes. b. PR valve outlets which are manifolded to a closed system or combined atmospheric vent, where isolation of the PR valve for onstream maintenance is required, subject to compliance with local codes. c. A flare header at the battery limit of a unit that shuts down independently of other units tied into the same header.

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TABLE I-1A PRESSURE RELIEF VALVE CONTINGENCIES (CUSTOMARY) CONTINGENCIES(4)

1

ITEM NUMBER

2 3 4

SERVICE FLUID CRITICAL CONDITION

STEAM TEMPERATURE

5 6 7 8

DISPOSITION

VAPOR

PERFORMANCE DATA TOTAL LIQUID RATE @ Conditions(1) LIQUID SPECIFIC GRAVITY @ Conditions

9 10

gpm

12 13 14

LIQUID

-------------------------

LIQUID SPECIFIC GRAVITY @ 60 °F LIQUID VISCOSITY @ Conditions cP

11

VAPOR -------------

LIQUID

COOLING WATER

-------------

TEMPERATURE VAPOR

TOTAL VAPOR RATE(1) VAPOR MOLECULAR WEIGHT

15

klb/hr

°F klb/hr MW gpm SGc

-------------

LIQUID

-------------------------------------

°F klb/hr MW gpm SGc

16 17 18

COMPRESSIBILITY FACTOR SPECIFIC HEAT RATIO, Cp / Cv

19 20

TWO PHASE FLOW (YES OR NO) EMERGENCY TEMPERATURE(2)

21 22

DESIGN TEMPERATURE SET PRESSURE

psig

23 24 25

ALLOWABLE OVERPRESSURE % EST. SUPERIMPOSED BACK PRESSURE EST. BUILT-UP BACK PRESSURE

psig psi

26 27 28 29

EST. TOTAL BACK PRESSURE psig

VAPOR

VALVE DATA TOTAL NUMBER REQUIRED

LIQUID

30 31 32

NUMBER IN SERVICE NUMBER AS SPARES

33 34

DIFFERENTIAL SPRING PRESSURE REQ'D ORIFICE AREA PER VALVE(3)

psi in.2

VAPOR

klb/hr MW

35

INSTALLED ORIFICE AREA PER VALVE VALVE TYPE

in.2

LIQUID

gpm

36 37 38

VALVE SIZE INLET/ORIFICE LETTER/OUTLET IF LIQUID, CAPACITY CERTIFIED (YES OR NO)

39

WAREHOUSE SPARE REQUIRED (YES OR NO)

°F °F

POWER TEMPERATURE

°F

VAPOR

klb/hr MW

LIQUID

gpm SGc

INSTRUMENT AIR TEMPERATURE

FIRE TEMPERATURE

°F klb/hr MW gpm SGc

°F

SGc OPERATING(5) TEMPERATURE

40 41 42 43

VAPOR

44

CAUSE

LIQUID

°F klb/hr MW gpm SGc

Notes:

(1)

Vapor and liquid rates shown are those at the inlet of the valve when the valve is relieving. For valves in flashing service, they are not necessarily the rates used to calculate the required orifice area.

(2)

Emergency temperature is the inlet temperature when the valve is relieving.

(3)

This is the minimum area permitted in the purchased valve(s). If this valve is in flashing service, the area required in Line 34 may be greater than that calculated from the flashing service procedure given in API RP-520. The larger area must be provided.

(4)

Conditions shown assume a pressure of 14.7 psia at the relief valve outlet.

(5)

Added additional sheets as necessary.

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TABLE I-1B PRESSURE RELIEF VALVE CONTINGENCIES (METRIC) CONTINGENCIES(4)

1

ITEM NUMBER

2 3 4

SERVICE FLUID CRITICAL CONDITION

STEAM TEMPERATURE

5 6 7

DISPOSITION

VAPOR

8

TOTAL LIQUID RATE @ Conditions(1) LIQUID SPECIFIC GRAVITY @ Conditions

PERFORMANCE DATA

9 10

VAPOR m3/h

12 13 14

LIQUID

SGc

-------------------------

LIQUID SPECIFIC GRAVITY @ 15.5°C LIQUID VISCOSITY @ Conditions cP

11

LIQUID

------------COOLING WATER

-------------

TEMPERATURE VAPOR

15

TOTAL VAPOR RATE(1) VAPOR MOLECULAR WEIGHT

16 17

COMPRESSIBILITY FACTOR SPECIFIC HEAT RATIO, Cp / Cv

kg/h

°C kg/h MW m3/h

-------------

LIQUID

-------------

SGc

-------------------------

18

°C kg/h MW m3/h

POWER

TEMPERATURE

°C

VAPOR

kg/h MW

LIQUID

m3/h SGc

19 20

TWO PHASE FLOW (YES OR NO) EMERGENCY TEMPERATURE (2)

21 22

DESIGN TEMPERATURE SET PRESSURE

kPa(g)

23 24 25

ALLOWABLE OVERPRESSURE % EST. SUPERIMPOSED BACK PRESSURE EST. BUILT-UP BACK PRESSURE

kPa(g) kPa

26 27 28

EST. TOTAL BACK PRESSURE kPa(g)

VAPOR

VALVE DATA

LIQUID

29

TOTAL NUMBER REQUIRED

30 31 32

NUMBER IN SERVICE NUMBER AS SPARES

33 34

DIFFERENTIAL SPRING PRESSURE REQ'D ORIFICE AREA PER VALVE(3)

kPa mm2

VAPOR

kg/h MW

35

INSTALLED ORIFICE AREA PER VALVE VALVE TYPE

mm2

LIQUID

36

m3/h SGc

37 38

VALVE SIZE INLET/ORIFICE LETTER/OUTLET IF LIQUID, CAPACITY CERTIFIED (YES OR NO)

39

WAREHOUSE SPARE REQUIRED (YES OR NO)

°C °C

INSTRUMENT AIR TEMPERATURE

°C kg/h MW m3/h SGc

FIRE TEMPERATURE

40 41 42

OPERATING(5) TEMPERATURE

VAPOR LIQUID

°C

°C kg/h MW m3/h SGc

43 44

CAUSE Notes:

(1)

Vapor and liquid rates shown are those at the inlet of the valve when the valve is relieving. For valves in flashing service, they are not necessarily the rates used to calculate the required orifice area.

(2)

Emergency temperature is the inlet temperature when the valve is relieving.

(3)

This is the minimum area permitted in the purchased valve(s). If this valve is in flashing service, the area required in Line 34 may be greater than that calculated from the flashing service procedure given in API RP-520. The larger area must be provided.

(4)

Conditions shown are assuming a pressure of 1 bara at the relief valve outlet to flare.

(5)

Add additional sheets as necessary.

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72 °F (22 °C) 100

Inconel Relative Burst Pressure, %

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FIGURE I-1 BOTTOM AND TOP-GUIDED LOW-LIFT VALVE FOR TURBINE EXHAUST

90

80

Nickel 70 Aluminum 60

0 (-18)

DP15CII11

200 (93)

400 (204)

Stainless Steel

600 (315)

800 (426)

Temperature, °F ( °C)

Note:

(1)

Page

Fresh water is required for sealing system.

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TABLE II-1 SUMMARY OF ACCEPTABLE RUPTURE DISCS

SERVICE

Gas, Vapor, or Two-Phase

Liquid (only) or Combinations

ACCEPTABLE RUPTURE DISK TYPES

USE LIMITATIONS

MAX. OPERATING PRESSURE(2)

Pre-scored Conventional (Tension-Loaded) Rupture Disc

None

0.85 Pset

Pre-scored (Cross Score Pattern) Reverse Buckling Rupture Disc

None

0.90 Pset

Semi-circular Score Reverse Buckling Rupture Disc in special disc holder (such as the BS&B Model CSR-7RB)

None

0.90 Pset

Semi-circular Score Reverse Buckling Rupture Disc in conventional disc holder (such as the BS&B Model CSR-7RS)

Not under a PR Valve

0.90 Pset

Pre-scored Conventional (Tension-Loaded) Rupture Disc

None(1)

0.85 Pset

Semi-circular Score Reverse Buckling Rupture Disc in special disc holder ( such as the BS&B Model CSR-7RB)

None(1)

0.90 Pset

Semi-circular Score Reverse Buckling Rupture Disc in conventional disc holder (such as the BS&B Model CSR-7RS)

Not under a PR Valve(1)

0.90 Pset

For more information, see Report EE.92E.92.

Notes:

1.

In liquid service the petals or flap may not open completely. To account for the additional pressure drop across the partly open rupture disc, the rupture disc holder assembly should be considered as an orifice (Kd = 0.6) with a flow area equivalent to one-half of the nominal pipe flow area. This pressure drop would be in addition to the pressure drop for the disc holder which is equivalent to the pressure drop in a pipe 75 pipe diameters in length.

2.

Pset = Upstream pressure at which rupture disc is intended to burst. When the superimposed back pressure is zero, Pset equals the rupture disc bursting differential pressure. When the superimposed back pressure is greater than zero, Pset equals the rupture disc bursting differential pressure plus the superimposed back pressure.

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TABLE II 2 (1) TYPICAL MANUFACTURING RANGES FOR RUPTURE DISCS DISC TYPE

BURST PRESSURE, PB PSIG (KPA GAUGE)

Pre-scored Conventional (Tension-Loaded Rupture Disc

Reverse Buckling Rupture Disc

MANUFACTURING RANGE, %

20 to 45 (138 to 310)

-7/+14

46 to 90 (317 to 620)

-6/+12

91 to 270 (627 to 1862)

-5/+10

271 to 500 (1868 to 3448)

-4/+8

Above 500 (3448)

-3/+6

7 to 10 (48 to 69)

-15/+30

11 to 15 (76 to 103)

-10/+20

16 to 25 (110 to 172)

-8/+16

26 to 45 (179 to 310)

-7/+14

46 to 90 (317 to 620)

-6/+12

91 to 270 (627 to 1862)

-5/+10

271 to 500 (1868 to 3448)

-4/+8

Above 500 (3448)

-3/+6

Note:

(1)

These are typical standard manufacturing ranges. Lower ranges may be available at additional cost. Additional information is available in EE.79E.84.

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TABLE II-3 RUPTURE DISC SPECIFICATION SHEET

Unit ___________________________ by ___________________________ date ____________________________ Item Number Service Fluid Controlling Contingency Disposition Total Liquid Rate · Liquid S.G. @ Conditions

gpm (m3/hr) @ cond.

· Liquid S.G. @ Conditions

Total Vapor Rate

cP k lb/hr (kg/s)

· Vapor Molecular Weight · Compressibility Factor @ Inlet Conditions · Cp / Cv Ratio @ Inlet Conditions

Corrosive/Fouling Compounds Normal System Operating Temperature °F (°C) Normal System Operating Pressure psig (kPa gage) System Design Pressure psig (kPa gage) Static Back Pressure psig (kPa gage) Maximum Transient Back Pressure psig (kPa gage) Allowed Overpressure % Fluid Temperature @ Controlling Contingency °F (°C) DISC DATA Total Number Required Number in Service Number as Spares Rupture Disc Diameter Required/Actual Disc Type(1) Required Burst Pressure (@ Required Burst Temperature) Required Burst Temperature(2) Allowable Manufacturing Range Required Disc Material Design Temperature of Safety Head Safety Head Materials

/

in. (mm) psig (kPa gage) °F (°C)

+%

/–% °F (°C)

Notes:

(1)

Reverse buckling discs are not acceptable in liquid service.

(2)

Required Burst Temperature is the coldest temperature at disc when it may need to relieve overpressure. Requires special consideration for discs located away from protected equipment.

