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Handbook of fire and explosion protection engineering principles for oil, gas, chemical,and related facilities

Handbook of fire and explosion protection engineering principles for oil, gas, chemical,and related facilities

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    • HANDBOOK OFFIRE ANDEXPLOSION PROTECTIONENGINEERING PRINCIPLES FOROIL, GAS, CHEMICAL, ANDRELATED FACILITIESbyDennis P. Nolan, P.E.NOYES PUBLICATIONSWestwood, New Jersey, U.S.A.
    • Copyright Q 1996 by Noyes PublicationsNo part of this book may be reproduced or utilized inany form or by any means, electronic or mechanical,including photocopying, recording or by any informa-tion storage and retrieval system, without permissionin writing from the Publisher.Library of Congress Catalog Card Number 96-10908Printed in the United States of America byNoyes Publications369 Fairview Ave.Westwood, New Jersey 07675ISBN: 0-8155-1394-110 9 8 7 6 5 4 3 2 1Library of Congress Cataloging-in-Publication DataNolan, Dennis P.Handbook of fire and explosion protection engineering principlesfor oil, gas, chemical, and related facilities / by Dennis P. Nolan.p. cm.Includes index.1. Chemical plants--Fires and fire prevention. 2. PetroleumISBN 0-8155-1394-1refineries--Fires and fire prevention. 3. Explosions. I. Title.TH9445.C47N65 1996660.2804--dc20 96-10908CIP
    • About the AuthorDennis P. Nolan has had a long career devoted to risk engineering, fire protectionengineering, loss prevention engineering and system safety engineering. He holds a Masterof Science degree in Systems Management from Florida Institute of Technology and aBachelor of Science degree in Fire Protection Engineering from the University of Maryland.He is a U.S.registered Fire Protection Engineering Professional Engineer in the State ofCalifornia.He is currently associated with the Fire Prevention Engineering staff of the Saudi Arabian OilCompany (Saudi Aramco), located in Abqaiq, Saudi Arabia, site of the largest oil and gasproduction facilities in the world. He has also been associated with Boeing, Lockheed,Marathon oil Company and Occidental Petroleum Corporation in various fire protectionengineering, risk and safety roles at several locations in the United States and overseas. Aspart of his career he has examined oil production, refining and marketing facilities in varioussevere and unique worldwide locations, including Africa, Asia, Europe, the Middle East,Russia, and North and South America. His activity in the aerospace field has includedengineering support for the Space Shuttle launch facilities at Kennedy Space Center (and forthose undertaken at Vandenburg Air Force Base, California) and "Star Wars" Defense systems.Mr. Nolan has received numerous of safety awards and is a member of the American Societyof Safety Engineers, National Fire ProtectionAssociation, Society of Petroleum Engineers, andSociety of Fire Protection Engineers. He is the author of the book "Application of HAZOPand What-If Safety Reviews to the Petroleum,Petrochemicaland Chemical Industries," whichis widely referred to within the petroleum and chemical industries. Mr. Nolan has also beenlisted in "Whos Who in California" for the last ten years and has been elected to appear inthe 1996 International Edition of "Whos Who of Science and Engineering."vii
    • List of Figures1.2.3.4.5.6.7.8.10.11.12.Example of Autoignition Temperature Approximation Method . . . . . . . . . . . . . . . . . . . 32Historical Average Financial Loss for Major Incidents . . . . . . . . . . . . . . . . . . . . . . . . 64Safety Flow Chart ................................................. 88Example of Horizontal Vessel Rupture Calculation Method .................... 128Example of Column Rupture Calculation Method ........................... 129Process Vessel Depressurization Flowchart ............................... 132International Electrical Area Classification Differences ....................... 161Explosion Overpressure Consequence Diagram .............................Offshore Evacuation Flowchart ....................................... 200Electrical Installation Fire Control Flowchart .............................. 220Relative Effectiveness of Various Spray Arrangements at Wellhead Flames168. . . . . . . . . 233xi
    • List of Tables1.2.3.4.5.6.7.8.9.10.11.12.13.14.15.16.17.18.19.20.21.22.23.24.25.26.27.28.29.30.Independent Levels of Protection (ILP) ................................... 21Characteristics of Selected Common Hydrocarbons ........................... 39Fire Hazard Zone (FHZ) Identification Example ............................. 56Fire Extinguishing Explanations. Fire Hazardous Zone Drawings . . . . . . . . . . . . . . . . . 57General Hazards of Common Petroleum Commodities ......................... 60Immediate Cause of Death (Gulf of Mexico. 1980-1990) ...................... 83Cause of Incidents. Gulf of Mexico ..................................... 84Example of Quantifiable Accident Scenario Summary ......................... 92Comparison of Industry and Insurance Spacing Tables ....................... 102Comparison of Dike Design Requirements ................................ 108Drainage Requirements and Capacity Analysis ............................. 109Typical ESD Levels ............................................... 117Typical Safety Integrity Levels (SIL) ................................... 118Firesafe Valve Test Standards ........................................ 122General Guidelines for Material Disposal Methods .......................... 135Recognized International Electrical Approval Testing Agencies . . . . . . . . . . . . . . . . . . 146Recognized Fire Testing Laboratories ................................... 167Passive Fire Protective Systems ....................................... 170Comparison of Fire Detectors ........................................ 183Application of Fixed Fire Detection Devices .............................. 184Comparison of Common Hydrocarbon Vapor Hazards ....................... 185Comparison of Gas Detection Systems .................................. 193Example of Firewater Demand Calculations ............................... 206Fire Pump Standards ............................................... 208Test Standards for Fire Protection Valves ................................ 210Fixed Fire Suppression Design Option Basis. Application Table . . . . . . . . . . . . . . . . . 223Fire Suppression System Applications ................................... 224Advantages and Disadvantages of Firewater Systems ........................ 225Probability of Human Errors ......................................... 241Color Coding Applications .......................................... 244NoticeReasonable care has been taken to assure that the books content is authentic. timely andrelevant to the industry today; however. no representation or warranty is made to its accuracy.completeness or reliability.Consequently. the author and publisher shall have no responsibilityor liability to any person or organization for loss or damage caused. or believed to be caused.directly or indirectly. by this information.In publishing this book. the publisher is not engagedin rendering legal advice or other professional services.It is up to the reader to investigate andassess his own situation. Should such study disclose a need for legal or other professionalassistance the reader should seek and engage the services of qualified professionals.xii
    • PrefaceThe security and economic stabilityof many nations and multinationaloil companies are highly dependent onthe safe and uninterrupted operation of their oil, gas and chemical facilities. One of the most critical impactsthat can occur to these operations are fire and explosions from accidental or political incidents. The recentGulf War amplydemonstratesthe impact these events can have on oil installations.This publication is intended as a general engineering handbook and reference guideline for those personnelinvolved with fire and explosion protection aspects of these critical hydrocarbon facilities. Several otherreference books are available that provide portions of the necessary information required to evaluatehazards, provide fire protection measures, or determine insurance needs. However most are not fkllycompletein mentioning all technical subjects and some have become somewhat technically outdated. Theyusually tend to be a collectionof technical papers or else provide a broad coverage of subjectswithout muchpractical applications or details. The main objective of this handbook is to provide some backgroundunderstanding of fire and explosion problems at oil and gas facilities and a general source of referencematerial for engineers, designers and others facing fire protection issues, that can be practically applied. Itshould also server as a reminder for the identificationof unexpected hazards at a facility.As stated, much of this book is intended to be a guideline. It should not be construed that the materialpresented herein is the absolute requirement for any facility. Indeed, many organizations have their ownpolicies, standardsand practicesfor the protection of their facilities. Portions of this book are a synopsis ofcommon practices employed in the industry and can be referred to as such where such information isunavailableor outdated. Numerous design guidelines and specifications of major, small and independent oilcompanies as well as information from engineering firms and published industry references have beenreviewed to assist in its preparation. Some of the latest published practices and research into fire andexplosionshave also been mentioned.This book in not intended to provide in-depth guidance on basic risk assessment principles nor on fire andexplosion protection engineering foundations or design practices. Several other excellent books areavailableon these subjectsand some references to these are provided at the end of each chapter.The scope of this book is to provide a practical knowledge and guidance in the understanding of preventionand mitigation principals and methodologies from the effects of hydrocarbon fires and explosions. TheChemical Process Industry (CPI), presents several different concerns that this book does not intend toaddress. However the basic protection features of the Hydrocarbon Process Industry (HPI) are alsoapplicableto the chemical process industry and other related process industries.Explosion and fire protection engineeringprinciples for the hydrocarbon industriesare still being researched,evolved and expanded, as is the case with most engineering disciplines. This handbook does not profess tocontain all the solutionsto fire protection problems associated with hydrocarbon facilities. It does however
    • x Prefacetry to shed some insight into the current practices and trends being applied in the petroleum industry today.From this insight, professional expertise can be obtained to examine design features in detail to resolveconcernsof fires and explosions.Continuallyupdated technical information is needed so that industrial processes can be designed to achievethe optimum risk levels from the inherent material hazards but stillprovide acceptableeconomic returns.This book is generally written from the point of reference of the United States basis, but does attempt toreference other international codes, standards and practices where they have been referenced or heavily usedby the international oil industry. It does use SI units as the normal units of measure, as these are typicallyused in the international oil industry.