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TABLE II-4 TYPICAL PRESSURE TEMPERATURE LIMITS FOR PRE-SCORED REVERSE BUCKLING RUPTURE DISCS(1)

ALUMINUM SIZE, in. (mm)

NICKEL

MIN Pb(2) psig kPa)

MAX psig

Pb(2) (kPa)

MIN psig

Pb(2) (kPa)

MAX psig

316 SS Pb(2) (kPa)

MIN psig

Pb(2) (kPa)

MAX psig

MONEL / INCONEL Pb(2) (kPa)

MIN psig

Pb(2) (kPa)

MAX psig

Pb(2) (kPa)

1

(25)

75

(520)

125

(860)

125

(860) 1,000 (6,900)

328

(2,260) 1,000

(6,900)

150

(1,035)

1,000

(6,900)

1.5

(38)

54

(370)

90

(620)

90

(620) 1,000 (6,900)

282

(1,945) 1,000

(6,900)

110

(760)

1,000

(6,900)

2

(50)

45

(310)

75

(520)

75

(520) 1,000 (6,900)

230

(1,595) 1,000

(6,900)

90

(620)

1,000

(6,900)

3

(75)

36

(250)

60

(415)

60

(415) 1,000 (6,900)

167

(1,150) 1,000

(6,900)

72

(500)

1,000

(6,900)

4

(100)

30

(206)

50

(345)

50

(345)

800

(5,500)

132

(910)

800

(5,500)

60

(415)

800

(5,500)

6

(150)

24

(165)

40

(275)

40

(275)

800

(5,500)

92

(635)

800

(5,500)

48

(330)

800

(5,500)

8

(200)

-

-

-

-

35

(245)

700

(4,830)

-

-

-

-

42

(290)

700

(4,830)

10

(250)

-

-

-

-

30

(206)

700

(4,830)

-

-

-

-

36

(250)

700

(4,830)

12

(300)

-

-

-

-

27

(185)

600

(4,140)

-

-

-

-

33

(230)

600

(4,140)

16

(400)

-

-

-

-

23

(150)

100

(690)

-

-

-

-

28

(190)

180

(1,240)

18

(450)

-

-

-

-

22

(150)

92

(635)

-

-

-

-

26

(180)

160

(1,100)

20

(500)

-

-

-

-

21

(145)

84

(586)

-

-

-

-

24

(165)

142

(980)

24

(600)

-

-

-

-

20

(138)

70

(485)

-

-

-

-

22

(150)

118

(815)

Max. T, °F (°C)

250 (120)

750 (400)

900 (480)

800 / 1,000 (425 / 540)

Notes:

(1)

All data for unlined/uncoated discs. Maximum temperature and maximum/minimum pressures are not simultaneous. Maximum/minimum burst pressure listed is at 72°F (20°C). Data represent range offered by various manufacturers.

(2)

Pb = burst pressure, gage.

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TABLE II-5 TYPICAL PRESSURE TEMPERATURE LIMITS FOR PRE-SCORED TENSION-LOADED RUPTURE DISCS(1)

ALUMINUM SIZE, in. (mm)

MIN psig

Pb(2)( kPa)

NICKEL

MAX psig

Pb(2) (kPa)

MIN psig

Pb(2) (kPa)

316SS

MAX psig

Pb(2) (kPa)

MIN psig

Pb(2) (kPa)

MAX psig

MONEL Pb(2) (kPa)

MIN psig

Pb(2) (kPa)

INCONEL

MAX psig

Pb(2) (kPa)

MIN psig

Pb(2) (kPa)

MAX psig

Pb(2) (kPa)

0.5

(12)

45

(310)

250

(1,520)

600

(4,140)

350

(2,620)

350

(2,620)

1

(25)

30

(206)

188

(1300)

150

(1,035)

1,500

(10,300)

350

(2,620)

225

(1,550)

1,500

(10,300)

225

(1,550)

1,800

(124,000)

1.5

(38)

25

(170)

135

(930)

100

(690)

1,500

(10,300)

300

(2,070)

165

(1,140)

1,500

(10,300)

165

(1,140)

1,800

(124,000)

2

(50)

20

(138)

113

(780)

50

(345)

1,350

(9,310)

200

(1,380)

100

(690)

1,500

(10,300)

225

(1,550)

1,800

(124,000)

3

(75)

15

(103)

90

(620)

45

(310)

1,250

(8,620)

150

(1,035)

80

(550)

1,400

(9,650)

80

(550)

1,600

(112,000)

4

(100)

15

(103)

75

(520)

40

(275)

1,200

(8,275)

125

(860)

65

(450)

1,200

(8,275)

65

(450)

1,400

(9,650)

6

(150)

10

(68)

60

(415)

35

(245)

1,200

(8,275)

100

(690)

60

(415)

1,200

(8,275)

60

(415)

1,400

(9,650)

8

(200)

-

-

-

-

30

(206)

1,100

(7,580)

75

(520)

55

(380)

1,100

(7,580)

55

(380)

1,300

(8,960)

10

(250)

-

-

-

-

24

(165)

1,100

(7,580)

60

(415)

44

(300)

1,100

(7,580)

44

(300)

1,300

(8,960)

12

(300)

-

-

-

-

20

(138)

900

(6,200)

50

(345)

37

(255)

900

(6,200)

37

(255)

1,100

(7,580)

14

(350)

-

-

-

-

17

(120)

43

(300)

32

(220)

32

(22)

16

(400)

-

-

-

-

30

(206)

85

(585)

65

(450)

65

(450)

18

(450)

-

-

-

-

25

(170)

75

(520)

55

(380)

55

(380)

20

(500)

-

-

-

-

25

(170)

65

(450)

50

(345)

50

(345)

24

(600)

-

-

-

-

20

(138)

55

(380)

45

(310)

45

(310)

Max. T, °F (°C)

250 (120)

750 (400)

900 (480)

800 (425)

1,000 (540)

Notes:

(1)

All data for unlined/uncoated discs. Maximum temperature and maximum/minimum pressures are not simultaneous. Maximum/minimum burst pressure listed is at 72°F (20°C). Data represent range offered by various manufacturers.

(2)

Pb = burst pressure, gage.

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FIGURE II-1 TYPICAL CONVENTIONAL PRESSURE RELIEF VALVE

Cap Stem Spring Adjustment Jam Nut (Spring Adjusting Screw) Cap Gasket Bonnet Spring Button Spring Spring Button Vent (Normally Plugged) Stem Retainer Sleeve Guide Bonnet Gasket Body Stud Bonnet Vent Opening into Valve Outlet

Hex Nut Body Gasket Disc Holder Locking Screw Disc Disc Holder Blowdown Ring Locking Stud Locking Screw Gasket

Outlet

Blowdown Ring Locking Screw Hex Nut (Blowdown Ring Locking Screw) Blowdown Ring Drain (Normally Plugged) Nozzle Body Nozzle Gasket DP15CFII1

Inlet

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PRESSURE VALVE REQUIREMENTS

VESSEL PRESSURE

Maximum accumulated (fire exposure

TYPICAL CHARACTERISTICS OF PRESSURE RELIEF VALVES Maximum pressure fire sizing

12 12

Maximum accumulated for multi-valve (other than fire

Maximum accumulated for design

Multiple Maximum pressure process for process

11 11 Pe rc en t of m ax im u m all o w ab le w or ki ng pr es su re

Single valve Maximum pressure for process Maximum allowable set for supplemental (fire

11

Overpressure (maximium) Maximum allowable set for additional valves

10

10 Simmer (typical)

Maximum allowable set for single Start to open Blowdown (see Note 6)

9 Closing for a single Maximum operating (see Notes 5 and 6)

113 of 156

June, 2004

Figure II-2 Characteristics of Typical Pressure Relief Valve

Maximum accumulated for single-valve (other than fire

Page

9

Leak test pressure (typical)

8 Notes: (1) (2) (3) (4) (5)

This figure conforms with the requirements of Section VIII of the ASME Boiler and Pressure Vessel Code. The pressure conditions shown are for pressure relief valves installed on a pressure vessel. Allowable set-pressure tolerances will be in accordance with the applicable codes. The maximum allowable working pressure is equal to or greater than the design pressure for a coincident design temperature. The operating pressure may be higher or lower than 90.

(6)

Section VIII, Division 1, Appendix M, of the ASME Code should be referred to for guidance on blowdown and pressure differentials.

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FIGURE II-3 FORCES ACTING ON DISCS OF BALANCED BELLOWS AND CONVENTIONAL PRESSURE RELIEF VALVES Spring Bonnet Vented to Atmosphere Balanced Bellows Valve

Spring, No Bellows Conventional Valve

Spring FS

Spring FS

Vented Spring Bonnet

PB

PB

Disk PB

PB

PB

PV

Disk PB

PB

PV

Back Pressure Increases Set Pressure

PV AN = FS – PB (AD – AN)

PV AN = FS + PB AN

AD = Disk Area. AN = Nozzle Seat Area. FS = Spring Force. PV = Vessel Pressre, In Gauge Pressure. PB = Superimposed Back Pressure, In Gauge Pressure. DP15CFII3

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FIGURE II-4 PRESSURE CONDITIONS FOR PRESSURE RELIEF VALVE INSTALLED ON A PRESSURE VESSEL (VAPOR PHASE) PRESSURE VALVE REQUIREMENTS

Maximum allowable accumulated pressure (fire exposure only)

120

116

auge) ssure (g rking pre o w le b a m allow

115

imu t of max Percen

Maximum allowable working pressure or design pressure (hydrotest at 150)

Maximum relieving pressure for fire sizing

121

Maximum allowable accumulated pressure for multi-valve installation (other than fire exposure)

Maximum allowable accumulated pressure for single-valve installation (other than fire exposure)

TYPICAL CHARACTERISTICS OF PRESSURE RELIEF VALVES

VESSEL PRESSURE

Margin of safety due to orifice selection varies

Multiple valves Single valve

Maximum allowable set pressure for supplemental valves (fire exposure)

110

Overpressure (maximium) Maximum allowable set pressure for supplemental valves (process)

105

Overpressure (typical)

100 Simmer (typical)

Maximum allowable set pressure for single valve (average) Start to open Blowdown (typical) Seat clamping force

95

Reset pressure (typical) for single valve Usual maximum normal operating pressure

90

Standard leak test pressure Setting " 3 percent Tolerences

85

Not specified by ASME code, Section VIII Tightness: API STD 527

Blowdown simmer

Notes: (1) The operating pressure may be any lower pressure required. (2) The set pressure and all other values related to it may be moved downward if the operating pressure permits. (3) The figure conforms with the requirements of Section VIII, Division 1, of the ASME Code.

(4)

The pressure conditions shown are for safety relief valves installed on a pressure vessel (vapor phase).

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FIGURE II-5 TYPICAL BALANCED BELLOWS PRESSURE RELIEF VALVE Cap Stem Spring Adjustment Jam Nut (Spring Adjusting Screw) Cap Gasket Bonnet Spring Button Spring Spring Button Stem Retainer Vent Sleeve Guide Bonnet Gasket Body Stud Hex Nut Bellows Body Gasket Disc Holder Locking Screw Bellows Gasket Disc Disc Holder Outlet

Blowdown Ring Locking Stud Locking Screw Gasket Blowdown Ring Locking Screw Hex Nut (Blowdown Ring Locking Screw) Blowdown Ring Drain (Normally Plugged) Nozzle Body Nozzle Gasket

DP15CFII5

Inlet

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FIGURE II-6 TYPICAL PILOT-OPERATED PRESSURE RELIEF VALVE Pilot Valve 8 7 6

9

5

No. 1 2 3 4 5 6 7 8 9

Part Name Blowdown Adjustment Two Piece Nozzle Spindle Guide O-Ring Seat Spindle Spring Bonnet Adjusting Screw Body

4 3 2 1 11 10

12 9 13

8 7 5

No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14

Main Valve Part Name Body Nozzle Seat Seat Retainer Liner Piston Piston Seal Shipping Spring Cap Supply Tube Pilot Valve Exhaust Tube Lift Adjustment Screw Dipper Tube

6 3 2 1

4 14

DP15CII6

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FIGURE II-7 OPERATION OF THE AGCO PATENTED FULLY ADJUSTABLE NON-FLOWING PILOT OPERATED PRESSURE RELIEF VALVE Pressure Seat Open (Opens at Set Pressure and is Held Open by Spacer Rod Until Reseat Pressure is Reached)

Set Pressure Adjustment

Pilot Vents Only From Top of Piston

Pressure Seat Closed Field Test Valve (Optional)

Spacer Rod Blowdown Seat Open

Field Test Check Seat Closed (By Gravity)

Back Flow Preventer (Optional) Piston Closed

Spacer Rod Blowndown Seat Closed (Closes at Set Pressure and is Held Closed by Process Pressure Until Reseat Pressure is Reached Field Test Check Open

Piston in Full Lift Blowdown Adjustment

Normal Closed Position (also Position Upon Reseating)

Position When Open

Process Pressure Downstream Pressure Notes: Pressure at which valve will reseat is dependent upon two factors (1)

The area of the blowdown seat with respect to the pressure seat. This determines the total lifting force against the spring when the valve is flowing. This area ratio is the same for all pilots.

(2)

The lift of the spring when the valve is flowing. Higher spring lift gives greater closing spring force - due to added force of compression - and the higher the spring lift, the shorter the blowdown. Hence, the blowdown is adjustable by the patented AGCO system of changing the spring lift. This is done by raising or lowering the entire blowdown assembly of the pilot which raises or lowers the spacer rod - which in turn causes the pilot spring to lift more or less when the valve relieves. DP15CFII7

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FIGURE II-8 "O" RING SEAT SEAL PRESSURE RELIEF VALVE

Disc Holder

Disc

Retaining Screw

"O" Ring Retainer

"O" Ring Seat Seal

Plug

Blowdown Ring

Nozzle

DP15CFII8

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FIGURE II-9 PRE-SCORED REVERSE BUCKLING RUPTURE DISC Before:

After:

Rupture Disc Correct Installation: Standard Studs and Nuts Outlet Standard Flange Insert-Type Rupture Disc Holder 2 Special Flanges Pre-Assembly Screws Standard Flange

Inlet

Pressure

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Before:

FIGURE II-10 PRE-SCORED TENSION-LOADED RUPTURE DISC

After:

Rupture Disc Correct Installation: Standard Studs and Nuts Outlet Standard Flange Insert-Type Rupture Disc Holder 2 Special Flanges

Pre-Assembly Screws Standard Flange

Inlet

Pressure

DP15CFII10

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FIGURE II-11 EFFECT OF TEMPERATURE ON BURST PRESSURE FOR CONVENTIONAL RUPTURE DISCS

72 °F (22 °C) 100

Inconel Relative Burst Pressure, %

Page

90

80

Nickel 70 Aluminum 60

DP15CII11

0 (-18)

200 (93)

400 (204)

Stainless Steel

600 (315)

800 (426)

Temperature, °F ( °C)

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FIGURE II-12 EXPLOSION HATCH FOR ASPHALT OXIDIZER Adequately Reinforced Hinged Hatches

Close Flat Fit

Weather Lip Beam

Drip Lip

Drain

Vent

Top Steam

DP15CFII12

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June, 2004

FIGURE II-13 RUPTURE PIN DEVICE Pin Retaining Nut

Pin Holder

Replacement Pin Inside Support Post

Page

Pin

Support Post

Piston

O-Ring Seal

DP15CFII13

EXXONMOBIL RESEARCH AND ENGINEERING COMPANY – FAIRFAX, VA

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Section

XV-C

Page

125 of 156

June, 2004

FIGURE II-14 BALANCED RUPTURE PIN DEVICE

DP15CFII14

EXXONMOBIL RESEARCH AND ENGINEERING COMPANY – FAIRFAX, VA

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Section

XV-C

DESIGN PRACTICES

Page

126 of 156

June, 2004

TABLE III-1 THERMODYNAMIC PROPERTIES OF VARIOUS SUBSTANCES AT 60ºF (15ºC) AND ATMOSPHERIC PRESSURE

MOLECULAR WEIGHT

SPECIFIC HEAT RATIO K = Cp / Cv

CRITICAL FLOW PRESSURE RATIO Px / P1

Methane

16.04

1.30

0.55

Ethane

30.07

1.19

0.57

Ethylene

28.05

1.24

0.56

Propane

44.10

1.13

0.58

Propylene

42.08

1.15

0.57

Isobutane

58.12

1.10

0.58

n-Butane

58.12

1.09

0.59

1-Butane

56.11

1.11

0.58

Isopentane

72.15

1.08

0.59

n-Pentane

72.15

1.08

0.59

1-Pentane

70.14

1.08

0.59

n-Hexane

86.18

1.06

0.59

Benzene

78.11

1.12

0.58

n-Heptane

100.20

1.05

0.60

Toluene

92.14

1.09

0.59

n-Octane

114.23

1.05

0.60

n-Nonane

128.23

1.04

0.60

n-Decane

142.29

1.04

0.60

Air

28.96

1.40

0.53

Ammonia

17.03

1.30

0.55

Carbon Dioxide

44.01

1.29

0.55

Hydrogen

2.02

1.41

0.53

Hydrogen Sulfide

34.08

1.32

0.54

Sulfur Dioxide

64.06

1.27

0.55

Steam

18.02

1.33

0.54

GAS

References: API Technical Data Book

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DESIGN PRACTICES

TABLE III-2 CROSBY AND FARRIS STEEL FULL NOZZLE RELIEF VALVES(1) Standard Connections ANSI Flanges (2)

Maximum Back Pressure psig at 100°F (38°C) (3)

450°F (230°C) Maximum Service Temperature Carbon Steel Spring Carbon Steel Body Typical Valve Type (1) (4)

J 1.287 (830)

K 1.838 (1186)

L 2.853 (1841)

M 3.60 (2323) N 4.34 (2800)

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ç Orifice Size and Effective Orifice Area In2 (mm2) (6)

Page

Inlet

Outlet

Conv.

2-150 2-300 3-300 3-600 3-900 3-1500 3-150 3-300 3-300 3-600 3-900 3-1500 3-150 3-300 4-300 4-600 4-900 4-1500 4-150 4-300 4-300 4-600 4-900 4-150 4-300 4-300 4-600 4-900

3-150 3-150 4-150 4-150 4-150 4-300 4-150 4-150 4-150 4-150 4-150 4-300 4-150 4-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150

285 285 285 285 285 600 285 285 285 285 285 600 285 285 285 285 285 285 285 285 285 285 285 285 285 285 285 285

Bellows

230 230 230 230 230 230 150 150 150 200 200 200 100 100 170 170 170 170 80 80 160 160 160 80 80 160 160 160

Crosby

Farris

JOS-15 JOS-25 JOS-35 JOS-45 JOS-55 JOS-65 JOS-15 JOS-25 JOS-35 JOS-45 JOS-55 JOS-65 JOS-15 JOS-25 JOS-35 JOS-45 JOS-55 JOS-15 JOS-25 JOS-35 JOS-45 JOS-15 JOS-25 JOS-35 JOS-45 -

A-10 A-11 A-12 A-13 A-14 A-15 A-10 A-11 A-12 A-13 A-14 A-15 A-10 A-11 A-12 A-13 A-14 A-10 A-11 A-12 A-13 A-10 A-11 A-12 A-13 -

Pressure Limits, psig (5) (7) Inlet Temperature -20 to 450°F 100°F (230°C) (-30 to 38°C) 285 185 285 285 740 615 1480 1235 2220 1845 2700 2060 285 185 285 285 740 615 1480 1235 2220 1845 2220 2220 285 185 285 285 740 615 1000 1000 1500 1500 285 185 285 285 740 615 1100 1100 285 185 285 285 740 615 1000 1000 -

800°F (425°C) Maximum Service Temperature Alloy Steel Spring Carbon Steel Body Typical Valve Type (1) (4) Crosby

Farris

JOS-16 JOS-26 JOS-36 JOS-46 JOS-56 JOS-66 JOS-16 JOS-26 JOS-36 JOS-46 JOS-56 JOS-66 JOS-16 JOS-26 JOS-36 JOS-46 JOS-56 JOS-66 JOS-16 JOS-26 JOS-36 JOS-46 JOS-56 JOS-16 JOS-26 JOS-36 JOS-46 JOS-56

A-20 A-21 A-22 A-23 A-24 A-25 A-20 A-21 A-22 A-23 A-24 A-25 A-20 A-21 A-22 A-23 A-24 A-25 A-20 A-21 A-22 A-23 A-24 A-20 A-21 A-22 A-23 A-24

Pressure Limits, psig (5) (7) Inlet Temperature 450°F 800°F (230°C) (425°C) 185 285 615 1235 1845 2060 185 285 615 1235 1845 2220 185 285 615 1000 1500 1500 185 285 615 1100 1100 185 285 615 1000 1000

80 285 410 825 1235 2060 80 285 410 825 1235 2060 80 285 410 825 1235 1500 80 285 410 825 1100 80 285 410 825 1000

EXXONMOBIL RESEARCH AND ENGINEERING COMPANY – FAIRFAX, VA

1000°F (540°C) Maximum Service Temperature Alloy Steel Spring Alloy Steel Body Typical Valve Type (1) Crosby

Farris

JOS-37 JOS-47 JOS-57 JOS-67 JOS-37 JOS-47 JOS-57 JOS-67 JOS-37 JOS-47 JOS-57 JOS-67 JOS-37 JOS-47 JOS-57 JOS-37 JOS-47 -

A-32 A-33 A-34 A-35 A-32 A-33 A-34 A-35 A-32 A-33 A-34 A-35 A-32 A-33 A-34 A-32 A-33 A-34

Pressure Limits, psig (5) (7) Inlet Temperature 800°F 1000°F (425°C) (540°C) 510 1015 1525 2540 510 1015 1525 2220 510 1000 1500 1500 510 1000 1100 510 1000 1000

215 430 650 1080 215 430 650 1080 215 430 650 1080 215 430 650 215 430 650

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DESIGN PRACTICES

TABLE III-2 (Cont) CROSBY AND FARRIS STEEL FULL NOZZLE RELIEF VALVES(1) Standard Connections ANSI Flanges (2)

Maximum Back Pressure psig at 100°F (38°C) (3)

450°F (230°C) Maximum Service Temperature Carbon Steel Spring Carbon Steel Body Typical Valve Type (1) (4)

J 1.287 (830)

K 1.838 (1186)

L 2.853 (1841)

M 3.60 (2323) N 4.34 (2800)

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ç Orifice Size and Effective Orifice Area In2 (mm2) (6)

Page

Inlet

Outlet

Conv.