    • Contents1. INTRODUCIION ....................................................... 1Historical Background .................................................. 2Legal Influences ....................................................... 4Hazards and Their Prevention ............................................ 4Systems Approach ..................................................... 5Fire Protection Engineering Role .......................................... 5Risk Management and Insurance .......................................... 6Senior Management Responsibility and Accountability .......................... 72. OVERVIEW OF OIL AND GAS FACILITIES .................................. 9Exploration .......................................................... 9Production .......................................................... 10Enhanced Oil Recovery @OR) ........................................... 11Secondary Recovery ................................................... 11Water Injection ..................................................... 11Steam Injection ..................................................... 12Gas Injection ....................................................... 12Tertiary Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Chemical Injection ................................................... 12Thermal Recovery ................................................... 12Recirculated Gas Drive ................................................ 12Transportation ....................................................... 12Refining ............................................................ 13Basic Distillation .................................................... 13Thermal Cracking ................................................... 14Alkylation and Catalytic Cracking ........................................ 14Purification ........................................................ 14Typical Refinery Process Flow ........................................... 14Production Percentages ................................................ 15Marketing .......................................................... 153. PHILOSOPHY OF PROTECTION PRINCIPALS .............................. 17General Philosophy ................................................... 18Worst Case Conditions ................................................. 19Ambient Conditions .................................................. 20Independent Layers of Protection (ILP) .................................... 20Design Principles ..................................................... 22Accountability and Auditability .......................................... 254. PHYSICAL PROPERTIES OF HYDROCARBONS ............................. 27General ............................................................ 27Alkene Series ...................................................... 28xiii
    • xiv ContentsAlkyne Series ...................................................... 28Cyclic Hydrocarbons ................................................. 28Characteristics of Hydrocarbons .......................................... 29Lower Explosive Limit &EL)/Upper Explosive Limit VEL) .................... 29Flash Point(FP) ...................................................... 29Autoignition Temperature (AIT).......................................... 30Vapor Density ....................................................... 33Vapor Pressure ...................................................... 33Specific Gravity ...................................................... 33Flammable .......................................................... 33Combustible ......................................................... 33Heat of Combustion ................................................... 33Description of Some Common Hydrocarbons ......................... :. . . . . .34Natural Gas ........................................................ 34Crude Oil ......................................................... 34Methane (Cl) ....................................................... 34........................................ 34Ethane (C2) ........................................................ 35F’ropane(C3) ....................................................... 35Butane(C4) ........................................................ 35LPG. Liquefied Petroleum Gas (C3 & C4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Gasoline (C5 to C11) ................................................. 36Condensate (C4. C5. C6 & )) ........................................... 36Gas and Fuel Oils (C12 to C19) ......................................... 37Lubricating Oils and Greases (C20 to C27) ................................. 37Asphalts and Waxes (C28 & )) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37LNG. Liquefied Natural Gas (Cl)5. CHARACTERISTICS OF HYDROCARBON RELEASES. FIRES AND EXPLOSIONS .. 41Hydrocarbon Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42Gaseous Releases ..................................................... 42Mists or Spray Releases ................................................ 43Liquid Releases ...................................................... 43Nabre and Chemistry of Hydrocarbon Combustion ........................... 44Hydrocarbon Fires .................................................... 46Nature of Hydrocarbon Explosions ........................................ 48Process System Explosions (Detonations) ................................... 48Vapor Cloud Explosions ............................................... 48Semi-confined Explosion Overpressures ................................... 50Vapor Cloud Explosion Overpressures ..................................... 50Boiling Liquid Expanding Vapor Explosions (BLEVE) ......................... 51Smoke and Combustion Gases ........................................... 52Mathematical Consequence Modeling ...................................... 53Methods of Flame Extinguishment ........................................ 55Cooling ........................................................... 55Fuel Removal ...................................................... 55Chemical Reaction Inhibition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55Flame Blow Out . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55........................... 56Oxygen Depravation .................................................. 55Selection of Fire Control and Suppression MethodsTerminology of Hydrocarbon Explosions and Fires . . . . . . . . . . . . . . . . . . . . . . . . . . . . 586. HISTORICAL SURVEY OF FIRE AND EXPLOSIONS IN THEHYDROCARBON INDUSTRIES ........................................... 62Relevancy of Incidents ................................................. 63
    • Contents xvOffshore Oil Production and Exploration (USA) .............................. 81Worst Fatal Incidents ................................................. 81Worst Property Losses ................................................ 82Summary ........................................................... 857. RISKANALYSIS ....................................................... 87Safety Flow Chart .................................................... 87Risk Identification and Evaluation ........................................ 89A. Qualitative Reviews ................................................ 90B.Quantitative Reviews ............................................... 90C.Specialized Supplemental Studies ...................................... 90Risk Acceptance Criteria ................................................ 93Relevant and Accurate Data Resources ..................................... 938. SEGREGATION. SEPARATION AND ARRANGEMENT ........................ 95Segregation ......................................................... 95Separation .......................................................... 96Manned Facilities and Locations .......................................... 97Storage Facilities-Tanks ............................................... 98Process Units ........................................................ 99Flares .............................................................. 99Critical Utilities and Support Systems ..................................... 99Fire Zones ......................................................... 100Arrangement ....................................................... 101Facility Access and Egress ............................................. 1019. GRADING. CONTAINMENT. AND DRAINAGE SYSTEMS ..................... 104Drainage Systems .................................................... 104Process and Area Drainage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104Surface Drainage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105Open Channels and Trenches . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106Spill Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10710. PROCESS CONTROLS ................................................. 111Human Observation .................................................. 111Instrumentation and Automation ........................................ 111Electronic Process Control ............................................. 112Process System Instrumentation and Alarms ............................... 113Transfer and Storage Controls .......................................... 113Burner Management Systems ........................................... 11411. EMERGENCY SHUTDOWN ............................................. 116Definition and Objective ............................................... 116Design Philosophy ................................................... 116Activation Mechanisms ................................................ 116Levels of Shutdown .................................................. 117Reliability and Fail Safe Logic .......................................... 117ESD/DCS Interfaces .................................................. 119Activation Points .................................................... 119Activation Hardware Features .......................................... 120Isolation Valve Requirements ........................................... 120Emergency Isolation Valves (EIV) ....................................... 121Subsea Isolation Valves (SSIV) .......................................... 121Protection Requirements .............................................. 121
    • xvi ContentsSystem Interactions .................................................. 12312. DEPRESSURIZATION. BLOWDOWN AND VENTING ........................ 125Objective .......................................................... 125Blowdown ......................................................... 133Venting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133Flares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13313. OVERPRESSURE AND THERMAL RELIEF ................................ 137Pressure Relief Valves (PSV) ........................................... 138Thermal Relief ...................................................... 139Solar Heat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139Thermal Relief Fluid Disposal .......................................... 140Isolation Circumvention . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140Disposal to the Oily Water Sewer ....................................... 140Surface Runoff ..................................................... 140Pressure Relief Device Locations ........................................ 14014. CONTROL OF IGNITION SOURCES ...................................... 143Open Flames. Hot Work and Smoking .................................... 143Electrical Arrangements ............................................... 143Electrical Area Classification ........................................... 143Surface Temperature Limits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147Classified Locations and Release Sources .................................. 147Protection Measures .................................................. 148Explosionproof Rated Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148Intrinsically Safe Rated Equipment ...................................... 148Hermetically Sealed Electrical Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148Purging .......................................................... 148Relocation of Devices ................................................. 149Surface Temperatures ................................................ 149Static ............................................................. 149Lightning .......................................................... 150Internal Combustion Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151SparkArrestors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151HandTools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15115. ELIMINATION OF PROCESS RELEASES .................................. 154Inventory Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155Vents and Relief Valves ............................................... 155Sample Points ....................................................... 155Drainage Systems .................................................... 155Storage Facilities .................................................... 155Pump Seals ......................................................... 156Vibration Stress Failure of Piping ....................................... 156Rotating Equipment .................................................. 15716. FIRE AND EXPLOSION RESISTANT SYSTEMS ............................. 159Explosions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159Definition of Explosion Potentials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160Explosion Protective Design Arrangements ................................. 162Vapor Dispersion Enhancements ........................................ 163Water Sprays ...................................................... 163Air Cooler Fans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163
    • Contents xviiLocation Optimization Based on Prevailing Winds ........................... 163Supplemental Ventilation Systems ....................................... 163Damage Limiting Construction .......................................... 164Fireproofing Specificatioas ............................................. 166Fireproofing Materials ................................................ 169Radiation Shields .................................................... 171Water Cooling Sprays ................................................ 171Vapor Dispersion Water Sprays ......................................... 171Locations Requiring Consideration of Fire Resistant Measures . . . . . . . . . . . . . . . . . . 172Flame Resistance .................................................... 172Fire Dampers ....................................................... 173Smoke Dampers ...................................................... 173Flame and Spark Arrestors ............................................ 173Piping Detonation Arrestors ............................................ 174Fireproofing ........................................................ 16417. FIRE AND GAS DETECTION AND ALARM SYSTEMS ....................... 177Fire and Smoke Detection Methods ...................................... 177Human Surveillance .................................................. 177Manual Activation Callpoint (MAC)/Manual Pull Station (MPS) . . . . . . . . . . . . . . . . .178Telephone Reporting ................................................. 178Portable Radios ..................................................... 178Smoke Detectors ..................................................... 178Ionization ........................................................ 178Photoelectric ...................................................... 178Dual Chamber ..................................................... 179Very Early Smoke Detection and Alarm P S D A ) ........................... 179Thermal or Heat Detectors ............................................. 179Optical (Flame) Detectors .............................................. 180Ultraviolet (VV)Detector ............................................. 180Single Frequency Infrared (IR) Detectors .................................. 181Dual or Multiple Frequency Infrared (IR/IR) Detectors ........................ 181Ultravioletflnfiared (UV/IR) Detectors .................................... 182Multi-Band Detectors ............................................... 182Gas Detection ....................................................... 185Application ......................................................... 186Typical Hydrocarbon Facility Applications ................................. 187Catalytic Detectors ................................................... 188Infra-Red (IR) Beam Gas Detection ...................................... 189Application (IR Beam) ............................................... 189Alarm Setting ....................................................... 189Calibration ......................................................... 190Hazardous Area Classification Rating ..................................... 190Fire and Gas Detection Control Panels .................................... 190Graphic Annunciation ................................................ 191Power Supplies ...................................................... 191Emergency Baclolp Power ............................................. 191Time Delay ......................................................... 191Voting Logic ....................................................... 191Cross Zoning ....................................................... 191Executive Action .................................................... 192Circuit Supervision ................................................... 192Description ....................................................... 188
    • xviii Contents18. EVACUATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196Alarms and Notifications .............................................. 196Alarm Initiation ..................................................... 197Evacuation Routes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197Emergency Doors. Exits. and Escape Hatches ............................... 198Marking and Identification ............................................. 198Emergency Illumination ............................................... 198Offshore Evacuation .................................................. 198NortNSouth Atlantic and NortNSouth Pacific Environments . . . . . . . . . . . . . . . . . . . 199Temperate and Tropic Environments ..................................... 199Means of Egress ..................................................... 199Flotation Assistance .................................................. 19919. METHODS OF FIRE SUPPRESSION ...................................... 202Portable Fire Extinguishers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 202Water Suppression Systems ............................................ 204Water Supplies ...................................................... 204Fire Pumps ......................................................... 205Fire Pump Standards and Tests ......................................... 208Firewater Distribution Systems .......................................... 208Firewater Control and Isolation Valves ................................... 209Sprinkler Systems .................................................... 210Water Deluge Systems ................................................ 210Water Spray Systems ................................................. 210Water Flooding ..................................................... 211Steam Smothering ................................................... 211Water Curtains ..................................................... 211Blow Out Water Iqjection System ....................................... 212Hydrants. Monitors and Hose Reels ...................................... 212Nozzles ............................................................ 213Foamwater Suppression Systems ......................................... 213Types ........................................................... 214Concentrations ..................................................... 214Systems .......................................................... 214High Expansion Foam ............................................... 216Carbon Dioxide Systems .............................................. 216Halon ........................................................... 218Halon Replacements ................................................. 219Oxygen Deficient Gas Inerting Systems ................................... 219Wet Chemical ..................................................... 221Dry Chemical ..................................................... 221Dual Agent Systems .................................................. 221Chemical and Foam ................................................. 221Gaseous Systems ..................................................... 216Chemical Systems .................................................... 22120. SPECIAL LOCATIONS. FACILITIES AND EQUIPMENT ...................... 228Arctic Environments ................................................. 228Desert Environments ................................................. 228Offshore Facilities ................................................... 229Offshore Floating Exploration and Production Facilities ....................... 230Pipelines ........................................................... 230Wellheads-Exploration (Onshore and Offshore) ............................ 231Loading Facilities .................................................... 234