2-150 2-300 3-300 3-600 3-900 3-1500 3-150 3-300 3-300 3-600 3-900 3-1500 3-150 3-300 4-300 4-600 4-900 4-1500 4-150 4-300 4-300 4-600 4-900 4-150 4-300 4-300 4-600 4-900

3-150 3-150 4-150 4-150 4-150 4-300 4-150 4-150 4-150 4-150 4-150 4-300 4-150 4-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150 6-150

285 285 285 285 285 600 285 285 285 285 285 600 285 285 285 285 285 285 285 285 285 285 285 285 285 285 285 285

Bellows

230 230 230 230 230 230 150 150 150 200 200 200 100 100 170 170 170 170 80 80 160 160 160 80 80 160 160 160

Crosby

Farris

JOS-15 JOS-25 JOS-35 JOS-45 JOS-55 JOS-65 JOS-15 JOS-25 JOS-35 JOS-45 JOS-55 JOS-65 JOS-15 JOS-25 JOS-35 JOS-45 JOS-55 JOS-15 JOS-25 JOS-35 JOS-45 JOS-15 JOS-25 JOS-35 JOS-45 -

A-10 A-11 A-12 A-13 A-14 A-15 A-10 A-11 A-12 A-13 A-14 A-15 A-10 A-11 A-12 A-13 A-14 A-10 A-11 A-12 A-13 A-10 A-11 A-12 A-13 -

Pressure Limits, psig (5) (7) Inlet Temperature -20 to 450°F 100°F (230°C) (-30 to 38°C) 285 185 285 285 740 615 1480 1235 2220 1845 2700 2060 285 185 285 285 740 615 1480 1235 2220 1845 2220 2220 285 185 285 285 740 615 1000 1000 1500 1500 285 185 285 285 740 615 1100 1100 285 185 285 285 740 615 1000 1000 -

800°F (425°C) Maximum Service Temperature Alloy Steel Spring Carbon Steel Body Typical Valve Type (1) (4) Crosby

Farris

JOS-16 JOS-26 JOS-36 JOS-46 JOS-56 JOS-66 JOS-16 JOS-26 JOS-36 JOS-46 JOS-56 JOS-66 JOS-16 JOS-26 JOS-36 JOS-46 JOS-56 JOS-66 JOS-16 JOS-26 JOS-36 JOS-46 JOS-56 JOS-16 JOS-26 JOS-36 JOS-46 JOS-56

A-20 A-21 A-22 A-23 A-24 A-25 A-20 A-21 A-22 A-23 A-24 A-25 A-20 A-21 A-22 A-23 A-24 A-25 A-20 A-21 A-22 A-23 A-24 A-20 A-21 A-22 A-23 A-24

Pressure Limits, psig (5) (7) Inlet Temperature 450°F 800°F (230°C) (425°C) 185 285 615 1235 1845 2060 185 285 615 1235 1845 2220 185 285 615 1000 1500 1500 185 285 615 1100 1100 185 285 615 1000 1000

80 285 410 825 1235 2060 80 285 410 825 1235 2060 80 285 410 825 1235 1500 80 285 410 825 1100 80 285 410 825 1000

EXXONMOBIL RESEARCH AND ENGINEERING COMPANY – FAIRFAX, VA

1000°F (540°C) Maximum Service Temperature Alloy Steel Spring Alloy Steel Body Typical Valve Type (1) Crosby

Farris

JOS-37 JOS-47 JOS-57 JOS-67 JOS-37 JOS-47 JOS-57 JOS-67 JOS-37 JOS-47 JOS-57 JOS-67 JOS-37 JOS-47 JOS-57 JOS-37 JOS-47 -

A-32 A-33 A-34 A-35 A-32 A-33 A-34 A-35 A-32 A-33 A-34 A-35 A-32 A-33 A-34 A-32 A-33 A-34

Pressure Limits, psig (5) (7) Inlet Temperature 800°F 1000°F (425°C) (540°C) 510 1015 1525 2540 510 1015 1525 2220 510 1000 1500 1500 510 1000 1100 510 1000 1000

215 430 650 1080 215 430 650 1080 215 430 650 1080 215 430 650 215 430 650

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PRESSURE RELIEF

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DESIGN PRACTICES

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June, 2004

ç

TABLE III-2 (Cont) CROSBY AND FARRIS STEEL FULL NOZZLE RELIEF VALVES(1) Orifice Size and Effective Orifice Area In2 (mm2) (6)

Standard Connections ANSI Flanges (2)

Maximum Back Pressure psig at 100°F (38°C) (3)

450°F (230°C) Maximum Service Temperature Carbon Steel Spring Carbon Steel Body Typical Valve Type (1) (4)

P 6.38 (4116) Q 11.05 (7129) R 16.0 (10323) T 26.0 (16775)

Inlet

Outlet

Conv.

4-150 4-300 4-300 4-600 4-900 6-150 6-300 6-300 6-600 6-150 6-300 6-300 6-600 8-150 8-300 8-300 8-300

6-150 6-150 6-150 6-150 6-150 8-150 8-150 8-150 8-150 8-150 8-150 10-150 10-150 10-150 10-150 10-150 10-150

285 285 285 285 285 115 115 115 115 60 60 100 100 30 30 60 100

Bellows

80 80 150 150 150 70 70 115 115 60 60 100 100 30 30 60 100

Crosby

Farris

JOS-15 JOS-25 JOS-35 JOS-45 JOS-15 JOS-25 JOS-35 JOS-45 JOS-15 JOS-25 JOS-35 JOS-45 JOS-15 JOS-25 JOS-35 JOS-45

A-10 A-11 A-12 A-13 A-10 A-11 A-12 A-13 A-10 A-11 A-12 A-13 A-10 A-11 A-12 A-13

Pressure Limits, psig (5) (7) Inlet Temperature -20 to 450°F 100°F (230°C) (-30 to 38°C) 285 185 285 285 525 525 1000 1000 165 165 165 165 300 300 600 600 100 100 100 100 230 230 300 300 65 65 65 65 120 120 300 300

800°F (425°C) Maximum Service Temperature Alloy Steel Spring Carbon Steel Body Typical Valve Type (1) (4) Crosby

Farris

JOS-16 JOS-26 JOS-36 JOS-46 JOS-56 JOS-16 JOS-26 JOS-36 JOS-46 JOS-16 JOS-26 JOS-36 JOS-46 JOS-16 JOS-26 JOS-36 JOS-46

A-20 A-21 A-22 A-23 A-24 A-20 A-21 A-22 A-23 A-20 A-21 A-22 A-23 A-20 A-21 A-22 H-A-22

Pressure Limits, psig (5) (7) Inlet Temperature 450°F 800°F (230°C) (425°C) 185 285 525 1000 1000 165 165 300 600 100 100 230 300 65 65 120 300

80 285 410 825 1000 80 165 300 600 80 100 230 300 65 65 120 300

EXXONMOBIL RESEARCH AND ENGINEERING COMPANY – FAIRFAX, VA

1000°F (540°C) Maximum Service Temperature Alloy Steel Spring Alloy Steel Body Typical Valve Type (1) Crosby

Farris

JOS-37 JOS-47 JOS-37 JOS-47 JOS-37 JOS-47 JOS-37

A-32 A-33 A-34 A-32 A-33 A-32 A-33 A-32 H-A-32

Pressure Limits, psig (5) (7) Inlet Temperature 800°F 1000°F (425°C) (540°C) 510 1000 1000 165 600 100 300 120 300

215 430 650 165 430 100 300 100 225

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DESIGN PRACTICES

ç

Page

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June, 2004

Notes for Table III-2:

1.

Crosby valve information from Catalog 310, 1995.

JOS conventional; B replaces O for bellows. JLT precedes JOS or JBS for capacity-certified valves for liquid service. Farris valve information from catalog 193C, 1996. A type is conventional; B replaces A for bellows. C replaces A for conventional with “O” ring. D replaces A for bellows type with “O” ring. E replaces A for bellows with auxiliary balancing piston. F replaces A for bellows with auxiliary balancing piston and “O” ring. 2.

Raised face is standard. Ring joint is optional. Flange sizes and ratings are based on API Standard 526 Fifth Edition, June 2002 and may not necessarily agree with information in vendors’ literature.

3.

Outlet pressure limit for temperatures above 100°F (38°C) shall not exceed the rating in ANSI / ASME B16.34. For temperatures over 400°F (204°C), maximum allowable back pressure for balanced bellows valves shall not exceed the lesser of the ANSI / ASME B16.34 rating or the maximum allowable back pressure at 100°F (38°C) multiplied by the following correction factors:

TEMPERATURE

MULTIPLY MAXIMUM BACK PRESSURE AT 100°F BY:

TEMPERATURE

MULTIPLY MAXIMUM BACK PRESSURE AT 38°C BY:

400°F 500°F 600°F 800°F

1.00 0.91 0.83 0.66

200°C 300°C 400°C

1.00 0.85 0.70

4.

GP03-15-01 forbids the use of “light-body” models. A light-body model is one in which the pressure rating of the inlet flange exceeds that of the body of the valve. Thus, Crosby models JOS / JBS –2X or Farris models A / BX1should not be specified for new construction.

5.

Pressure limits are based on API Standard 526, Fifth Edition, June 2002 and may not necessarily agree with information in vendors’ literature.

6.

Effective orifice areas are based on API Standard 526. These effective orifice areas shall be used together with the effective coefficients of discharge recommended in this Design Practice (and in API RP 520) to estimate the rated relief capacity. The actual orifice area for most commercially available valves is greater than the effective orifice area specified in API Standard 526 and shown in this table. This compensates for the fact that the certified coefficient of discharge determined by the rules of the ASME Boiler and Pressure Vessel Code is less than the effective coefficient of discharge used for preliminary sizing. Thus, it is not necessary to apply an additional de-rating factor to the effective orifice areas listed in this table when estimating the rated capacity of a pressure relief valve. Refer to API RP 520 Part I for details.

7.

Metric conversion for pressure: 1 psi = 6.89 kPa.

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DESIGN PRACTICES

ç

Page

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June, 2004

TABLE III-3 CROSBY AND FARRIS PRESSURE RELIEF VALVES FOR LOW-TEMPERATURE SERVICE

Temperature Range, °F (°C) Crosby Designation (Note 3) JOS JBS JBS-BP JLT-JOS JLT-JBS JLT-JBS-BP Farris Designation (Note 4) A B C D E F Orifice Size D E F G H J K L M N P Q R T

12

22

10/S4

11/S4

275 275 275 275 275 275 275 275 275 275 175 165 55 50

-450 to -76 (-268 to –60) 32 42 -

-

-

14

24

15/S4

16/S4

10/S3

11/S3

Maximum Set Pressure, psig (Notes 1,2) 275 720 1440 2160 3600 275 720 1440 2160 3600 275 720 1440 2160 2200 275 720 1440 2160 2450 275 720 1440 1485 1600 275 500 625 800 800 275 525 600 600 750 275 535 535 700 275 525 600 275 450 500 175 300 480 165 250 300 55 150 200 50 65 -

4000 4000 3400 2600 -

275 275 275 275 275 275 275 275 275 275 275 165 100 65

12/S4

13/S4

14/S4

-75 to –21 (-59 to –29) 34 44 -

-

-

15/S3

16/S3

Maximum Set Pressure, psig (Notes 1,2) 275 720 1440 2160 3600 275 720 1440 2160 3600 275 720 1440 2160 3600 275 720 1440 2160 3600 275 720 1440 2160 2750 275 720 1440 2160 2700 275 720 1440 2160 2220 275 720 1000 1500 275 720 1000 275 720 1000 275 525 1000 165 300 600 100 230 300 65 120 -

6000 6000 5000 3600 -

12/S3

EXXONMOBIL RESEARCH AND ENGINEERING COMPANY – FAIRFAX, VA

13/S3

14/S3

ExxonMobil Proprietary SAFETY IN PLANT DESIGN

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PRESSURE RELIEF

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DESIGN PRACTICES

k=

Cp Cv

æ 2 ö ÷÷ C = 520 k çç è k + 1ø

1.01 1.02 1.04 1.06

317 318 320 322

1.08 1.10 1.12 1.14

325 327 329 331

1.16 1.18 1.20 1.22

333 335 337 339

1.24 1.26 1.28 1.30

341 343 345 347

1.32 1.34 1.36 1.38

349 351 353 354

1.40 1.42 1.44 1.46

356 358 360 361

1.48 1.50 1.52 1.54

363 365 366 368

1.56 1.58 1.60 1.62

369 371 373 374

1.64 1.66 1.68 1.70

376 377 379 380

2.00 2.20

400 412

(k +1) / (k -1)

Note:

For use in Eq.

132 of 156

June, 2004

TABLE III-4 VALUES OF CONSTANT "C" FOR FLOW FORMULA CALCULATIONS*

*

Page

(5a).

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June, 2004

FIGURE III-1 CRITICAL FLOW PRESSURE FOR HYDROCARBONS

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FIGURE III-2A VARIABLE OR CONSTANT TOTAL BACK PRESSURE FACTOR, Kb, FOR CONVENTIONAL OR PILOT

Kb =

Capacity With Back Pressure Rated Capacity Without Back Pressure

OPERATED PRESSURE RELIEF VALVES (VAPORS AND GASES) SUBCRITICAL FLOW*

1.0 0.8 k = 1.1 k = 1.3 k = 1.5

0.6 0.4

k = 1.7

0.2 0 0

10

20

30

% Absolute Back = Pressure

40

50

60

70

80

90

100

Total Back Pressure, absolute X 100 Accumulated Pressure, absolute

* Critical flow for conventional or pilot, Kb = 1.