    • Contents xixElectrical Equipment and Communication Rooms ........................... 234Battery Rooms ...................................................... 235Enclosed Turbines or Gas Compressor Packages ............................ 235Heat Transfer Systems ................................................ 236Cooling Towers ..................................................... 237Oil Filled Transformers ............................................... 237Hydrocarbon Testing Laboratories ....................................... 237Warehouses ........................................................ 238Cafeterias and Kitchens ............................................... 23821. HUMAN FACTOR AND ERGONOMIC CONSIDERATIONS .................... 240Human Attitude ..................................................... 243Access and Acceptability ............................................... 243Instructions, Markings and Labeling ..................................... 243Color and Identification ............................................... 244Colors ........................................................... 244Numbering and Identification ........................................... 245Instrumentation Alarm Overload ........................................ 245Noise Control ....................................................... 245Panic ............................................................. 246Security ........................................................... 246Accommodation of Religious Functions .................................... 246APPENDIX A: TESTING FIREWATER SYSTEMS ............................... 249A.l Testing of Firewater Pumping Systems ................................ 250A.2 Testing of Firewater Distribution Systems .............................. 254A.3 Testing of Sprinkler and Deluge Systems ............................... 258A5 Testing of Hose Reels and Monitors .................................. 260A.4 Testing of Foam Systems ........................................... 259APPENDIX B: REFERENCE DATA ........................................... 262B.l Fire Resistance Testing Standards .................................... 263B.2 Explosion and Fire Resistance Ratings ................................ 266B.3 National Electrical Manufacturers Association (NEMA) . . . . . . . . . . . . . . . . . . . 269B.4 Hydraulic Data .................................................. 273B.5 Selected Conversion Factors ........................................ 274ACRONYM LIST ......................................................... 278GWSSARY ............................................................. 283INDEX ................................................................. 289
    • Chapter 1IntroductionFire, explosions and environmentalpollution are the most serious "unpredictable"life affecting and businesslosses having an impact on the hydrocarbon industriestoday. These issues have essentiallyexisted sincetheinception of industrial scale petroleum and chemical operations during the middle of the last century. Theycontinue to occur with ever increasing financial impacts. It almost appears that the management of industryis oblivious, or else must be careless, to the potential perils under their command. Although in some circlesmost accidentscan be thought of as non-preventable, all accidentsare in fact preventable.Research and historical analyseshave shown that the main cause of accidents or failures can be categorizedaccordingto the followingbasic areas:Ignorancea.b.c.d.e.fIncompetentdesign, constructionor inspection occurs.Supervisionor maintenanceoccurs by personnel without the necessaryunderstanding.Assumption of responsibilityby managementwithout an adequateunderstanding of risks.Thereis a lack of precedent.There is a lack of sufficientpreliminary information.Failureto employcompetentLoss Preventionprofessionals.EconomicConsiderationsa.6.Initial engineeringand construction costs for safety measures appear uneconomical.Operation and maintenancecosts are unwittinglyreduced to below what is necessary.Oversight and Negligencea.b.c.d.e. Unethicalbehavior occurs.Otherwisecompetent professional engineersand designerscommit errors.Contractual personnel or company supervisorsknowingly assume high risks.Lack of proper coordinationin the review of engineeringdesigns.Failure to conduct prudent safetyreviews or audits.1
    • 2 Handbook of Fire and Explosion ProtectionUnusual Occurrencesa.b.c. Labor unrest, vandalism.Natural catastrophes - earthquakes, extremeweather, etc.Politicalupheaval -terrorist activities.As can be seen, the real cause of most accidents is what might be classified as human errors. Most peoplehave good intentions to perform a function properly, but where shortcuts, easier methods or considerableeconomic gain opportunities appear or present themselves, human vulnerability usually succumbs to thetemptation. Therefore it is prudent in any organization, especiallywhere high risk facilitiesare operated, tohave a system in place to conduct considerable independent checks, inspections, and safety audits of thedesign and construction of the installation.This book is about engineering principles and philosophies to identi@and prevent accidents associated withhydrocarbon facilities. All engineering activities are human endeavors and thus they are subject to errors.Fully approved facility designs and later minor changes can introduce an aspect from which something cango wrong. Someof these human errors are insignificant and may be never uncovered. However others maylead to catastrophic incidents when combined with other activities. Recent incidents have shown that any"fullyengineered"and operationalprocess plants can experiencetotal destruction. Initial conceptual designsand operational philosophies have to address the possibilities of a major incident occurring and providemeasures to prevent or mitigate such events.Historical BackgroundThe first commercially successful oil well was drilled in August 1859 in Titusville (Oil Creek), Pennsylvaniaby Colonel Edwin Drake. Few people realize that Colonel Drakes famous oil well caught fire and somedamage was sustained to the structure shortly after its operation. Later in 1861 another oil well at "OilCreek", close to Drakes well, caught fire and grew into a local conflagration that burned for three dayscausing 19 fatalities. One of the earliest oil refiners in the area, Acme Oil Company, suffered a major fireloss in 1880, from which it never recovered. The State of Pennsylvania passed the first anti-pollution lawsfor the petroleum industry in 1863. These laws were enacted to the prevent release of crude oil intowaterways next to oil production areas. At another famous early oil field named "Spindletop",an individualsmoking set off the first of several catastrophic fires, which raged for a week, only three years after thediscovery of the reservoir. Major fires occurred at Spindletopalmost every year during its initial production.Considerable evidence is available that hydrocarbon fires were a fairly common sight at early oil fields.These fires manifested themselves either from man-made, natural disasters, or from deliberate and extensiveflaring of the then "unmarketable" reservoir gas. Hydrocarbon fires were accepted as part of the earlyindustry and generallylittle effortswere made to stem the their existence.Ever since the inception of the petroleum industry the level of fires, explosions and environmental pollutionthat have precipitated from it, has generally paralleled its growth. As the industry has grown so has themagnitude of its accidental events. Relatively recent events such as the Flixborough incident (1974),Occidentals Piper Alpha disaster (1988), and Exxons Valdez oil spill (1989) have all amply demonstratedthe extreme financialimpact these accidentscan produce.After the catastrophic fire that burned ancient Rome in 64 A. D., the emperor Nero rebuilt the city with fireprecautions that included wide public avenues, limitations in building heights, provision of fireproofconstruction and improvementsto the city water supplies to aid in fire fighting. Thus it is very evident that
    • Introduction 3the basic fie protection requirements such as limiting &el supplies (fireproof construction), removing theavailable ignition sources (wide avenues and limited building heights to prevent carryover of flying brandembers) and providing fie control and suppression (water supplies), have essentially been known sincecivilizationbegan.Amazingly, "Heron of Alexandria", the technical writer of antiquity (circa 100 A.D.), describes a twocylinder pumping mechanism with a dirigiblenozzle for fighting fires in hisjournals. It is very similar to theremains of a Roman water supply pumping mechanism on display in the British Museum in London.Devices alan to these were also used in the eighteenth and ninetieth century in Europe and America toprovide fire fightingwater. There is therefore considerableevidencesociety has generallytried to prevent ormitigatethe effectsof fires, admittedlyafter a major mishap has occurred.The Hydrocarbon Processing Industry (HPI), has traditionally been reluctant to invest capital where animmediate direct return on the investment to the company is not obvious, as would any business enterprise.Additionallyfinancial fire losses in the petroleum and related industrieswere relatively small up to about the1950s. This was due to the small size of hcilities and the relatively low value of oil and gas to the volumeof production. Until 1950, a fire or explosion loss of more than 5 millionU. S. Dollars had not occurred inthe refining industry in the USA. Also in this period, the capital intensive offshore oil exploration andproduction industry were only just beginning. The use of gas was also limited early in the century.Consequentially its value was also very low. Typically production gas was immediately flared or the wellwas capped and considered as an uneconomical reservoir. Since gas development was limited, large vaporexplosions were relatively rare and catastrophic destruction from petroleum incidents was essentiallyunheard of The outlays for petroleum industry safety features were traditionally the absolute minimumrequired by governmentalregulations. The development of loss prevention philosophies and practices weretherefore not effectivelydevelopedwithin the industry.In the beginnings of the petroleum industry, usually very limited safety features for fire or explosionprotection were provided, aswas evident by the many early blowouts and fires. The industry became knownas a "risky" operation, not only for economic returns, but also for safety (loss of life and propertydestruction) and environmental impacts, although this was not well understood at the time.The expansion of industrial facilities after WW 11, construction of large integrated petroleum andpetrochemical complexes, increased development and uses of gas deposits, coupled with the rise of oil andgas prices in the 1970shave sky-rocketed the value of petroleum products and facilities. It has also meantthe industry was rapidly awakened to the possibility of large financial losses if a major incident occurred. Infact fire losses greater than 50 million U. S. Dollars were first reported during the years 1974 and 1977(ie.,Fhbourough U.K.,Qatar, and Saudi Arabia). In 1992,the cost just to replace the Piper Alpha platform andresume production was reportably over one billion U.S.Dollars. In some instances legal settlements havebeen financially catastrophic, e.g., the Exxon Valdez oil spill legal fines and penalty was five billion U. S .Dollars Financial forecasts have predicted that the long term trend in oil prices should increase as oilreserves are eventually reduced and depleted.It should also be remembered that a major incident may also force a company to literary withdrawn fromthat portion of the business sector where public indignation, prejudice or stigma towards the companystrongly developsbecause of the loss of life suffered. The availabilityof 24 hour news transmissionsthroughworldwide satellite networks virtually guarantees a significant incident in the hydrocarbon industry will beknown worldwidevery shortly after it occurs, resulting in immediatepublic reaction.Only in the last several decades has it been well understood and acknowledgedby most industries, that fireand explosion protection measures may be also be operational improvemyt measures, as well as a means ofprotecting a facility against destruction. An example of how the principle of good safety practice equates togood operating practice is the installationof emergency isolation valves at a facility inlet and outlet pipelines.In an emergencythey serve to isolate &el supplies to an incident and therefore limit damage. In theory theycould also serve as an additionalisolationmeansto a facilityfor maintenance and operational activitieswhen
    • 4 Handbook of Fire and Explosion Protectiona major facility isolation requirement occurs. It can be qualitatively shown that it is only limitations inpractical knowledge by those involved in facility construction and cost implications that have generallyrestricted applicationof adequatefire protection measuresthroughout history.Nowadays safety features should hopehlly promulgate die design and arrangement of all petroleumfacilities. In fact, in highly industrial societiesthese features must demonstrateto regulatory bodies that thefacility has been adequately designed for safety, before permission is given for their construction. It is thusimperativethat these measures are well defined early in the design concept in order to avoid costly projectschange orders or later incident remedial expenses required by regulatory bodies. Industry experience hasdemonstrated that reviewing a project design early in the conceptual and preliminary stages for safety andfire protection features is more cost effective than performing reviews after the designs have beencompleted. The "Cost Influence Curve" for any project acknowledgesthat 75% of a project cost is definedin the first 25% of the design. On averagethe first 15% of the overall project cost is usually spent on 90%of the engineeringdesign. Retrofit or modification costs are estimated at ten times the cost after the plant isbuilt and 100 times after an incident occurs. It should also be realized that fire protection safety principlesand practices are also prudent business measures that contribute to the operational efficiencies of a facility.Most of these measures are currently identified and evaluated through a tlio~oughand systematic riskanalysis.Ai Legal InfluencesBefore 1900, the U.S. industry and the Federal Government generally paid little notice to the safety ofindustrialworkers. Only with the passage of the Workmens CompensationLaws in the U.S.between 1908and 1948 did businessesstart to improvethe standardsfor industrialsafety. Making the work environmentallysafer was found to be less costly than paying compensation for injuries, fatalities and governmental fines.Labor shortages during World War XI focused renewed attention on industrial safety and on the lossesincurred by industrial accidents, in order to keep production output available for the war effort. In the1960s, a number of industry specific safety laws were enacted in the U.S. They included the Metal andNonmetallicMine Safety Act, the Coal Mine Health and Safety Act, and the ConstructionSafety Act, all ofwhich mandated safety and fire protection measures for workers by the companies employing them. Amajor U.S. policy towards industrial safety measures was established in 1970, when for the first time allindustrial workers in businesses affected by interstate commerce were covered by the Occupational Safetyand Health Act. Under this act, the National Institute for Occupational Safety and Health (NIOSH) wasgiven responsibility for conducting research on occupational health and safety standards, and theOccupational Safety and Health Administration (OSHA) was charged with setting, promulgating, andenforcingappropriatesafetystandardsin industry.Hazardsand Their PreventionPetroleum and chemical related hazards can arise from the presence of combustibleor toxic liquids, gases,mist, or dust in the work environment. Common physical hazards include ambient heat, burns, noise,vibration, sudden pressure changes, radiation, and electric shock. Various external sources, such aschemical,biological, or physical hazards, can causework related injuriesor fatalities. Although all of thesehazards are of concern this book primarily concentrates on fire and explosions hazards that can causecatastrophicevents.Hazardsmay also result from the interaction between company employeesand the work environment;theseare called "ergonomic" hazards. If the physical, psychological, or environmental demands on workersexceed their capabilities, an ergonomic hazard exists. These hazards, in themselves may lead to fbrthermajor incidents when the individual cannot perform properly under stress during critical periods of plant
    • Introduction 5operations. Ergonomichazards can cause either physiologicalor psychological stress in individuals.Industrial fire protection and safety engineers attempt to eliminatehazards at their source or to reduce theirintensity with protective systems. Hazard elimination may typically require the use of alternative and lesstoxic materials, changes in the process, spacing or guarding, improved ventilation or, spill control orinventory reduction measures, fire and explosion protective measures - both active and passive mechanisms,protective clothing, etc. The level or protection is dependent on the risk prevalent at the facility versus thecost to implement safety measures.Systems ApproachIn recent years, engineers have developed a systems approach (termed system safety engineering) toindustrial accident prevention. Because accidents arise from the interaction of workers and their workenvironments, both must be carehlly examined to reduce the risk of injury. Injury can result from poorfacility designs, working conditions, the use of improperly designed equipment and tools, fatigue,distraction,lack of skill, and risk taking. The systems approach examinesall areas in a systematicfashiontoensure all avenues of accident development have been identifiedand analyzed. Typically the followingmajorareas are examined: all work locationsto eliminateor control hazards, operating methods and practices, andthe training of employees and supervisors. The systems approach, moreover, demands a thoroughexaminationof all accidentsand near misses. Key facts about accidentsand injuries are recorded, along withthe history of the worker involved,to check for and eliminateany patterns that might lead to hazards.The systems approach also pays special attention to the capabilities and limitations of the workingpopulation. It recognizes large individual differences among people in their physical and physiologicalcapabilities. Thejob and the worker, therefore, shouldbe appropriatelymatched whenever possible.The safety and risk of a hydrocarbonfacility cannot be assessed solely on the basis of fire fighting systems orpast loss histories. The overall risk can only be assessed by defining loss scenariosand an understanding ofthe risk philosophyadopted by senior management.Due to the destructive nature of hydrocarbon forces when handled incorrectly, fire and explosion protectionprinciples should be the prime feature in the risk philosophy of any hydrocarbon facility. Vapor cloudexplosions in particular are consider the highest risk at a hydrocarbon facility. Disregarding the importanceof protection features or systems will eventually prove to be costly both in economic and human termsshould a catastrophicincident occur without adequate safeguards.Fire Protection Engineering RoleFire protection engineering is not a stand alone discipline that is brought in at an indiscriminate state of aproject design or even as an after the fact design review of a project. Fire protection principles should be anintegrated aspect of an oil or gas project that reaches into all aspects of how a facility is designed arrangedand constructed. They are usually the prime starting and focal points in the layout and processarrangements of hydrocarbon facility.Fire protection engineering should be integral with all members of the design team, be it structural, civil,electrical, process, HVAC, etc. Although a fire protection or risk engineer can be employed as part of aproject team or engineering staff, he should mainly be in an advisory role. He can advise on the mostprudent and practical methods to employ for fire protection objectives. The fire protection or risk engineermust therefore be knowledgeable in each of the various disciplines. In addition he must have expertise inhazard, safety, risk and fire protection principles and practices applied to the petroleum or other relatedindustries.
    • 6 Handbook of Fire and Explosion ProtectionRisk Management and InsuranceIt should also be realized that science of risk management also provides other avenues of protection besidestechnical solutions to a risk. There are four elements of risk management availableto resolve a concern.The four methods, in order of preferenceare:(1) Risk Avoidance(2) Risk Reduction(3) Risk Insurance(4) Risk AcceptanceThis handbook concentrates primarily on risk avoidancetechniquesand risk reduction. Risk acceptance andrisk insurance techniques are general monetary measures that are dependent on the financial optionsavailable to the Facility Manager. These are based on a companys policy and preferences in the insurancemarket. If used, they rely on financial measures within an organization to provide for financial security incase of an incident. Although these measures can accommodate financial losses, they are ineffective inreputation and prestige affects from an incident @e., negative effects). This is why risk avoidance and riskreduction measures are the preferred method of solution for a high risk problem with the petroleum andindustrialcommunity at large.Risk avoidance involveseliminatingthe cause of the hazard. This is accomplishedby changes in the inherentrisk features of the process or facility. Risk reduction concerns the provision of prevention or protectivemeasures that will lessen the consequencesof a particular accidental event.Risk insurance is the method chosen when the possible losses are financiallytoo great to retain internallybyrisk acceptance and in some cases too expensive to prevent or avoid. However even the risk insurers willwant to satisfy themselves that adequate precautions are being taken at facilities they are underwriting.Thus,they will look very carefully at risks they feel are above the industry norm or have high loss histories.Most offshore installations, international onshore production sharing contracts and large petro-chemicalplants are owned by several companies or participating national governments. The majority owner or mostexperiencecompanyis usually the onsite operator. The objective is to share the fbnding and financial risk offindingoil, developingand operatingthe facility. Shouldthe exploration hole prove "dry",i.e., commerciallyuneconomical, it prevents an undue economic impact to the exploration budget for a particular area.Investments in other exploration wells with other companies may prove fruitful thereby spreading the riskover a wider range of prospects. It also lessens the financial impact to the companies if a catastrophicincident occurs that destroys the facility, since each company must also share in the damage costproportionately to their investment stake. If a company historically has a poor record in relation to safeoperations, other companies may be hesitant to invest fbnds with it, since they may consider that companytoo high a risk. Alternativelythey may demand to be the operator since they would feel better qualified andthe risk of losingthe facility would be lower.Property damages and legal liabilities are not the only sources of financial impacts a company may suffer atthe time of an incident. Business interruption losses will also occur since the facility will not longer be ableto function as intended. Analysis of insurance industry claims data shows that business interruption lossesare generallythree times the amount of physical property damage. Often the justification for a safety featuremay not be the loss of the componentitselfbut of the impact to operations and loss revenueit produces.
    • Introduction 7Most of the major oil companies were originally started as a drilling organization for the exploration of oil.Drilling personnel have traditionally been idolized by company management as the individuals who havesupplied the real resources or profit to the company by successfully drilling and "finding" the oil or gas.Since the early days of oil, exploration activities were considered somewhat reckless and hazardous,especially due to wildcat drilling operations. This impression or the "inheritance" of drilling personnel hasalways been one of wild, aloof or above safety features or requirements. Due to the dramatic effects ofoccasional drilling blowout incidents, this impressionis still difficult to eradicate. This conceptionalso existswithin the general public. In some organizationswhere these drillingpersonnel are idolized, they will usuallyor may eventuallybe promoted to senior management positions. Their independent attitude may still prevailor impressions by subordinate employees will be preconceived to a lack of safety concern due to theirbackground. This is not to say other departmentsor individualjob classificationswithin an organizationmaynot bejust as ill perceived (e.g., constructionor project management).There are and probably will always be requirements to achieve oil and gas production or refining for anygiven project as soon as possible. Therefore the demands on drilling, construction and project managementto achieve a producing or refining facility as soon as possible may be in some casesbe in direct conflict withprudent safety measures, especiallyif they have not been adequatelyplanned or provided before the start ofthe project. Operationsmanagement should not be mistakenly led into believing a facility is ready to operatejust because it is "felt"by those performing its construction that it is complete.However unfortunate, drilling personnel have been historically directly connected with major incidentswithin the petroleum industry on numerous occasions and the impression, consciously or unconsciously stillremains. On the other hand, it is very rare or non-existent that a loss prevention professional is promoted tothe ranks of seniormanagement, even though they may have been keenly conscientiousin maintaining a higheconomic return to the companyby the prevention of catastrophic accidents.Safety achievement is a team approach.Without team cohesiveness, commitment and accountability objectives will not be met.important is the leadership of a team, which in business operationsis the senior management.All parties to the operation must participate and contribute.SpecificallySenior management responsibility and accountability are the keys to providing effective fire and explosionsafety measures at any facility or operation. The real attitude of management towards safety will bedemonstrated in the amount of importance placed on achieving qualitative or quantifiable safety results.Providing a permissive attitude of leaving safety requirements to subordinates or to the Loss Preventionpersonnel will not be conductive or lead to good results. The effect of indifference or lack of concern tosafety measures is always reflected top down in any organizational structure. Executive management mustexpress and contribute to an effective safety program in order for satisfactory results to be achieved. Allan ultimate goal of any organization. Where a safety culture is "nurtured1,continual economic benefits areusually derived. On the other hand, it has been stated that the 150 largest petroleum and chemical industryincidentsduring the past 30 years have involved breakdownsin the managementof process safety.asckknts s h l d 5ethght o-€as prevesabk. Acc*nt preventio-rla d ek&x?ith s h ! d bc em*red as
    • 8 Handbook of Fire and Explosion Protection1.2.3.4.5.6.7.8.BibliographyEllis,W. D., On The Oil Lands, R. R. Donnelly & Sons,Willard, OH, 1983.Giddens, P. H., Earlv Days of Oil, A Pictorial Histow of the Beginnings ofthe Industry in Pennsylvania, PrincetonUniversity Press, Princeton, NJ, 1948.Head, George L, and Stephen Horn 11,Essentialsof the Risk Management Process,Vols. I & 11, Insurance Instituteof America, Malvern, PA, 1985.Knowles, R. S., TheFirst PictorialHistorv of the American Oil and Gas Industry 1859-1983,OhioUniversityPress,Athens, OH, 1983.MacDonald, D., CoruorateRisk Control,John Wiley and Sons,Co. New York, NY, 1990.Rundell Jr., W., Earlv Texas Oil. A Photoa-aDhic Historv. 1866-1936, Texas A & M University Press, CollegeStation,TX, 1977.Sedgwick Energy, Limited, An Introductionto Energy Insurance, SedgwickEnergy, Ltd.,London, U.K., 1994SpragueDe Camp, L., The Ancient Engineers, Dorset Press,New York, NY, 1963.9. Swiss Reinsurance Company (Swiss Re), Petrochemical Risks: A Burning Issue, Swiss Re, Zurich, Switzerland,1992.
    • Chapter 2Overview of Oil and Gas FacilitiesPetroleum and gas deposits occur naturally throughout the world in every continent and ocean. Most of thedeposits are several thousand meters deep. The petroleum industrys mission is to find, develop, refine, andmarket these resources in a fashion that achieves the highest economic return to the owners or investorswhile adequatelyprotecting the fixed investmentin the operation.Oil and gas operations today are almost universally constitute a continuous run operation versus a batchprocess. Once fluids and gases are found and developed they are transported from one process to anotherwithout delay or interruption. This providesimproved economics, but also increases the fuel inventories andthereby inherent risk in the operation.The main facets of the oil and gas industry are exploration, production, refining, transportation andmarketing. A brief description of each of these sectors is provided in this chapter. Although somepetroleum companies are fully integrated with each of these operations others are segmented and onlyoperate in their particulararea of expertiseor highest financial return.ExplorationExploring for oil and gas reservoirs consist mainly of geophysical testing anddrilling !wildcat" wells. To find crude oil or gas reserves underground, geologistssearch for a sedimentary basin in which shales rich in organic material have beenburied for a sufficiently long time for petroleum to.have formed. The petroleummust also have had an opportunity to migrate into porous traps that are capable ofholdinga large amount of fluid or gas. The occurrence of crude oil or gas is limitedboth by these conditions, which must be met simultaneously, and by the time spanof tens of millions to a hundred million years. Surface mapping of outcrops ofsedimentary beds makes possible the interpretation of subsurface features, whchcan then be supplemented with information obtained by drilling into the crust andretrieving cores or samplesof the rock layers encountered.Seismictechniques, the reflection and refraction of sound or shock waves propagated through the earth, arealso used to reveal details of the structure and interrelationship of various layers in the subsurface. Theshock or sound waves record densities in the earths surface that may indicate an oil or gas reservoir.Explosive charges or vibration devices are used to impart the required shockwave.Ultimately the only way to prove that oil is present underground is to drill an exploratorywell. Most of the9
    • 10 Handbook of Fire and Explosion Protectionoil provinces in the world have initially been identified by the presence of surface seeps, and most of theactual reservoirs have been discovered by so-called wildcatters who relied perhaps as much on intuition ason science. The term wildcatter comes from West Texas, USA, where in the early 1920s, drilling crewscame across many wildcats as they cleared locations for exploratory wells. The hunted wildcats were hungon the oil derricks, and the wells became known as wildcat wells. A wildcat well is considered essentiallyatest boring to verify the existence and "commercial" quantities of quality oil or gas deposits. Since theabsolute characteristicsof a wildcat well are unknown, a high pressure volatile hydrocarbon reservoir maybe easily encountered. As drilling occurs deeper into the earth the effects of overburden pressure of anyfluid in the wellbore increases. If these reservoirs are not adequatelycontrol during exploratorydrilling,theycan lead to an uncontrolledrelease of hydrocarbonsthrough the drilling system. This is commonly termed a"blowout",whether it is ignited or not. Blowout preventers, BOPS(i.e., hydraulic shear rams) are providedto control and prevent a blowout event. Uncontrolled drillinghydrostatic pressure is consideredthe primarycause of drilling blowouts(while evidentlythe underlyingcause is human error).An oil field may comprise more than one reservoir, i.e., more than one single, continuous, boundedaccumulation of oil. Indeed, severalreservoirsmay exist at various increasing depths, stacked one abovetheother, isolated by intervening shales and imperviousrock strata. Such reservoirsmay vary in size from a fewtens of hectares to tens of square kilometers. Their layers may be from a few meters in thickness to severalhundred or more. Most of the oil that has been discovered and exploited in the world has been found in arelatively few large reservoirs. In the USA, for example, 60 of the approximately 10,000 oil fields haveaccounted for half of the productivecapacity and reserves in the country.ProductionUnderground oil or gas deposits are produced through wells that are drilled to penetrate the oil bearing rockformations. Most oil wells in the world are drilled by the rotary method. In rotary drilling, the drill "string",which is a series of connected pipes, is supported by a derrick (a structural support tower). The string isrotated by being coupled to a rotating "table" on the derrick floor. The drillingdevice or "bit" at the end ofthe string, is generally designed with three cone-shaped wheels tipped with hardened teeth. Additionallengths of drill pipe are added to the drill string as the bit penetrates deeper into the earths crust. The forcerequired for cutting into the earth comes from the weight of the drill pipe itself. Drill cuttings or theformation rock is continually lifted to the surface by a circulating fluid ("mud") system driven by a pump.The drilling mud is constantlycirculated down through the drill pipe, out through nozzles in the drill bit, andthen up to the surface through the space between the drill pipe and the bore through the earth (the diameterof the bit is somewhat greater than that of the pipes). By varying the force and momentum on the drill bit,the bore can be angled into or penetrate horizontallyinto a reservoir.Once the well is drilled, the oil is either released under natural pressure orpumped out. Normally crude oil is under pressure; (were it not trapped byimpermeable rock it would have continued to migrate upward), because ofthe pressure differentialcaused by its buoyancy When a well bore is drilledinto a pressured accumulation of oil, the oil expands into the low-pressuresink created by the well bore in communicationwith the earths surface Asthe well fills up with fluid, a back pressure is exerted on the reservoir, andthe flow of additionalfluid into the well bore would soon stop, were no otherconditionsinvolved Most crude oils, however, contain a significant amountof natural gas in solution, and this gas is kept in solutionby the high pressurein the reservoir The gas comes out of solutionwhen the low pressure in thewell bore is encountered and the gas, once liberated, immediately begins to expand. This expansion,together with the dilution of the column of oil by the less dense gas, results in the propulsion of oil up to theearths surface As fluid withdrawal continuesfrom the reservoir, the pressure within the reservoir graduallydecreases, and the amount of gas in solution decreases As a result, the flow rate of fluid into the well boredecreases, and less gas is liberated The fluid may not reach the surface, so that a pump (artificial liR) must