DP15CFIII2A

FIGURE III-2B VARIABLE OR CONSTANT TOTAL BACK PRESSURE FACTOR, Kb, FOR BALANCED BELLOWS

Kb =

Capacity With Back Pressure Rated Capacity Without Back Pressure

PRESSURE RELIEF VALVES (VAPORS AND GASES) CRITICAL FLOW ONLY*

1.00

20% Over 10 press % ure Ov er pr es su re Note: This curve is an average of the values recommended by several manufacturers, and will generally give conservative results. Manufacturers curves should be used where possible.

0.90 0.80 0.70 0.60 0.50 0

5

10

15

20

25

30

35

% Gage Back Total Back Pressure, gage = Pressure Set Pressure, gage

* Subcritical flow for balanced bellows, consult manufacturer.

40

45

50

X 100 DP15CFIII2B

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June, 2004

FIGURE III-3 VISCOSITY CORRECTION: PROCEDURE PER API RP-500 1.0

Ku = Viscosity Correction Factor

0.9

0.8

0.7

0.6

0.5

0.4

0.3 10

20

40

60 100

200

400

1,000

2,000

4,000

10,000

20,000

100,000

R = Reynolds Number

Notes:

To size a relief valve for viscous liquid service: (1)

Determine area required without viscosity correction, Ao (Ku = 1), from Eq. (8) or (9).

(2)

Select next larger standard orifice size from manufacturer's literature or Table III-2.

(3)

Determine Reynolds Number, R:

R =

R = where:

2800 LS m A

=

12700 L U A

1.127 x 106 LS m A

(Customary)

(Metric)

L=

Flow Rate, gpm (dm3/s)

S=

Specific gravity at flowing temperature vs. water at 60°F (15°C)

m=

Viscosity at flowing temperature, centipoises or MPa·s

U=

Viscosity at flowing temperature, SSU Effective orifice area, in.2 (mm2) (from manufacturer's literature)

A= (4)

Find Ku, viscosity correction factor from chart.

(5)

Corrected area required is Ao / Ku; if this exceeds A, repeat the calculation using the corrected area to define size.

(6)

If the required corrected area is only slightly above a standard orifice size, consider using multiple smaller valves with staggered set pressure to minimize tendency to chatter.

EXXONMOBIL RESEARCH AND ENGINEERING COMPANY – FAIRFAX, VA

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June, 2004

FIGURE III-4 VARIABLE OR CONSTANT BACK PRESSURE SIZING FACTOR KW, ON BALANCED BELLOWS PRESSURE RELIEF VALVES (LIQUIDS ONLY)

ç

1.00 0.95 0.90

0.80

KW =

b

Capacity With Variable Back Pressure X 100 Rated Capacity Based on p - p

(NOTE 1) 0.85

0.75 0.70 0.65 0.60 (NOTE 2)

0.55 0.50 0.45 0.40 0.35 0

10

20

30

% Gage Back Pressure =

40

50

60

70

Total Back Pressure, gage X 100 Set Pressure, gage

Notes: (1) The above curve represents a compromise of the values recommended by a number of relief valve manufacturers. This curve may be used when the make of the valve is not known. When the make is known the manufacturer should be consulted for the correction factor. (2) The extensions beyond 50% gage back pressure (shown as dashed line) is intended to be used only for PR valves in subcooled liquid inlet with flashing downstream of the PR valve nozzle (flashing in the PR valve body). IT SHALL NOT BE USED FOR ALL-LIQUID PR Valves (no flashing within the PR valve). DP15CFIII4

EXXONMOBIL RESEARCH AND ENGINEERING COMPANY – FAIRFAX, VA

80

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DESIGN PRACTICES

Page

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June, 2004

FIGURE III-5 CAPACITY CORRECTION FACTORS DUE TO OVERPRESSURE FOR NON-ASME CERTIFIED RELIEF VALVES IN LIQUID SERVICE 1.10

1.00

Not Recommended Below 5% Overpressure

0.90

0.80

Correction Factor, Kp

0.70

0.60

0.50 0.40

0.30

0.20

0.10

0

0

5

10

15

20

25

30

35

40

45

50

Percent Overpressure Note: (1) The above curve shows that up to and including 25 percent overpressure, capacity is affected by the change in lift, the change in orifice discharge coefficient, and the change in overpressure. Above 25 percent, the valve is at full lift and capacity is affected only by overpressure. DP15CFIII5

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ç FIGURE III-6 CRITICAL TWO-PHASE PRESSURE RATIO FOR SUBCOOLED LIQUIDS 1.000

Saturated Omega Parameter

10

0.950

15

20

40

7 5

Critical Pressure Ratio

0.900

0.850

2

0.800

0.750

0.700

1 0.650

0.600 0.600

0.650

0.700

0.750

0.800

0.850

0.900

0.950

1.000

Saturation Pressure Ratio

Critical Two-Phase Pressure Ratio for Subcooled Liquids

This chart provides a graphical solution for the following implicit equation for hc:

ö h2 æ æh ö 1 çç ws + - 2 ÷÷ c - 2(ws - 1)hc + w shs lnçç c ÷÷ + 1.5wshs = 1.0 ws ø 2 hs è è hs ø Where: ws

=

Saturated omega parameter, dimensionless

hs

=

Saturation pressure ratio, dimensionless

hc

=

Critical pressure ratio, dimensionless

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10 APPENDIX 1 PROTECTION OF VESSELS AGAINST OVERPRESSURE DUE TO EXTERNAL FIRE

VESSELS CONTAINING LIQUIDS The procedure for calculating the required relieving rates is given below. 10.1

STEP 1 - AMOUNT OF HEAT ABSORBED

The amount of heat absorbed by a vessel exposed to an open fire is markedly affected by the size and character of the installation and by the environment. A major variable in this regard is the degree to which the vessel is enveloped. This is greatly affected, in turn, by the adequacy of the drainage system since these systems can limit the amount of spilled/burning material in close proximity to the equipment being protected. Two broad categories of situations are identified in API RP-521 and different equations for calculating the resulting heat input are provided, as follows: 1. For Situations in Which Good Drainage Exists - This situation is typical of onsite process units. (However, use of permanent covers on sewage drains may impair drainage and should be considered.) For these situations, the following equation can be used to estimate the heat absorbed by equipment: Q = 21,000 F A 0.82

(Customary)

Eq. (A1-1)

Q = 43.2 F A 0.82

(Metric)

Eq. (A1-1)M

where: Q A= (m2) F=

= Total heat absorbed (input) by the equipment Btu/hr (kW) Total wetted surface of the equipment (through which the heat is absorbed), ft2 Environmental factor

A graphical solution of this equation is offered in Figure A1-1. 2. For Facilities That Lack Good Drainage - This situation is typical of offsite facilities in which the diked areas around tanks increase the level of fire envelopment of the equipment. For these situations, the following equation can be used to estimate the heat absorbed by equipment: Q = 34,500 F A 0.82 Q = 70.9 F A 0.82 (Metric)

where: Q A

= =

F

=

(Customary)

Eq. (A1-2) Eq. (A1-2)M

Total heat absorbed (input) by the equipment Btu/hr (kW) Total wetted surface of the equipment (through which the heat is absorbed), ft2 (m2) Environmental factor

A graphical solution of this equation is offered in Figure A1-2. 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 LPG storage. For storage vessels with design pressure of 15 psig (100 kPa) or lower, or above 15 psig (100 kPa) but not storing LPG, see API 2000 for recommended heat absorption due to fire. The API 2000 load is greater than those above when the wetted area is less than 1,000 ft2 (90 m2) and drainage is poor, or the wetted area is less than 2,800 ft2 (260 m2) and remote impoundment provides good drainage.

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Environmental Factor - For a bare vessel the environmental factor, F, is 1.0. For insulated vessels, the environmental factor depends on the thermal conductivity and thickness of the insulation with all other environmental effect ignored, and can be evaluated from the following equation:

F=

k(1660 - T) 21,000t

F =

k (904 - T ) 66.2 t

(Customary)

Eq. (A1-3)

(Metric)

Eq. (A1-3)M

where: ç

ç ç

F

=

Environmental factor

k

=

Thermal conductivity of the insulation at the mean temperature between 1660°F (904°C) and T, Btu - in. per hr - ft2 - °F (W - m per m2 - °C). Use of a conservative mean temperature of 1000°F (540°C) is suggested. For insulation types acceptable per GP 03-02-04, a thermal conductivity of 1.0 Btu - in. per hr - ft2 - °F (0.144 W - m per m2 - °C) may be used. For gunite or concrete insulation (fireproofing), a thermal conductivity of 8.0 Btu - in. per hr - ft2 - °F (1.15 W - m per m2 - °C) may be used.

T

=

PR valve inlet temperature at relieving conditions, °F (°C)

t

=

Insulation thickness, in. (mm)

(Note: Equation A1-3 applies for situations where "good drainage" exist. For facilities that lack "good drainage" the F factor calculated from Equation A1-3 may be multiplied by a factor of 0.6). The minimum allowable value of the environmental factor, F, is 0.075 regardless of whether or not "good drainage" exists (note that local codes may define a higher minimum). Credit should not be taken for additional insulation which would reduce the environmental factor further. Credit may not be taken for insulation that can not withstand fire exposure (such as polyurethane) and can not be taken for insulation which due to its attachment design can not be expected to survive fire exposure, (refer to GP 03-02-04 for approved insulation installation details.) For most applications, the minimum size of a safety valve to protect against fire exposure is 1 in. x 2 in. (25 mm x 50 mm, “D" orifice). The loss of small amounts of insulation during a fire will have little effect on heat input to the vessel, provided that the bulk of the insulation remains intact. To ensure this when credit is taken for insulation, the insulation must be held in place with corrosion resistant, e.g., stainless or galvanized, steel banding and sheeting. Note that economics will frequently favor the provision of additional insulation (beyond that required for heat conservation), in order to reduce the required capacity of the pressure relieving system, when it is sized by fire considerations. In situations where insulation is not required for process reasons or personnel protection, addition of thermal insulation to (usually cold) vessel is impractical due to long term corrosion problems and fireproofing with gunite is the preferred option to permit reduction in the fire exposure sizing of the PR valves. Typical environmental factors are as follows: MATERIAL

THICKNESS, In. (mm)

Bare

F

1.0

ç

Gunite / Concrete

1.5 (38)

0.40

ç

Mineral wool / foam glass insulation

0.25(6.5)

0.30

0.5(13)

0.15

³1.0(25)

0.075

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(Note: the above environmental factors were calculated from Equation A1-3 using the values of thermal conductivity shown under that equation and assuming a relief temperature of 60°F (15.5°C) which is conservative). No credit should be taken for water spray or deluge systems in sizing PR systems. Supplying enough water to absorb most of the radiant heat becomes impractical for most installations. Emphasis should be placed on providing enough water to the outside of a vessel exposed to fire, to keep metal temperature below a point where failure might occur. Freezing weather, high winds, clogged systems, undependable water supply, and vessel surface conditions are among the factors which may prevent adequate water coverage, so no reduction in environmental factor is recommended.

ç

ç

ç

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 (7.5 m) of 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 a. Up to 25 ft (7.5 m) above grade - Use total wetted vessel surface up to high liquid level. b. Greater than 25 ft (7.5 m) above grade - Use the wetted area of the vessel surface to high liquid level or up to the vessel center line whichever is less. 2. Vertical Drums - The wetted vessel surface within 25 ft (7.5 m) of grade, based on high liquid level, is used. If the entire vessel is more than 25 ft (7.5 m) above grade, then only the surface of the bottom head need be included. For vessels supported on skirts that do not require fireproofing of their inside surface per GP 14-03-01, the surface of the bottom head need not be included in the wetted area regardless of elevation. 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 (7.5 m) of grade is used. If the entire vessel is 25 ft (7.5 m) or more above grade, then only the surface of the bottom head need be included. For vessels supported on skirts that do not require fireproofing of their inside surface per GP 14-03-01, the surface of the bottom head need not be included in the wetted area regardless of elevation. 4. Storage Spheres and Spheroids - The total surface exposed within 25 ft (7.5 m) of grade, or up to the elevation of the center line whichever is greater, is used. 5. Shell and Tube Heat Exchangers and Piping - The external surface area (not the heat transfer surface area of the tube bundle) 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 reboilers, is not normally included in the wetted surface area. The required relief rate for the tube side of heat exchangers exposed to fire (including reboilers) should be calculated based on the wetted surface of the channel and channel cover (or bonnet) on the front-end (stationary) tube sheet plus, in the case of fixed rear-tubesheet exchangers, the wetted surface of the rear-end channel and channel cover (or bonnet). The required relief rate for the shell side should be calculated based on the wetted surface of the shell plus, in the case of floating head (or U-tube) exchangers, the wetted surface of the rear-end channel and channel cover (or bonnet). Heat exchangers that are free-draining (e.g., a condenser that self-drains to a reflux drum) need not be considered in the calculation of relief loads arising from fire exposure. 6. Air Cooled Exchangers:: Only that portion of the bare surface on air-cooled exchangers located within the fire risk area being evaluated needs to be considered in the calculation of fire loads. Air fins located directly above piperacks 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: a. Gas cooling services. There will be no vapor generation due to fire and the tubes are likely to fail due to overheating. b. Air cooled partial or total condensers that meet the following criteria: 1. The tubes are sloped so that they are self-draining. 2. There is no control valve or pump connected directly to the condenser liquid outlet.

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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 risk area and within 25 feet (7.5m) of 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.

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FIGURE A1-1 HEAT ABSORBED FROM FIRE EXPOSURE FOR FACILITIES WITH GOOD DRAINAGE

100 Heat Absorbed, Million Btu/Hour*

Page

10

1

0.1

0.01

10

100

1000

10000

Total Wetted Area, Square Feet** F = 1.000

F = 0.330

F = 0.250

F = 0.125

* For Conversion to Watts, 0.2931 x Btu/hr = W ** For Coversion to m2, .093 x ft2 = m2

F = 0.075

DP15CFA1-1

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FIGURE A1-2 HEAT ABSORBED FROM FIRE EXPOSURE FOR FACILITIES WITH POOR DRAINAGE

Heat Absorbed, Million Btu/Hour*

Page

100

10

1

0.1

0.01

10

100

1000

10000

Total Wetted Area, Square Feet** F = 1.000

F = 0.330

F = 0.250

F = 0.125

* For Conversion to Watts, 0.2931 x Btu/hr = W ** For Coversion to m2, .093 x ft2 = m2

F = 0.075

DP15CFA1-2

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10.2

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STEP 2 - VAPOR RELEASE RATE AND REQUIRED RELIEF AREA

The required vapor relief rate, W, is calculated from: W =

Q æ r L - rV ç l çè r L

ö ÷ ÷ ø

Eq. (A1-4)

where:

W

=

Vapor relief rate, lb/h (kg/s)

Q

-

Heat input to vessel due to external fire, BTU/h (kW)

l

=

Heat absorbed per unit mass of vapor generated at relieving conditions, BTU/lb (kJ/kg)

rL

=

Liquid density at relief conditions, lb/ft (kg/m )

rV

=

Vapor density at relief conditions, lb/ft (kg/m )

3

3

3

3

Single Component Systems

For single component systems, the term l equals the latent heat of vaporization at relieving conditions. It may be determined from a flash calculation as the difference in the specific enthalpies of the vapor and liquid phases in equilibrium with each other, or it may be obtained from API RP 521, Appendix A, Figure A1-1 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

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: 1.

Assume that all vapor and liquid inflows into and outflows from the vessel (other than the fire relief load) have stopped.

2.

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).

3.

Flash the liquid from the preceding flash at constant pressure and a weight fraction vaporized equal to 0.01. 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, l. 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).

4.

Using the value of l calculated from Step 3, calculate the relief vapor rate, W, from Equation A1-4.

5.

Using the physical properties (temperature, molecular weight, compressibility factor) of the vapor generated in Step 3, calculate the required relief area using the appropriate sizing equation.

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6.

Repeat steps 3 through 5 until about 90% of the original liquid inventory in the vessel has been vaporized or until the absolute temperature from the flash is about 0.9 times the absolute thermodynamic critical temperature, whichever occurs first. To reduce the calculation effort if the calculations are being performed manually, it is suggested that the weight fraction vaporized for the third and subsequent flashes be increased from 0.01 to 0.1. However, in the case of wide boiling mixtures, improved accuracy may be obtained by setting the temperature of each subsequent isobaric flash 10 to 50 degrees F (5 to 30 degrees C) higher than that of the preceding flash (instead of using fraction vaporized as a specification).

7.

The required relief area is the largest obtained from the various iterations. The physical properties of the relief vapor are taken from the flash corresponding to the iteration resulting in the limiting relief area.

In applying this procedure, it is permissible to take credit for the reduction in the wetted surface as the liquid inventory is depleted. Experience shows that, when this is done, the limiting relief load usually occurs at the onset of the fire. Thus, for preliminary estimates, or for cases in which fire exposure is clearly not the limiting contingency, it may not be necessary to carry out steps 6 and 7 above. As the temperature of the system starts to approach the thermodynamic critical temperature, the heat absorbed per unit mass of liquid vaporized begins to approach zero, but at the same time, the difference between the liquid and vapor densities, rL - rV, also approaches zero. Thus, the required relief load due to vaporization decreases sharply as the critical temperature is approached and becomes zero at the critical temperature. At the critical temperature there can be no vaporization since the properties of the residual liquid and vapor phases are identical. At temperatures exceeding the critical temperature, any external heat input results in an increase in the temperature and a decrease in the density of the contained supercritical gas. The required relief rate will then equal the volumetric thermal expansion rate of the contained fluid. A procedure for calculating the required relief rate for such systems, together with a discussion of other applicable considerations, is presented under DRY VESSELS OR VESSELS CONTAINING SUPERCRITICAL FLUIDS in this Appendix. Systems Containing Two Immiscible Liquid Phases

Consult with EMRE’s Safety & Risk Section for guidance on the calculation of the required relief load and relief area for fire exposure of vessels containing two immiscible liquid phases. Consideration of Two-Phase Pressure Relief Due to Fire Exposure

When a vessel containing a liquid is exposed to fire, the traditional approach has been to assume that all the heat goes to boiling the liquid contents, and the resulting vapor then has to be relieved. In fact, the situation is more complex and it is possible that both liquid and vapor may need to be relieved if the vessel is completely liquid-filled or almost completely liquid filled. Two-phase relief is the result of both “swelling" of the liquid (due to thermal expansion and generation of vapor and inadequate vapor-liquid disengagement. Designing PR valves for two-phase relief due to fire exposure can be avoided by limiting the fill level in the vessel: to 85% of expanded volume for small vessels (under 10 ft diameter); to 95% expanded volume for large vessels (10 ft diameter or greater). Alternatively, for those cases in which PR valves have to be designed for two-phase flow. The sizing procedure is as follows: Based on simulations using DIERS (Design Institute for Emergency Relief Systems) technology, when the above levels are not met the following additional rules apply for non-foaming systems with design pressure of 50 psig (345 kPa) or greater. Non-foaming systems are those containing clean, low-viscosity (less than 100 cP at conditions), hydrocarbon distillates (or water). Size based on vapor relief only when: 1. The vessel is a sphere greater than 10 ft (3 m) diameter venting C3 or heavier hydrocarbon (good or poor drainage) 2. The vessel is a horizontal drum greater than 5 ft (1.5 m) in diameter venting C3 or heavier hydrocarbon (good or poor drainage) or water (good drainage) 3. The vessel is a vertical drum or tower greater than 10 ft (3 m) in diameter and contains hydrocarbon (good drainage) These rules may be applied regardless of liquid level. Additional details are available in the Safety Technology Manual, TMEE-0073.

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For vertical vessels between 10 and 5 ft diameter, the required relieving area may be approximated by doubling the area calculated for vapor-only relief. For vessels which fall out outside the above limitations or for “foamy" liquids, follow the guidelines below. Foamy liquids are those in which bubbles do not tend to coalesce and are possible when the liquid is: ·

Dirty with finely divided solids, or

·

Contains surfactants, or

·

Multi-component with diverse physical properties, or

·

Chemically reactive, or

·

High viscosity - over 100 cP at relieving conditions, or

· ç

1.

ç

2. 3.

More than one condensed phase (separated water phase may be treated based on the upper hydrocarbon phase). Using Eq. (A1-4) calculate the required vapor-only relief rate, W,. Note that, for this calculation, it is only necessary to calculate W at the onset of the fire. The premise is that two-phase vapor/liquid relief, if applicable, occurs only at the onset of the fire. At later stages of the fire, it is assumed that there will be a large enough vapor space in the vessel to provided for vapor/liquid disengagement. Obtain the physical properties of the saturated liquid and the (bubble point) vapor at set pressure and at accumulated pressure. Using the information from Step 2, calculate the two-phase relief rate, W 2, from the following equation: W2 = {[Q / (Cp DT )] * [Ln ((Q v fg ) / ( W2 v o l)) - 1]} + {[v o / v fg ] * [( W2 l) / (Cp DT )]}

(Equation A1-5)

If W 2 exceeds 3 times the vapor only relief rate, W, calculated from Equation A1-4, contact EMRE’s Safety & Risk Section for additional guidance. where: W2 = Rate of vapor and liquid to be relieved, lb/hr (kg/s) ç Q = Total heat absorbed, Btu/h (kW)r = Liquid heat capacity at set pressure, Btu/lb-°F (kJ/kg-°C) Cp DT = Temperature rise from set point to accumulated pressure (difference between the bubble point temperature at accumulated pressure and the bubble point temperature at set pressure), °F (°C) a = Initial fraction of the vessel volume occupied by vapor, (for example, if the vessel is 95% liquid filled, a = 0.05; if the vessel is completely liquid filled, a = 0.00) 3 = Liquid specific volume at set pressure, ft3/lb (m /kg) vf 3 3 vg = Vapor specific volume at set pressure, ft /lb(m /kg) = vg – vf vfg ç vo = 1 / {[(1 – a) / vf] + [a / vg]} ç l = Heat absorbed per unit mass of liquid vaporized at relieving conditions, Btu/lb (kJ/kg)

ç

WARNING: THIS EQUATION HAS MULTIPLE ROOTS SOME OF WHICH ARE TRIVIAL SINCE THE TWOPHASE RATE, W 2, IS SMALLER THAN W V. THIS EQUATION MUST BE SOLVED BY TRIAL AND ERROR. THE REQUIRED RELIEF RATE IS TAKEN AS THE SMALLEST VALUE OF W 2 THAT EXCEEDS W. 4.

Calculate the liquid rate to be relieved, W L. WL = W2 - W

(Equation A1-6)

where: W2

=

Rate of vapor and liquid to be relieved (from Step 2), lb/hr

W WL

= =

Vapor rate to be relieved, lb/hr Liquid rate to be relieved, lb/hr

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5.

ç

10.3

Section

XV-C

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June, 2004

Determine the required PR valve size for two-phase relief, using the Two-Phase Flashing Flow procedure in , Part III of this Design Practice as follows: a. Using the liquid composition, flash the material at the accumulated pressure, P1 and a weight fraction vaporized equal to 0.01 b. Using an isenthalpic flash at the accumulated relieving pressure, P1, mix the liquid from Step 5a, at a flow rate equal to WL with its equilibrium vapor from Step 5a, at a flow rate equal to W. This flash characterizes the overall flow rate, composition and phase distribution of the material entering the pressure relief valve. c. Flash the total stream from step 5b at constant enthalpy to P9, where P9 = 0.90P1 . d. Determine the liquid specific volume, vapor specific volume and vapor mass fraction at P1 and P9. e. Follow steps 4 through 8 under Design Procedure, Part III, Two-Phase Flashing Flow, to determine the required relief area for two-phase relief. f. Determine the required relief area for vapor only relief using the procedure described elsewhere in this Appendix. This is necessary to confirm that the relief area for two-phase relief is at least as large as that required based on vapor only flow g. The required relief area is the larger of those calculated in Steps 5e and 5f. As discussed previously, this procedure assumes that the required relief area for two-phase relief will be a maximum during the initial stages of the fire. As the liquid in the vessel is depleted, entrainment of liquid will decrease and the required relief area for two-phase relief will also decrease. However, as discussed under Step 5f, it is necessary to confirm that the relief area for two-phase relief is at least as large as that required based on vapor only flow. DRY VESSELS AND VESSELS CONTAINING SUPERCRITICAL FLUIDS

For dry vessels, or for vessels that contain supercritical fluids (or fluids that become supercritical as a result of the fire), overpressure protection by a pressure relief valve, by itself, is not effective in the prevention of vessel rupture since, eventually, the exposed vessel will fail due to overheating. However, a pressure relief valve, together with other protective measures such as the application of fire water or the use of fireproofing will prevent the vessel pressure from rising indefinitely and provide additional time to control or extinguish the fire before vessel failure occurs. The following approaches are suggested to protect against potential failure of dry vessels exposed to fire: 1.