    • Overview of Oil and Gas Facilities 11be installed in the well bore to continue producing the crude oil. Gas reservoirs by their nature are high inpressure and can be essentiallytapped into to obtain the deposit.The produced oil or gas is connected to surface flowlines from the wellhead pumping unit or surfaceregulating valve assembly typically referred to as a Christmas tree but to its arrangement. The flowlinescollect the oil or gas to local tank batteries or central production facilities for primary oil, water, and gasseparation. The reliability of electrical submersible pumps (ESPs) has increased to the point where thesubmersibleelectrical pump is commonly used for the production of liquid hydrocarbonswhere artificialliRis required for production.Primary separation facilities process the produced fluids and gases into individual streams of gas, oil andwater. These facilitiesare commonly referred to as Gas Oil SeparationPlants (GOSPs), Central ProcessingFacilities (CPF) or if located offshore on drilling, production and quarters platforms (PDQs). The offshoreplatforni may either float on the sea or be supported on steel or concrete supports secured to the oceanfloor, where it is capable of resisting waves, wind, and in Arctic regionsice flows. In some instancessurplusoil tankers have been converted into offshoreproduction and storage facilities.The produced fluids and gases are typically directed into separationvessels. Under the influence of gravity,pressure, heat, retention times, and sometimes electrical fields, separation of the various phases of gas, oil,and water occurs so that they can be drawn off in separate streams. Suspended solids such as sediment andsalt will also be removed. Deadly hydrogen sulfide(HzS), is sometimesalso encountered,which is extractedsimultaneouslywith the petroleum production. Crude oil containing H2S can be shipped by pipeline andused as a refinery feed but it is undesirable for tanker or long pipeline transport. The normal commercialconcentrationof impurities in crude oil sales is usually less than 0.5% BS & W (Basic Sediment and Water)and 10 Ptb (Pounds of salt per 1,000barrels of oil). The produced liquids and gases are then transported toa gas plant or refinery by truck, railroad tank car, ship, or pipeline. Large oil field areas normally have directoutlets to major, common-carrierpipelines.Enhanced Oil Recovery (EOR)Most petroleum reservoirs are developed by numerous production wells. As the primary productionapproaches its economic limit, perhaps approximately 25 percent of the crude oil in place from a particularreservoir has been withdrawn. The petroleum industry has developed unique schemesfor supplementingtheproduction of gaseous and liquid hydrocarbons that can be obtained, by taking advantage of the naturalreservoir energy and geometry of the underground structures. These supplementary schemes, collectivelyknown as enhanced oil recovery (EOR) technology, can increase the recovery of crude oil, but only at theadditional cost of supplying extraneous energy to the reservoir. In this way, the recovery of crude oil hasbeen increased to an overall approximateaverage of 33 percent of the original "in the ground" oil. As theindustry matures and reservoirs are considered depleted, EOR techniqueswill become the prevalent methodof production for most of the petroleum reservoirsand the overall recoveryrates will increases.Secondary RecoveryWater InjectionIn a completely developed oil or gas field, the wells may be drilled anywhere from 60 to 600 m (200to 2,000 ft) horizontally from one another, depending on the nature of the reservoir. If water ispumped into alternate wells in such a field, the pressure in the reservoir as a whole can be maintainedor even increased. In this way the daily production rate of the crude oil also can be increased. Inaddition, the water physically displaces the oil, thus increasing the recovery efficiency. In somereservoirs with a high degree of uniformity and little clay content, water flooding may increase therecoveryefficiencyto as much as 60 percent or more of the original oil in place. Water flooding wasfirst introduced in the Pennsylvaniaoil fields, somewhat accidentally,in the late 19thcentury, and hassincebeen used throughout the world.
    • 12 Handbook of Fire and Explosion ProtectionSteam InjectionSteam injection is used in reservoirsthat contain very viscous oils, i.e., those that are thick and flowslowly. The steam not only provides a source of energy to displace the oil, it also causes a markedreduction in viscosity (by raising the temperature of the reservoir), so that the crude oil flows fasterunder any given pressure differential.Gas InjectionSome oil and gas reservoirs contain large volumes of produced natural gas or carbon dioxide (C02).This gas is produced simultaneously with the liquid hydrocarbons. The natural gas or C02 isrecovered, recompressed, and reinjected into the gaseous portion of the reservoir. The reinjectednatural gas or C02 maintainsreservoir pressure and helps push additional liquid oil hydrocarbonsoutof liquid portion of the reservoir.Tertiary RecoveryAs the production lives of secondary methods lose their efficiency, fbrther techniqueshave been tested andfound to continueto release additional amounts of oil. These methods are considered tertiary methods andare generally associated with chemical or gaseous recirculation methods of recovery. Some instances of in-situ thermal recoveryhave been used but not on a large extent.Chemical InjectionProprietarymethods are developed which inject chemical detergent solutionsinto the oil reservoirstoincrease the viscosity of the remaining oil reservoirs. After the chemical detergent solutions areinjected, polymer thickened water is provided behind the chemical detergent to drive the oil towardsproducingwells.Thermal RecoveryUnderground hydrocarbonsare ignited, which creates a flame front or heat barrier that pushes the oiltowards the producingwell.Recirculated Gas DriveNatural gas or C02 is reinjected to mix with the underground oil, to free it from the reservoir rock.The gas is continually recirculated until it is economically nonproductive (i.e., the recovery rate ismarginal).Other experimental methods have been proven technologically feasible but are still commercially unviable.These includein-situ combustion, electromagneticcharging, and similarmethods.TransportationTransportation is the means by which onshore and offshore oil and gas production is carried to themanufacturing centers and from which refined products are carried to wholesale and retail distributioncenters.Petroleum commodities (gas and oil), are normally transported in pipelines from source points to collectionand processing facilities. Pipelines route unprocessed or refined products to centers of manufacturing andsales from areas of extraction, separation and refining. Where a pipeline system is unavailable, trucking is
    • Overview of Oil and Gas Facilities 13usually employed.Shipment from continent to continent is accomplished large tanker vessels, carriers or ships, which is themost economical method of shipment. These economies have produced the largest ships in the world,appropriately named Very Large Crude Carrier (VLCC), and Ultra Large Crude Carrier (ULCC) of sizerange between 160,000to 550,000 dwt. Refined products are typically shipped in vessels of up to 40,000dwt. Class rating. LNG or LPG vessels are typically in the range of up to 100,000cubic meter (838,700bbls.) capacity.In order to achieve a complete transportation system a host of other subsystems support the transportationsystem operations. Loading facilities, pumping and compressor stations, tank farms and metering andcontrol devices are necessary for a complete transportation system of liquid or gases hydrocarboncommodities.RefiningIn its natural state, crude oil has no practical uses except for burning as fuel after removal of the morevolatile gases that flow with it from the production well. It therefore is "taken apart" and sorted into itsprincipal components for greater economical return. This is accomplished in a refinery that separate thevarious fractionsinto fbel gases, liquefied petroleum gases, aviation and motor gasolines,jet fuels, kerosene,diesel oil, fkel oil and asphalt. Refinery operations can be generally divided into three basic chemicalprocesses: (1) Distillation, (2) Molecular structure alteration (Thermal Cracking, Reforming, CatalyticCracking, CatalyticReforming,Polymerization, Alkylation, etc.), and (3) Purification.There are numerous refining methods employed to extract the fractions of petroleum liquids and gases. Aparticular refinery process design is normally dependent on the raw feedstock characteristics(e.g., crude oiland produced gas natural specifications) and the market demands (e.g., aviation or automotive gasolines),which it intends to meet.Refining is superficially akin to cooking. Raw materials are prepared and processed according to aprescribed set of parameters such as time, temperature, pressure and ingredients. The following is summaryof the some of the basic processes that are used in refinery processes.Basic DistillationThe basic refining tool is the common distillationunit. It is usually the first process in refining crudeoils. Crude oil normally begins to vaporize at a temperature somewhat less than what is required toboil water. Hydrocarbons with the lowest molecular weight vaporize at the lowest temperatures,whereas successivelyhigher temperaturesare applied to separateor distill the larger molecules.The first material to be distilled from crude oil is the gasoline fraction, followed in turn by naphthaand then by kerosene. The residue in the batch vessel or "kettle", in the old still refineries, was thentreated with caustic and sulfuric acid, and finally steam distilled. Lubricants and distillate fuel oilswere obtained from the upper regionsand waxes and asphalt fiom the lower regionsof the distillationapparatus. In the later 19th century, gasoline and naphtha fractions were actually considered anuisance because little need for them existed. The demand for kerosene also began to declinebecause of the growing production of electricity and the wide spread use of electric lights. With the
    • 14 Handbook of Fire and Explosion Protectionintroduction of the automobile, however, the demand for gasoline suddenlyburgeoned, and the needfor greater suppliesof crude oil increased accordingly.Thermal CrackingIn an effort to increase the yield from distillation a thermal cracking process was developed. Inthermal cracking, the heavier portions of the crude oil are heated under pressure and at highertemperatures. This results in the large hydrocarbon molecules being split into smaller ones, so thatthe yield of gasoline from a barrel of crude oil is increased. The efficiency of the process is limitedbecause at the high temperatures and pressures that are use. Typically a large amount of coke isdeposited in the reactors. This in turn requires the use of still higher temperatures and pressures tocrack the crude oil. A coking process was then invented in which fluids were re-circulated; theprocess ran for a much longer time, with far less buildup of coke.Alkylation and Catalytic CrackingTwo additional basic processes, alkylation and catalytic cracking, were introduced in the 1930s andfurther increased the gasoline yield from a barrel of crude oil. In the alkylation process, smallmoleculesproduced by thermal cracking are recombinedin the presence of a catalyst. This producesbranched molecules in the gasoline boiling range that have superior properties (e.g., higherantiknock ratings as a fuel for high-powered internal combustion engines as those used in todayautomotiveengines).In the catalytic-cracking process, crude oil is cracked in the presence of a finely divided catalyst,typically platinum. This permits the refiner to produce many diverse hydrocarbonsthat can then berecombined by alkylation, isomerization, and catalytic reforming to produce high antiknock enginefuels and specialty chemicals. The production of these chemicals has given birth to the ChemicalProcess Industry (CPI). This CPI industry manufactures alcohols, detergents, synthetic rubber,glycerin, fertilizers, sulfir, solvents, and the feedstocks for the manufacture of drugs, nylon, plastics,paints, polyesters, food additives and supplements, explosives, dyes, and insulating materials. Thepetrochemical industry uses about five percent of the total supplyof oil and gas in the U.S.PurificationPurification processes are used to remove impurities such as sulfurs, mercury, gums and waxes. Theprocesses includeabsorption and stripping, solvent extraction and thermal diffision.Typical Refinery Process FlowAt a refinery all crude oil normally first goes to crude distillation. The crude is run though pipinginside a furnace where high temperatures cause it to partially vaporize before it flows into afractionating tower. The vapors rise up through the tower, cooling and liquefying in a number of"bubble trays". The cooling and lique@ng action is assisted by a relatively cold stream of liquidnaptha being pumped into the top of the tower to flow downward from one bubble tray to another.The liquid on the different bubble trays condenses the heavier part of the vapors and evaporates itsown lighter components.Liberated gasses are drawn off at the top of the tower with the naptha. The gas is recovered tomanufacture refrigerated liquefied petroleum gas (LPG). The naptha is condensed at a temperatureof about 52 OC (125 OF). Part of the condensed naptha is normally returned to the top of the tower.The naptha product stream is split into light naptha for gasoline blending and heavy naptha for furtherreforming. Inside the tower, kerosene is withdrawn at a temperature of about 149 OC (300 OF).Diesel is withdrawn at a temperature of 260 OC (500 OF). These middle distillates are usuallybrought up to specification with respect to sulfur content with hydrodesulfurization. The heavy oil
    • Overview of Oil and Gas Facilities 15from the bottom of the crude unit can be used in fuel oil blending or can be processed hrther invacuum distillation towers to recover a light distillate used in blending white and black diesel oils.The low pressure in the vacuum tower enables the recovery of additional distillate with the danger ofaffectingfuel oil qualityby subjectingit to excessivetemperatures.After products are produced by refining they are hrther enhanced in a blending unit. In this unit thefinished products are made by mixing the components in blending tanks. To gasoline for example,coloring dyes or special additivesmaybe added. The completed blends are tested and then routed totank farmstorage or shipment.Production PercentagesThe demand for lighter distillationproducts for gasolineandjet engineshas also increased the relativehazard levels of refinery facility processes over the years. A comparisonof product yields from 1920to today showsthe dramaticincreasesin light product production percentages.Product 1920s Today YOChangeGasoline 11 21 +90 %Kerosene 5.3 5 -6 %Gas Oils 20.4 13 -36 %Heavy Oils 5.3 3 -6 %By producing higher quantitiesof "lighter"hels, the plants themselves have become higher risks justby the nature of the produced percentages than in previous years. The corresponding expansion ofthese facilitiesthrough the decades has also combinedwith more explosive products to heighten riskslevelsunless adequate protective measures are provided.MarketingBulk Plants, Distribution and Marketing Terminals store and distributethe finished products from therefineries and gas plants. Typically these facilities handle gasoline, diesel, jet fuels, asphalts, andcompressed propane or butane.The facilities consist of storage tanks or vessels, loading racks (or unloading) by ship, rail or truck,metering devices, and pumping or compression systems. Their capacities are relatively smallercompared to refinery storage and are normally dictated by local commercial demands in the bulkstorage location.