Consider the use of a rupture disc, fusible plug or similar non-reclosing device instead of (or in parallel with) a pressure relief valve for overpressure protection. When such devices relieve, the internal pressure in the exposed equipment is reduced rapidly. A pressure relief valve, on the other hand, merely prevents the pressure from rising significantly above the MAWP of the equipment, but does not relieve the internal pressure. The effectiveness of rupture disks or pressure relief valves in this application, however, depends on whether or not the internal pressure of the equipment will reach the bursting pressure of the rupture disk or the set pressure of the pressure relief valve before the vessel wall fails due to overheating. From this standpoint, a fusible plug may be a more reliable means of protecting these vessels against overpressure due to fire. When local codes require that all vessels (including dry vessels) be protected against overpressure caused by external fire by a pressure relief device, see item 5 below.

2.

Consider fireproofing the vessel to reduce the rate of metal temperature rise during a fire exposure. If the vessel is insulated for process reasons, consider upgrading the insulation system to meet the requirements for fireproof insulation listed in GP 14-03-01. The advantages of using insulation or fireproofing for this purpose, however, should be balanced against the potential for corrosion under the insulation or fireproofing, especially in vessels that normally or frequently operate below 250°F (121°C). Corrosion under the insulation or fireproofing, if undetected, can lead to catastrophic failure of a vessel with little or no warning.

3.

Consider providing emergency depressuring facilities to safely and quickly reduce the vessel pressure and remove the inventory in the event of a fire. Refer to DP XV-F for a discussion on the need for and the design of emergency depressuring facilities.

4.

The application of fire water to the surface of the exposed vessel is very effective in controlling and even arresting or reversing the rate of temperature rise during a fire. Fire water applied uniformly over the entire 2 2 surface of the vessel at a rate of at least 0.25 gpm/ft (10 liters/min-m ) is usually sufficient to keep the metal

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temperature from rising above 212°F (100°C). Although no credit may be taken for the application of fire water in the design of pressure relief devices, it is clear that application of fire water is highly desirable to minimize the risk of vessel failure. Consideration should be given to providing fire water sprays or fixed fire water monitors to protect dry vessels against fire exposures. 5.

The relief load for dry vessels exposed to fire may be calculated from the following equations, taken from API RP 521. é A ' (T - T )1.25 ù w 1 W = 0.1406F MP1 ê ú êë úû T11.1506

ç

(Equation A1-7) US Customary

units é A' (T - T )1.25 ù 1 w W = 0.2771F MP1 ê ú êë úû T11.1506

ç

(Equation A1-7) SI units

where: W = relief rate, lb/h (kg/h) ç

F = environmental factor for insulated vessels (Equation A1-3) M = molecular weight, lb/ lb-mole (kg/kg-mole) P1 = upstream relieving pressure, psia (kPa absolute) ’

2

2

A = exposed surface of the vessel, ft (m ) Tw = vessel wall temperature, °R (°K) T1 = gas temperature at the upstream relieving pressure, °R (°K) = (P1/Pn) Tn Pn = normal operating pressure in vessel, psia (kPa absolute) Tn = normal operating temperature in vessel, °R (°K) Tw represents the maximum recommended wall temperature for the vessel materials. For carbon steel, use Tw = 1560°R (867°K). For other materials, consult EMRE’s Mechanical and Materials Engineering Section. The exposed surface area, A’, used to calculate heat absorption is taken to be the total exposed surface within 25 ft (7.5 m) of 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. Specific interpretations of A’ to be used for various vessels are as follows: 1. Horizontal Drums a. Up to 25 ft (7.5 m) above grade - Use total exposed surface. b. Greater than 25 ft (7.5 m) above grade - Use the horizontal projected area of the vessel 2. Vertical Vessels The exposed surface within 25 ft (7.5 m) of grade is used. If the entire vessel is more than 25 ft (7.5 m) above grade, then only the surface of the bottom head need be included. For vessels supported on skirts that do not require fireproofing of their inside surface per GP 14-03-01, the surface of the bottom head need not be included in the exposed surface area regardless of elevation Once the relief load is calculated using equations A1-7a or A1-7b, the required relief area is calculated using the methodology described under “ DESIGN PROCEDURE, PART III - SIZING FOR VAPOR SERVICE”. Equations A1-7a and A1-7B are based on ideal gas behavior and may not be accurate for fluids that deviate significantly from ideality, such as supercritical fluids. For such cases, or whenever increased accuracy is desired, a time-dependent analysis to determine the highest isobaric expansion rate of the fluid at the relieving pressure is required. The relief requirement is taken as the highest calculated volumetric expansion rate of all time intervals considered.

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11 APPENDIX 2 TRANSIENT PRESSURE RESPONSE SIMULATION FOR FLARE SIZING

This Appendix offers a description of the use of transient pressure response simulation for flare sizing. The term transient pressure response simulation as used in this appendix refers to the time dependent analysis of an overpressure incident to reflect the pressure within the protected system as a function of time considering all of the following: 1. The speed at which the pressure in the protected system is rising due to the postulated contingency. 2. The response time of any safety critical instrumentation (cut-out instruments), during which these instruments need to determine that a true overpressure condition is likely and the course of action to be taken. Consideration must be given to the spread between the set point for the safety critical instruments and the set point of the pressure relief devices and the impact this has in the capability of the safety critical instrumentation to limit the relief rate through the pressure relief devices. 3. The speed at which any valves or other shutdown devices actuated by the safety critical instrumentation function to limit the pressure rise in the protected system. 4. The buildup of pressure/flow within the flare header as the various relief loads are actually received by the flare header. (If any of these issues is not considered, then the relief loads into the flare header should be assumed to be simultaneous.) This approach shall not be used to size PR valves for individual equipment, only for sizing a common discharge header/flare. This Appendix is offered as a supplement to PART IV, DESIGN BASIS OF CLOSED SYSTEMS FOR PRESSURE RELIEF VALVES of this DP. Transient pressures response simulation may be used to assist in selecting flare design loads. This approach attempts to reflect the fact that during emergencies not all the pressure relief (PR) valves that might discharge, do so simultaneously. In addition, some releases may be of short duration (or their peak relief rates are of short duration) due to inherent limitations in inventory or the action of safety critical instruments. This approach considers and takes credit for advances in computational systems, improved instrument reliability, and an increased understanding of the process dynamics which might allow a reliable simulation of the emergency for non-complex systems. Thus, opportunities may exist for less conservative flare system designs.

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Use of transient pressure response simulation to assist in defining the flare design loads is subject to ALL the following restrictions: 1. The flare shall be sized for the larger of the following: a. The load defined by the transient pressure response simulation of the releases during the design contingency emergency being considered while designing for this emergency as a design contingency (where maximum protected system pressure shall be limited to no more than the Code allowable accumulation). b. The load defined by the sum of the peak releases from all PR valves that might discharge during the design contingency emergency being considered without any credit for transient conditions (while designing for this load as a remote contingency under the “1.5 Times Design Pressure Rule" (that is, allowing the protected system pressure to increase to the proof test pressure or 1.5 times the design pressure, whichever is lower). c. Or, the load defined by the potential releases to the system from any other remote contingency while designing for this load as a remote contingency under the “1.5 Times Design Pressure Rule." Note: It is possible/likely that different headers/laterals may be sized by different combinations of these or other contingencies. In addition, it is necessary to verify flare flame stability during the complete range of emergency loads, although the restrictions on flare tip speed and radiation may be waived for all contingencies to which the “1.5 Times Design Practice Rule" is applied. Also note that bellows type PR valve back pressure can not, under any circumstance, exceed 75% back pressure unless the manufacturer certifies a capacity larger than 33% of the capacity without back pressure (i.e., the manufacturer certified that Kb ³ 0.33), and this reduced capacity taken into account in the design. This limitation on bellows type PR valves is necessary since the reduced PR valve capacity at the high back pressure places in question the adequacy of the relief. In the case of conventional type PR valves, high back pressure will also affect performance and the impact this will have on the protection desired needs to be evaluated.

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The transient pressure response simulation load to the flare system shall be reviewed through the use of a response analysis (model) of the unit(s)/system(s) affected by the emergency begin considered. The model shall take into consideration the volumes, inventories, and dynamics of the unit(s) / system(s). Any (cut-out) instrument that actively impacts the transient pressure response simulation load shall be maintained in equivalent fashion to a PR valve and other safety critical instrument (whichever results in the most stringent design and/or testing frequency). In addition, the simulation of the design contingency load shall include the effect of the failure to function (at the time of the emergency) of the most critical 10% (or one, whichever is greater) of these cut-out instruments. Use of fast acting cut-out instruments is preferred for services where simulation is to be used for defining the flare load. The use of the above transient pressure response simulation approach to reduce the size of flare systems shall only be used when considering the need for modifications to existing flare facilities. New flares shall be designed for the sum of the peak releases from all PR valves that will discharge during the design contingency emergency being considered (assuming this emergency to be a design contingency) because the data to do a transient analysis is rarely available for a new design. The use of a transient pressure response simulation for defining the flare size shall be reviewed and approved by the appropriate SOC in each case.

As an example of the application of transient pressure response simulation, the following is offered: Consider a system which includes 10 towers all with PHCOs (Pressure High Cut-Outs) and tied into the same flare. All 10 towers are overpressured simultaneously by a design contingency, cooling water failure for example. The traditional design of this system would assume all the peak loads from the 10 towers happen simultaneously (ignores existence of any high-pressure cut-outs or PHCOs). Thus, traditionally the flare would be designed for the sum of the peak loads as a design contingency. An alternative may be a transient pressure response simulation. This would require tracking pressure inside the towers and flow rate to the flare as a function of time. During the transient pressure response, at some moment the PHCO should actuate (different moment for each tower) to potentially limit the pressure and possibly reduce the load on the flare. But the actuation of each PHCO may not be instantaneous. For example, while the PHCO detects high pressure and sends a signal to shut down, heat input (the heat input may be reduced) and pressure in the towers might continue to rise. Eventually, depending on the system design and the speed with which the system and the PHCOs react, the tower PRVs may open for some time and relieve to the flare. The transient simulation tracks these loads as they occur in the flare and what the total load on the flare is at any time. However, all the PHCOs may not function, so the simulation should be done at lease 11 times: first with all PHCOs working, then one time each with one of the PHCOs disabled (10% or one, whichever is higher). From the results of these simulations, the design of the flare system should be derived, as follows: 1. The flare is designed on a design contingency basis for the dynamic simulation that gives the highest load to the flare (out of the 11+ simulations that would be done). 2. The flare is also designed for the sum of the peak relieving rates as a remote contingency to which the “1.5 Times Design Pressure Rule" is applied. 3. The size of the various laterals would be set by the largest requirement identified for each lateral, usually as a design (but possibly as a remote contingency if there is a larger such contingency). 4. The PRV discharge from each tower would be designed for the peak rate from that tower as a design contingency. This must include the requirement that the installed PRV size at each tower has to be consistent with the peak relief requirement from that tower, assuming the PHCO on that tower fails to work. (In other words, the transient simulation should only apply to the design of the flare header system not the design of the overpressure protection of the individual equipment. Thus the rate from each tower would be the calculated relieving rate, not the PRV rated capacity.) Finally, any other identified contingencies for the system, either design or remote, applicable to one or more of the towers, must be considered; the resulting flare/header sizes compared with the sizes derived above; and the largest combination(s) chosen for the design.