    • 16 Handbook of Fire and Explosion ProtectionBibliography1. Anderson, R. O., Fundamentals of the Petroleum Industry,Universityof Oklahoma Press,Norman,OK, 19842. Baker, R., A Primer of Oilwell Drilling, Fifth Edition, Petroleum Extension Service, Universityof Texas at Austin,Austin, TX, 1994.3. Kruse, C. F., A Primer of Offshore Operations, Second Edition, Petroleum Extension Service, Universityof Texasat Austin, Austin, TX, 1985.4. Petroleum ExtensionService,A Dictionq for the Petroleum Industry, Divisionof ContinuingEducation,PetroleumExtensionService, University of Texas at Austin,Austin, TX, 1991.5. Petroleum Extension Service, Fundamentals of Petroleum, Third Edition, Petroleum Extension Service, Universityof Texas at Austin,Austin, TX, 1986.6. Petroleum Extension Service, A Primer of Oilwell Service and Workover, Third Edition, Petroleum ExtensionService, University of Texas at Austin, Austin, TX, 1979.7. Shell International Petroleum Company, Ltd., The Petroleum Handbook, Elsevier Science Publishing Co., Inc.,Amsterdam, The Netherlands, 1983.
    • Chapter 3Philosophy of Protection PrincipalsThe risk management techniques of the organization should be defined before any consideration of thephilosophy of protection needs for a facility are identified. An organization that is capable of obtaining ahigh level insurance coverage at very low expense, even though they may have high risks, may opt to have alimited outlay for protection measures since it is not cost effective. In reality this would probably neveroccur, but servesto demonstrate influencesin a corporate approach to protection levels and risk acceptance.All insurance companies provide property risk engineers or inspectors to evaluate their insurance risks forhigh value properties or operations. So in reality, a standard level of protection is maintainedin the industry.All the major oil companies have high levels of self insurance and usually high deductibles. Their insurancecoverages are also obtained in several financial layers from different agencies with considerable options,amendments and exclusions. So hopehlly no individualinsurer should be in a financial peril from a singlemajor incident.A general application of loss prevention practices is considered prudent both by insurers and petroleumcompanies, so overall, all facilities are required to achieve the corporate protection standards. In fact thepremium of insurance is normally based on the level of risk for the facility after an insurance engineer has"surveyed"the facility. Isolated cases may appear where less fixed protection systems are provided in placeof manual fire fighting capabilities, however the general level of overall loss prevention level or risk ismaintained. Insurers will also always make recommendationsfor loss prevention improvementswhere theyfeel the protection levels are substandard and the risk high. Where they feel the risk is too high, they mayrefuse to underwrite certain layers of insurance or charge substantial additional premiums for reinsurancerequirements.The protection of petroleum facilities follows the same overall philosophy that would be applied to anybuilding or installation. These basic requirements are personnel evacuation, containment, isolation, andsuppression. Sincethese are design features that cannot be immediatelybrought in at the time of an incidentthey must be adequately provided as part of the original facility design. What constitutes adequate is thedefinitionfire, risk and loss protection professionals must provide.17
    • 18 Handbook of Fire and Explosion ProtectionGeneral PhilosophyIn general the fire and explosion protection engineering design philosophy for oil, gas and related facilitiescan be defined by the followingobjectives (listed in order of decreasingimportance):(1) Prevent the immediate exposure of individuals to fire and explosion hazards.No facility should be designed such that an employee or the public could be immediately harmed ifthey were to be exposed to the operation.(2) Provide inherently safe facilities.Inherently design safety features at facilities .provides for adequate spacing, arrangement andsegregation of equipment from high hazard to low hazard. The least hazardous process systemsshould be used for obtaining the desired product or production objectives. Protective systems areprovided to minimized the effectsthat may occur from a catastrophicincident.(3) Meet the prescriptive and objective requirements of governmental laws and regulations.All international, national and local laws or regulations are to be complied with, in both prescriptiverequirementsand underlying objectives. Laws are provided to achieve the minimum safeguardsthatare required by a society to exist without excessive turmoil. Industry must abide by these laws inorder to have a cohesiveoperationwithout fear of legal mandates.(4) Achieve a level of fire and explosion risk that is acceptable to the employees, the general public,the petroleum and related industries, the local and national government, and the company itself.Although a facility could conceivablybe designed that would comply with all laws and regulations, ifthe perceptionexiststhat the facilityis unsafe, it must be altered to provide for a facility is technicallyjudged safe by both recognized experts, the industry and the general public.(5) Protect the economic interest of the company for both short and long range impacts.The prime objective of a business is provide a positive economicreturn to the owners. Therefore theeconomic interest ofthe owners should be protected for long and short range survival without fear ofa potential loss of earnings.(6) Comply with a corporations policies, standards and guidelines.A companys policy and guidelines are promulgated to provide guidance in the conduction of thespecificbusiness in an efficient and cost effectivemanner.(7) Consider the interest of business partners.Where a consortium may exist, the economic interest of the partners must be considered and theirmanagement must approve of the risk involved in the venture. Where such risks are consideredunacceptable by the partners their interest must be protected to their satisfaction.(8) Achieve a cost effective and practical approach.The safety and protection of a facility does not need to involve expensive and elaborate systems. Allthat is desired is a simplistic, practical and economic solution to achieve a level of safety that isacceptableto interestedparties.
    • Philosophy of Protection Principals 19(9) Minimize space (and weight if offshore) implications.The most expensive initial investment of any capital project is the investment in space to provide afacility. For onshore on offshorefacilitiesthe amount a space a facilityoccupies directly correspondsto increased capital costs, however these should still be balanced with the need for adequateseparation,segregationand arrangement protection principles.(10) Respond to operational needs and desires.To provide effective process safety features they should be effective operational features. Providingsafeguards that are counterproductive to safety may cause the exact opposite to occur, sinceoperations may ovemde the safeguard for ease of operationalconvenience.(11) Protect the reputation of the company.Public perception of a company lowers if it is involved in major incident that has involvedconsiderable fatalities or does major harm to the environment. Although these incidents can beeconomicallyrecovered from, the stigma of the incident may linger and affect the sale of companyproducts for emotional issues.(12) Eliminate or prevent the deliberate opportunities for employee or public induced damages.Negative employee moral may manifest itself in an aspect of direct damage to company equipment asretribution. These effects may be disguised as accidental events in order to avoid persecutionby theindividualsinvolved. Other incidents may be perpetrated by outright terrorist activities. Incidentaleffects may develop into catastrophic incidents unbeknown even to the saboteur. The design offacilities should account for periods when management and labor relations may not be optimum andopportunities for vandalization could easily avail themselves. Where terrorist activity is ongoingsuitablepreventivemeasures must be instituted (i.e., increased securitymeasures, barricades, etc.).Worst Case ConditionsNormal loss prevention practices are to design protection measures for the worst case fire event that canoccur at the facility. To interpret this literally would mean that an oil or gas facility is completely on fire ortotally destroyed by an explosion. Practical, economical and historical review considerations indicate thisrational should be redefined to the Worst Case Credible Event (WCCE) or the as referenced in the insuranceindustry, the ProbableMaximumLoss (PML),that could occur at the facility.Much discussion could be presented as the most credible event at the facility. Obviously a multitude ofunbelievable events can be postulated (industrial sabotage, insane employees, plane crash impacts, etc.).Only the most realistic and highly probable events should be considered. In most cases historical evidenceof similar facilities is used as a reference for the worst case credible events. Alternatively the effect of themost probable high inventory hydrocarbon release could be postulated. The worst case event should beagreed upon with loss prevention, operational and senior executive management for the facility. The worstcase credible event will normally define the highest hazard location(s) of the facility. From these hazards,suitableprotection arrangementscan be postulated to prevent or mitigate their effects.
    • 20 Handbook of Fire and Explosion ProtectionSeveral additionalfactors are importantwhen consideringthe worst case credible event.Ambient ConditionsWeather - winds, snow, sandstorms, extremely high or low ambient temperatures, etc.Weather conditions can impede the progress of any activity and interrupt utility services ifthese become damaged.Time of Day - personnel availability, visibility, etc., plays a key role in the activities ofpersonnel during an incident. Periods of off-dutytime for offshoreor remote installations, shiftchanges and nighttime allow high density of personnel to develop on some occasions that canbe vulnerableto a high fatalityrisk. Poor visibilityalso affects transportationoperations.Independent Layers of Protection (ILP)Most facilities are designed around layers of protection commonly referred to as Independent Layers ofProtection (ILP). A protection layer or combination of combination of protection layers qualifies as a ILPwhen one of the followingconditionsare met: (1) the protection provided reduces the risk of a serious eventby 100 times, (2) the protective hnction is provided with a high degree of availability (i.e., greater than0.99)or (3) it has the followingcharacteristics- specificity,independence, dependability,and auditability.Most petroleum and chemical facilities rely on inherent safety and control features of the process, inherentdesign arrangementsof the facility, and process safety ESD features as the prime loss prevention measures.These features are immediately utilized at the time of an incident. Passive and active explosion and fireprotection measures are applicable after the initiating event has occurred and an adverse affect to theoperation has been realized. These features are used until their capabilityhas been exhausted or the incidenthas been controlled.
    • Philosophy of Protection Principals 21The most commonly encountered Independent Layers ofProtection (ILPs) are shown in Table 1:Table 1IndependentLevelsof Protection
    • 22 Handbook of Fire and Explosion ProtectionDesign PrinciplesTo achieve the project safety objectives and philosophy of protection through independent layers ofprotection, a project or organization should define specific guidelines or standards to implement in itsdesigns. Numerous industry standards are available (Le., API, NFPA, etc.) which give options, generalrecommendationsor specific criteria once a design preference is chosen. It is therefore imperative to havecompany specific direction in order to comply with company management directives for protection of thefacility.Typicallyencounteredfacility safety design principleswithin the petroleum industry are usually as follows:1. Immediate facility evacuation should be considered as a prime safeguard for all personnel from amajor incident. All onsite personnel should be hlly trained and where required certified for suchan eventuality(i.e., offshoreevacuationmechanisms).2. Process system emergency safety features (i.e. ESD, isolation, depressurizationand blowdown)should be considered the prime safeguardsfor loss prevention over fire protection measures (i.e.fireproofingor barriers, firewater systems, manual fire fighting).3. The facility design should meet the requirements of local national regulations and a companyspoliciespertainingto safety,health, and protection of the environment.4. Recognized international codes and standards applicable to petroleum facilities should be used(e.g., API, ASME, NACE, NFPA, etc.) in the design and in any proposed modifications.However it should be realized that compliance with applicable codes and standards is notsufficientin itselfto ensure a safe design is provide.5. Inherent safety practices should be used. Inherent safety practices implement the least riskoptions for conducting an operation and provide sufficient safety margins. General methodsusing inert or high flash point materials over highly volatile low flash point materials, use oflower pressuresinstead of higher pressures, smallervolumes instead of largevolumes, etc.In general these safe design characteristicscan be categorized as:a. Are intrinsically safe.b. Incorporate adequate design margins or safety factors.c. Have sufficient reliability.d. Have fail-safefeatures.e. Incorporate fault detection and alarms.f Provideprotection instrumentation.Some specificinherent safety practices used in the industry are mentioned below.(i.) Automatic ESD (shutdown and isolation) activation from confirmed process systeminstrumentation set points.(ii) Automaticde-inventoryingof high volume hydrocarbon processes (gasses and liquids) foremergencyconditionsto remote disposal systems.(iii.) Separation distances are maximized for high risks. Occupied facilities (e.g., control
    • Philosophy of Protection Principals 23rooms, accommodations, offices, etc.) should be located as far as practical from high riskprocesses. High volume volatile storage is highly spaced from other high risks. Safety factorsare included in calculated spacing distances determined by mathematical modeling ofexplosions and fire incidents. Spacingis implementedover passive protective barriers.(iv.) The amounts of flammableliquids and gases that may contribute to an incident should beminimized for normal operations and during emergency conditions (limited vessel sizes,isolation provisions, blowdown or depressurization,etc.). The maximum allowablelevels foroperational and emergency periods should be identified as part of the design process and riskanalysis.(v.)which are backed-up by human supervision.Automatic control (DCS-BPCS, PLC, etc.) for high risk processes should be used,(vi.) High integrity ESD systems containing fail-safe devices should be used where practical.Failure modes are selected for operating devices that isolate fuel supplies (i.e., fail close) anddepressure high volume gas supplies (i.e., fail open) upon disruption of utility services duringan incident.(vii.) A dual alarm level instrumentation (e.g., highhigh, low/low, etc.) should be used forcritical alarmsand controls.(viii.) The release of or exposure of flammablevapors or liquidsto the operating environmentshould be avoided (e.g., pressure relief to flare system or blowdown header, avoidance ofpump usage due to seal leaks, flanged or screwed fittings, mitigation of vibrational stress onpiping components,etc.).(ix.) Single point failure locations in the process flow should be eliminated for the primeproduction hydrocarbon processes and support systems (i.e., electrical power, heat transfer,coolingwater, etc.) that are criticalto.maintainthe production process.(x.) High performance corrosion protective measures or allowances should be instituted.Corrosion monitoring systems shouldbe used in all hydrocarboncontaining systems.(xi.) The facility should be designed with the maximum use of open space for free airventilation, especially for offshore installations. Enclosed spaces should be avoided whenpractical.(xii.) Ignition sources should be spaced as far as practical from hydrocarbon containingsystems (maximizeelectrical area classificationrequirements).(xiii.) Air supplies for ventilation for control rooms, prime movers, etc., should be located atthe least likely location for accumulation of flammable vapors or routes of dispersion (e.g.,generallyprovided at the lower levels of the facilityfor areas handling light vapors and higherlevels for facilities handling heavy vapors, where both occur a high level intake is prudentconsidering dispersion effects). Locations that do not need oxygen supplies or fresh air (i,e.,electrical switchgearenclosures), but require temperature control, should be recirculating.(xiv.)available.Two separate on site evacuation mechanisms should be provided and generally(xv.) The integrity of safety systems (ESDDepresurization, Fire DetectiodSuppression,AIarm and Evacuation means) should be maximized and preserved from accidental fire andexplosion events.
    • 24 Handbook of Fire and Explosion Protection(xvi.) Surface drainage and safe removal of spilled or accumulated liquids is adequatelyprovided.(xvii.) Liquid spills are immediately removed from the area through surface runoff, drains,area catch basins, sumps, sewers, dikes, curbing or remote impounding that does not exposeother facilitiesto the hazard.(xviii.) High flash point, noncombustible or inert liquids and gases are utilized wheneverpossible.(xix.) Gravity feed or low pressure systems should be used over high pressure systems (e.g.,fuel to prime movers, day tank supplies, etc.).(xx.) Common vulnerable leakage points are minimized, glass level gages, hose transfersystems,etc.(xxi.)Piping carrying hazardous materials is minimized where practical and where exposed, isafforded protection considered necessary.5. Operational personnel should be expected to suppress only very small incipient fires. All otheremergencies are to be handled with ESDhlowdown, isolation, fire protection systems (active orpassive) or exhaustion of fuel sourcesby the incident.6. Opportunitiesfor employeeinduced damages are minimized. All activities are made so that theyare direct actions and cannot be attributed to purely mechanical failures. For example, easilybroken liquid gage glasses are protected or reyoved, drains are capped, field ESD push buttonsare provided with tamper covers, work permt procedures are enforced, lock-out or tag-outmeasures are used, etc.7. The facility is secured and evacuated if weather or geological event predictions suggest severeconditionsmay be imminentat the location.8. The facility is designed with the use of the best available control technology (BACT), e.g.,PLCDCS, process management systems that are commensurate to the level of risk the facilityrepresents.9. The facility is subjected to a process hazard analysis commensurate to the level of hazard thefacility represents (ie., Checklist,PHA, HAZOP, What-If review, Event Tree, FMEA, etc.). Theresults of these analysesare fully understood and acknowledged by facilitymanagement. Wherehigh risk events are identified, quantifiable risk estimation and eects of mitigation measuresshouldbe evaluated and applied if productive.These are some of the numerous inherent design features that can be incorporated into the design of aprocess system depending on its nature. Not only should a process design achieve economic efficiencybutthe inherent safety of the process should be optimized simultaneouslyas well.
    • Philosophy of Protection Principals 25Accountability and AuditabilityAn organizationshould have a well though out protection design philosophythat is understood and accepted by management. The safety designphilosophies should be reflected in the engineering design standards orguidelines used by the organization. The standards or guidelines form thebasis from which the safety of the facility can be audited against.Organizations that do not provide such information, do not have anyaccountability standards to meet or achieve, and therefore he safety of thefacility will suffer accordingly. Additionally the objectives of designstandards and guidelines can be more fully understood if a philosophy ofdesign is documented.The argument cannot be made that standards or guidelines restrict creativity innovation or are undulyexpensive. Waivers or exceptions to the requirements can always be allowed. This is provided they areadequately supported by a justification that demonstrates equivalency or superiority in meeting therequirementsor safety objective. In this fashion standards or guidelinescan be also improved to account forsuch acceptable changes. Although not easily calculated a firm set of requirements prevents "re-inventingthe wheel" each time a facility is designed. This will also hopefully prevent mistakes made in the past fromreoccurring. Thus they establish a long term saving to the organization. Additionallyreference to industrystandards, e.g., ASME, M I , NFPA, etc., will not specify the actual protection measuresto be provided at afacility. In most cases they only defined the design parameters. A project or facility requires the "LocalJurisdiction" to determine protection requirements, which is usually the company itself. The industry codesonly provide detailed design guidancethat can be used once a particularprotection philosophyis specified.Engineering designs for new process facilities or changes should be circulated for review as dictated by thelevel of risk the facility represents to personnel competent to evaluate the risk. These reviews should fullyidentifjr the risks (both consequences and probabilities) and address measures to prevent or mitigate theireffects.
    • 261.2.3.4.5.6.7.8.9.10.11.12.Handbook of Fire and Explosion ProtectionBibliographyAmerican Petroleum Institute (API), RP 75. Recommended Practices for Develoument of a Safety andEnvironmental Management Promam for Outer Continental Shelf (OCS) Ouerations and Facilities, API,Washington, D.C., 1993.AmericanPetroleumInstitute(API),RP 750, Managementof Process Hazards,API, Washington,D.C., 1990.Armistead Jr., G., Safetvin PetroleumRefining and Related Industries,SecondEdition, J. G. Simmonds& Co., Inc.,New York,NY, 1959.Center for Chemical Process Safety (CCPS), Guidelines for Enpineering Design for Process Safety, AIChE, NewYork, NY, 1993.Environmental Protection Agency (EPA), U.S. Regulation 40 CFR Part 68, “Proposed Rule, Risk ManagementPrograms for ChemicalAccidentalRelease Prevention”,EPA,Washington, D.C.,October20, 1993.Health and Safety Executive (HSE), A Guide to the Control of Industrial Maior Accident Hazards Regulations,CIMAH,HMSO, London, U.K., 1985.Health and Safety Executive(HSE), A Guide to the OffshoreInstallations(SafetvCase) Regulations 1992, HMSO,London,U.K., 1992.Labour Inspectorate, U.D.C. 66.013/614.8.002, ProcessingPlants Checklist, Areas of Attention for a Safe Design,SecondEdition, Dutch Director Generalof Labor, Voorburg, The Netherlands, 1989.Lees, F. P., Loss Preventionthe Process Industries, Gulf Publishing,Houston, TX, 1980.Norwegian Petroleum Directorate (NPD), Guidelines for Safetv Evaluation of Platform Conceutual Design, NPD,Oslo,Norway, 1981.Occupational Safety and Health Administration (OSHA), U.S. Regulation 29 CFR 1910.119, “Process SafetyManagement of Highly Hazardous Chemicals; Explosives and Blasting Agents”, Department of Labor, OSHA,Washington,D.C.May 26, 1992.Russia (U.S.S.R.) GOST 12.1.010-76. Occupational Safety Standards Svstem. Explosion Safetv. GeneralReauirements,State StandardsCommitteeof the USSR, Moscow,U.S.S.R., 1984.