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12 APPENDIX 3 CALCULATION OF TUBE RUPTURE RELIEF LOAD

The following are guidelines for the calculation of the relief load for the contingency of a tube split in a shell and tube heat exchanger: 1. Tube failure in shell and tube exchangers is assumed to result in unimpeded flow from a guillotine cut of a single tube at the tubesheet. The total flow is the sum of those from the two resulting flow paths - a short one through the tubesheet and a longer one down the tube. 2. The diameter of the tube opening should be assumed to be the ID of the tube. 3. Assume the high-pressure side is at its maximum operating pressure. When the maximum operating pressure is not known, use the design pressure. 4. The tube rupture relief load "TS" can be estimated by assuming orifice flow, with no change of phase. This simplified method, summarized under paragraph 4a, provides a conservative result on two counts - it ignores frictional effects in the longer leak path, and it takes no credit for the choking effect in flashing liquids. As tube rupture is not always the relief valve controlling contingency, the conservative orifice approach is often sufficient. If, however, the tube rupture contingency becomes the controlling contingency, a more sophisticated calculation procedure is available and should be used. This procedure is based on research by the Design Institute for Emergency Relief Systems (DIERS) of the American Institute of Chemical Engineers, and is summarized under paragraph 4b. 4a. Calculate the leakage rate "TS" of high pressure fluid at exchanger inlet or outlet conditions, whichever gives the larger relief load. If the high pressure is two-phase, assume the same vapor/liquid ratio as in the normal stream To calculate “TS” use the following equation

TS = Kd 2 r 2 (P1 - P2 ) Where: K = Constant, 2.463 (0.1649) TS = Flow rate of high pressure fluid across tube break, klb/h (kg/h) d = Tube inside diameter, inches (mm) 3

3

r2 = Fluid density at vena contracta, lb/ft (kg/m ) P1 = High-pressure side pressure, psia (kPa absolute) P2 = Low-pressure side pressure, psia (kPa absolute) (Note: this equation assumes a discharge coefficient, C = 0.65)

For fluids that are liquid at the high pressure, use the liquid density for the fluid density at the vena contracta. For fluids that are vapor at the high pressure, calculate r2 as follows: æP ö r 2 = r1çç 2 ÷÷ è P1 ø

1 k

Where: r1 = Density on high-pressure side k = Specific heat ratio = Cp/Cv (dimensionless)

For vapors, the value of P2 depends on the critical flow pressure, Px. If P2 is less than or equal to Px,, use Px in place of P2.. Otherwise, use P2 as P2 in the above equations. Px is calculated as follows:

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k

æ 2 ö (k -1) Px = P1çç ÷÷ è k + 1ø

Where: Px = Critical flow pressure, psia (kPa absolute) 4b. If the tube rupture contingency becomes the governing contingency for the relief valve, or if a more accurate estimate of the relief load is desired, the relief rate "TS" may be calculated using the procedures developed by the Design Institute for Emergency Relief Systems (DIERS) of the American Institute of Chemical Engineers. Details of these procedures may be obtained from EMRE’s Safety & Risk Section. 5. Determine the maximum relief capacity available through the process or utility system connected to the low pressure side. Calculate the net relief load “NR” that must be handled by the PR device by subtracting this value from TS. In doing this calculation, the low pressure side is allowed to go to 1.5 times its design pressure or to its proof test pressure, whichever is lower. When the low-pressure side is liquid filled, the maximum relief capacity through the low pressure side is limited to the normal low-pressure side volumetric flow rate before the tube split occurs, unless a dynamic simulation is done to support the use of a higher flow rate. 6. If pressure relief is via a PR valve or a rupture disc on the exchanger itself (PR valves on exchangers are often too slow for tube splits) proceed as follows: a. If the set pressure of the PR valve or rupture disc is higher than the maximum pressure of the low-pressure fluid, flow of low-pressure fluid will stop, and the relief load is equal to “NR." b. If the set pressure of the PR valve or rupture disc is lower than the maximum pressure of the low-pressure fluid, flow of low-pressure fluid will continue. Mix “TS" with the normal amount of low-pressure material and subtract the relief capacity available through the low pressure side as outlined in Step 5, to determine via a flash the relief load, using consistent temperatures and enthalpies for both streams. In some cases, relief is via an assured open path to a downstream PR valve at the top of a tower/vessel; or the heat exchanger, although protected by a rupture disc, is connected to a downstream tower with a lower design pressure. In these cases, when additional vapor could enter the tower/vessel as a result of the tube split, it is necessary to estimate the amount of vapor that will be generated in the tower/vessel and will have to be release via the tower/vessel overhead PR valve. 1. Assume other feeds and reflux continue to enter tower. 2. Assume reboilers continue to input heat (except if the tube split in question will hydraulically prevent the reboiler from operating). 3. Evaluate impact of tube split on the tower condenser. The tube split may effectively block flow in the overhead circuit. 4. Calculate the maximum vapor to be released via a flash with the following inputs: a. “TS." b. Normal amount of low-pressure material (if the low pressure stream can continue to enter the exchanger). c. Other vapors entering tower, from other feeds or from the reboiler (unless tower material cannot enter the reboiler). d. Varying amounts of tower material, held in downcomers and trays, which can generate additional vapor when mixed with the vapors from the tube split. The calculation entails a trial-and-error, since the composition and temperature of the tower/vessel material to be included in the flash is a variable.

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13 APPENDIX 4 DETAILED REVISION MEMO

Page 8

Revised references 4 and 7.

Page 9

Added references 25, 26, 27, 28 and 29.

Page 15, 16

Revised guidance for vapor blow-through analysis.

Page 16

Clarified basis for determining residual cooling capacity of air-cooled exchangers upon failure of the cooling air supply or control mechanisms (Item 6).

Page 20, 21

Revised allowable accumulation limits for Section VIII vessels. Added guidance for equipment designed to codes other than ASME. Revised heading of the fourth column in Table under Item 19. Revised built-up back pressure limits for conventional, spring loaded PR valves.

Page 22

Revised inlet piping pressure drop criteria for remote contingencies in Item 21.

Page 24, 25

Added paragraph under Consideration of Contingencies. Updated allowable accumulation limits for Section VIII vessels.

Page 26

Restated basis for pressure limits when applying “1.5 Times Design Pressure” rule.

Page 36

Added guidance for DCS system failure under Failure of Automatic Control.

Page 37

Revised guidance for vapor blow-through analysis.

Page 41

Revised general guidance given under Manual Valve to emphasize that either inadvertent opening or closure may be a source of overpressure. Added example under Manual Valve involving a manual bypass valve around a control valve. Provided guidance under Manual Valve for the treatment of double valve installations. Revised first sentence in last paragraph under Manual Valve.

Page 42, 43

Revised conditions under which an exchanger tube rupture need not be considered for shell-and-tube exchangers. Change criteria for requiring transient analysis of tube rupture. Provided for use of alternative computer program to evaluate tube rupture.

Page 43

Provided additional guidance on the analysis of multiple tube ruptures.

Page 46, 47

Added overpressure protection requirements for intermediate extraction stages in condensing turbines.

Page 54

Added guidance for thermal relief of liquids that may vaporize at relieving conditions.

Page 63

Updated allowable accumulation limits for Section VIII vessels.

Page 63, 64

Revised opening characteristics for liquid service relief valves.

Page 64

Added warning about the use of balanced bellows valves in cold or auto-refrigerating service.

Page 66

Added requirement that any valves on pilot-operated valve sensing lines be CSO and of a design that minimizes the risk of accidental closure.

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APPENDIX 4 DETAILED REVISION MEMO (Cont)

Page 67

Revised back pressure limitation for balanced pilot-operated PR valves.

Page 72

Added guidance for set point stagger when local codes limit allowable accumulation to 10% of MAWP regardless of the number of PR valves in parallel. Updated allowable accumulation limits for ASME Section VIII vessels.

Page 82

Corrected Equation (5b).

Page 82

Corrected Equation (6).

Page 85

Revised introductory text under “SIZING FOR FLASHING MIXED PHASE (VAPOR AND LIQUID) AND FLASHING LIQUID SERVICE”. Changed heading of section addressing two-phase flow to exclude reference to saturated liquids.

Page 86

Deleted note regarding potential generation of superheated vapor on step 3 of the sizing procedure for pressure relief valves in flashing service. Deleted note regarding saturated liquid at PRV inlet Revised equation (13) and added equation (13A) Revised text on Step 7. Deleted equations (15) and (15)M from old version.

Page 86

Deleted equations (16), (16)M, (17) from old version. Revised equations (14) and (14)M. Revised definition of terms for use with equation (14) Revised requirements for use of balanced bellows valves.

Page 87

Renumbered equation (18) as equation (15). Revised equations (15) and (15)M for consistency with EE.810E.2002 (formerly equations (18) and (18)M.

Page 87

Revised definition of Kb for use with equation 15 (formerly Equation 18).

Page 88-90

Revised procedure for sizing PR valves in subcooled or saturated liquid service for consistency with recommendations in EE.810E.2002. Renumbered equations to maintain consistent numbering sequence.

Page 90

Revised equations (24) and (25) (formerly equations (19) and (20)).

Page 94-96

Updated PR valve vendor catalog information. Added orifice designation Z1 to table of Crosby large-orifice PR valves. Revised temperature range for Anderson-Greenwood large-orifice PR valve. Revised catalog reference for Anderson-Greenwood large-orifice PR valve. Revised nomenclature for Crosby and Farris PR valves.

Page 100

Revised inlet piping pressure drop criteria for remote contingencies. Revised Inlet Pipe Sizing criteria for manifolds.

Page 101, 102

Revised criteria for minimum size of PR valve discharge manifolds. Revised heading of fourth column in Table under Item 4. Revised built-up back pressure limits for conventional, spring loaded PR valves.

Page 103

Revised equation for Effective Set Pressure.

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APPENDIX 4 DETAILED REVISION MEMO (Cont)

Page 127-130

Table III-2: Updated table to agree with latest vendors' catalogs and API Standard 526.

Page 131

Table III-3: Updated table to agree with latest vendors' catalogs and API Standard 526. Added data for Crosby PR valves.

Page 136

Corrected title of Figure III-4.

Page 138

Replaced Figure III-6 for improved readability and added equation 20.

Page 140, 141

Corrected SI thermal conductivity units for Equation A1-3. Clarified basis for minimum value of environmental factor, F. Revised table of typical environmental factors for consistency with Equation A1-3. Added explanatory note under typical environmental factors table.

Page 141

Clarified that it is the external surface area of shell-and-tube exchangers and not the heat transfer surface area or the tube bundle that is used in the calculation of wetted surface for fire exposure. Added guidance on basis for tube-side and shell-side relief rates for shell-and-tube exchangers exposed to fire. Added guidance for free-draining heat exchangers exposed to fire.

Page 145

Revised calculation procedure for STEP 2 – VAPOR RELEASE RATE.

Page 147, 148

Revised steps 1 and 2 of procedure for two-phase relief during fire. Revised definition of Q for Equation A1-5. Revised definition of v0 for Equation A1-5. Revised definition of l for Equation A1-5. Revised warning on Step 3 (formerly Step 2). Renumbered former steps 2 through 4 as steps 3 through 5. Revised Step 5a (formerly Step 4a). Added Steps 5b, 5f and 5g. Revised Steps 5c and 5e (formerly Steps 4b and 4d). Former Step 4c becomes Step 5d. Added explanatory note.

Page 149

Renumbered equations A1-7a and A1-7b as A1-7 for consistency with equation numbering system used elsewhere in DP XV-C. Added environmental factor, F, to equations A1-7 (US Customary and SI Units versions). Added F factor to nomenclature for equations A1-7.

Page 150

Replaced numerical accumulation limits with the words “Code allowable”.

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