    • Chapter 4Physical Properties of HydrocarbonsPetroleum, or crude oil, is a naturally occurring oily, bituminous liquid composed of various organicchemicals. It is found in large quantitiesbelow the surface of the earth and is used as a fuel and as a rawmaterial in the chemical industry. Modern industrial societiesuse it primarily to achieve a degree of mobilityas a fuel for internal combustion and jet engines. In addition, petroleum and its derivatives are used in themanufacture of medicines, fertilizers, foodstuffs, plastic ware, building materials, paints, and cloth and togenerate electricity. Gas supplies are becoming increasing more important as the reserves of liquidhydrocarbonsare being depleted and the relatively clean burning gases are more acceptableenvironmentally.Petroleum is formed under the earths surfaceby the decompositionof organic material. The remains of tinyorganisms that lived in the sea and, to a lesser extent, those of land organisms were carried down to the seain rivers along with plants that grow on the ocean bottoms combined with the fine sandsand silts in calm seabasins. These deposits, which are rich in organic materials, become the source rocks for the formation ofcarbon and hydrogen, i.e.,natural gas and crude oil.This process began many millionsof years ago with the development of abundant life, and it continuesto thisday. The sedimentsgrow thicker and sink into the sea floor under their own weight. As additional depositspile up, the pressure on the ones below increases several thousand times, and the temperature rises byseveral hundred degrees. The mud and sand harden into shale and sandstone. Carbonate precipitates andskeletal shells harden into limestone. The remains of the dead organisms are then transformed into crude oiland natural gas. Usually the underground and formation pressure is sufficient for the natural release ofhydrocarbon liquidsand gases to the surfaceof the earth.GeneralThe range and complexity of naturally occurring petroleum is extremely large, and the variation incompositionfrom one reservoir to another is shows quite a range. Crude oil is graded by a specificviscosityrange indicated as degrees API. Higher degrees being lighter and lower degrees being heavier. All crudeoils differ in the fiactions of the various hydrocarbons they contain. The specific molecules vary in shapeand size from C1 to Cso or more. At the simplest, the one carbon compound has four hydrocarbon atomsbonded to the carbon atom to produce a the compound CH4, or methane gas. Liquid hydrocarbons fromnatural wells may have nitrogen, oxygen, and sulfurin quantitiesfrom trace amountsto significant,as well astraces of metals.Natural petroleum is distilled and reformulated to produce a variety of fbels for general use and as raw27
    • 28 Handbook of Fire and Explosion Protectionfeedstock materials for other industries.Three broad classes of crude petroleum exist: the paraffin types, the asphaltic types, and the mixed-basetypes. The paraffin types are composed of moleculesin which the number of hydrogen atoms is always twomore than twice the number of carbon atoms. The characteristic molecules in the asphaltic types arenaphthenes, composed of twice as many hydrogen atoms as carbon atoms. In the mixed-basegroup are bothparaffin hydrocarbons and naphthenes.The saturated open-chain hydrocarbons form a homologous series called the paraffin series or the alkaneseries. The compositionof each of the members of the seriescorresponds to the formula CnH2n + 2, wheren is the number of carbon atoms in the molecule. All the members of the seriesare unreactive. They do notreact readilyat ordinary temperatureswith such reagents as acids, alkalies,or oxidizers.The first four carbon molecules, C1 to C4, with the additionof hydrogen, form hydrocarbongases: methane,ethane, propane, and butane. Larger molecules C5 to C7, cover the range of light gasoline liquids; c 8 toC11 are napthas; C12 to C19, kerosene and gas oil; C20 to C27 lubricating oils; and above C2s heavy fuels,waxes, asphalts, bitumenes and materials as hard as stone at normal temperatures. Accompanying the gascompoundsmay be various amounts of nitrogen, carbon dioxide, hydrogen sulfide, and occasionallyhelium.Alkene SeriesThe unsaturated open-chain hydrocarbonsinclude the alkene or olefin series, the diene series, and thealkyne series. The alkene series is made up of chain hydrocarbons in which a double bond existsbetween two carbon atoms. The general formula for the series is CnHzn, where n is the number ofcarbon atoms. As in the paraffin series, the lower members are gases, intermediate compounds areliquids, and the higher members of the series are solids. The alkene series compounds are moreactive chemicallythan the saturated compounds. They react easily with substancessuch as halogensby adding atoms at the doublebonds.They are not found to any extent in natural products, but are produced in the destructive distillationof complex natural substances, such as coal, and are formed in large amounts in petroleum refining,particularly in the cracking process. The first member of the series is ethylene, C2H4. The dienescontain two double bonds between pairs of carbon atoms in the molecule. They are related to thecomplex hydrocarbonsin natural rubber and are important in the manufactureof synthetic rubber andplastics. The most importantmembersof this seriesare butadiene, C4H6 and isoprene, C5Hg.Alkyne SeriesThe members of the alkyne series contain a triple bond between two carbon atoms in the molecule.They are very active chemicallyand are not found free in nature. They form a series analogousto thealkene series. The first and most importantmember of the seriesis acetylene, C2H2.CyclicHydrocarbonsThe simplest of the saturated cyclic hydrocarbons, or cycloalkanes, is cyclopropane, C3H6, themolecules of which are made up of three carbon atoms to each of which two hydrogen atoms areattached. Cyclopropane is somewhat more reactive than the corresponding open-chain alkane,propane, C3H8. Other cycloalkanesmake up a part of ordinary gasoline.Several unsaturated cyclic hydrocarbons, having the general formula C10H16, occur in certainfragrant natural oils that are distilled from plant materials. These hydrocarbons are called terpenesand includepinene (in turpentine) and limonene(in lemon and orange oils).The most important group of unsaturated cyclic hydrocarbons is the aromatics, which occur in coal
    • Physical Properties of Hydrocarbons 29tar. Although the aromatics sometimes exhibit unsaturation, that is, the addition of other substances,their principal reactions bring about the replacement of hydrogen atoms by other kinds of atoms orgroups of atoms. The aromatichydrocarbonsincludebenzene, toluene, anthracene,and naphthalene.Characteristics of HydrocarbonsHydrocarbon materials have several different characteristicsthat can be used to define their level of hazard.Since no one feature can adequately define the ievel of risk for a particular substance they should beevaluated as a synergism. It should also be realized that these characteristicshave been tested under strictlaboratory conditions and procedures that may alter when applied to industrial environments. The maincharacteristics of combustible hydrocarbon materials which are of high interest for fire and explosioninfluencesare described below.Lower Explosive Limit (LEL)/Upper Explosive Limit (UEL)This is the range of flammability for a mixture of vapor or gas in air at normal conditions. The termsflammablelimits and explosivelimitsare interchangeable. Where the range between the limits is large, thehydrocarbon may be considered relatively more dangerous (e.g., hydrogen 4 to 75 % versus gasoline 1.4to 7.6 YO)when compared against each other since it has a higher probability of ignition in any particularsituation. Flammabilitylimits are not an inherent property of a material but are dependent on the surfaceto volume ratio and velocity or directionof air flow under the test.Some common petroleum materials and their flammable limits under normal conditions are listed belowbeginning with the widest ranges:Material YORange DifferenceHydrogenEthaneMethanePropaneButanePentaneHexaneHeptane4.0 to 75.63.0to 15.55.0to 15.02.0 to 9.51.5to 8.51.4to 8.01.7to 7.41.1to 6.771.612.510.07.57.06.65.75.6Flash Point (FP)The lowest temperature of a flammable liquid at which it gives off sufficient vapor to form an ignitablemixture with the air near the surface of the liquid or within the vessel used. The flash point has beencommonly determined by the open cup or closed cup method but recent research has yielded higher andlower flash points dependent on the surface area of the ignition source. Because of this aspect ASTMand other standardtest methods have been recently withdrawn. They are under review until an adequatedeterminationof a practical and comprehensive standard is composed and agreed upon.Common petroleum materials with some of the lowest flash points under normal conditions are listed
    • 30 Handbook of Fire and Explosion Protectionbelow:Material Flash PointHydrogenMethanePropaneEthaneButanePentaneHexaneHeptaneGasGasGasGas-60 OC (-76 OF)<-40 OC (<-4O OF)-22 (-7OF)-4OC (25OF)Autoignition Temperature (AIT)The autoignition temperature or the ignition temperature is the minimum temperature at to which asubstance in air must be heated to initiate or cause self sustaining combustion independent of the heatingsource. It is an extrinsic property, i.e., the value is specificto the particular experimental method that isused to determine it. The two most significant factors that influence a measurement of AITs are thevolume to surface ratio of the source of ignition (Le., a hot wire versus a heated cup will yield differentresults). Ignition temperatures should always be thought of as approximations and not as exactcharacteristicof the materialfor this reason.For straight paraffinic hydrocarbons (i.e., methane, ethane, propane, etc.) the commonly acceptedautoignition temperatures decrease as the paraffinic carbon atoms increase (e.g., methane 540 OC (1004OF) and octane 220 OC (428 OF)).Some common petroleum materials AITs under normal conditionsare listed below:Material ATTHeptaneHexanePentaneButanePropaneEthaneHydrogenMethane204 OC225 OC260 OC287 OC450 OC472 OC500 O C537 oc(399 OF)(437 OF)(500 OF)(550 OF)(842 OF)(882 OF)(932 OF)(999 OF)A mathematical method for obtaining a general approximation of hydrocarbon ignition temperaturesbased on the molecular weight of the vapor is mentioned in the NFPA Fire Protection Handbook. Itstates that the autoignition temperature of a paraffinic hydrocarbon series decreases as the molecularweight of the substancesincreases. A figure is provided by which if the "averagecarbon chain length"isknown, the minimum ignitiontemperature can be theoretically approximated.For hydrocarbon mixtures containing only paraffinic components, an approximation of the ignitiontemperature can be made by using the averagemolecular weight of the substance. It can be estimated bymultiplying the molecular weight of each pure vapor by its concentration (Le., measured percentage) inthe mixture, to arrive at an average mixture moiecular weight (average carbon chain length). Once thisknown it can be compared to the ignition temperature of a known substance with an equal weight orreference can be made to the figure in the NFPA Fire Protection Handbook. Again rememberingthat allAITs are onlyjust an approximation.
    • Physical Properties of Hydrocarbons 31By general inspection, where a large percentage of high ignition temperature paraffinic gas coexists in amixture with a low percentage of ignition temperature paraffinicgas, it can be conferred that the mixturewill have a higher ignition temperature than that of the low percentage ignition temperature gas (e.g.,90% propane, 10%hexane).This can be substantiated by the fact that where a high molecular weight hydrocarbon molecule isconverted into combustion,it takes less energy to sustainthe reaction than it would for a lower molecularweight (less energy) containing molecule. Thisis because more energy is being used for release in the highmolecular weight hydrocarbon substances.This principleonly applies to straight chain hydrocarbonsand is inappropriateif other types of substancesare involved (e.g., hydrogen).Figure 1 provides a suggested method to obtain an autoignitiontemperature approximation for paraffinichydrocarbonvapor mixtures. Although this method can be made to achieve a general approximation, it isstill best to obtain a laboratory analysis of the autoignition temperature for a gas mixture whenperformingmajor process designs.Autoignition temperatures are vitally important for process designs as it is the temperature at which toprevent or eliminate readily available ignition sources. (e.g., operating temperatures of electricalequipment, light fixtures, etc.).Recently revised test methods have revealed that nonluminous or barely luminous combustion reactionsare occurringwhere previously it was reported that no combustionactivity was occurring based on flameobservance.As a result of these new testing methods the following terminology for ignition temperature definitionshas been proposed:Hot Flame Ignition - A rapid self-sustaining, sometimes audible gas phase reaction of the sample orits decomposition products with an oxidant. A readily visible yellow or blue flame usuallyaccompaniesthe reaction.Cool Flame Ignition - A relatively slow self sustaining, barely luminous, gas phase reaction of thesampleor its decomposition products with an oxidant. Cool flamesare visible only in a darken area.Pre-Flame Reaction - A slow nonluminous gas phase reaction of the sample or its decompositionproducts with an oxidant.Catalytic Reaction - A relatively fast, self-sustaining, energetic, sometimes luminous, sometimesaudible reaction that occurs as a result of the catalytic action of any substance on the sample or itsdecomposition products, in a mixture with an oxidant.Non-Combustive Reaction - A reaction other than combustion or thermal degradation that isundergoneby certain substanceswhen they are exposed to heat.NFPA now normally refers to autoignition as the Hot Flame Ignition Temperature, as a more precisedefinition. Subsequentlythe followingtwo additional terms are being adopted by NFPA to hrther refinethe ignition properties of materials. The lowest temperatures at which cool flame ignitions are observedare named the Cool Flame Reaction Threshold (CFT). The lowest flame temperatures at which anexothermicgas phase reaction is noticed are named the PreflameReaction Threshold (RTT).
    • 32 Handbook of Fire and Explosion ProtectionExample:NGL ColumnBottoms Liquid Percentage Concentrationfrom sampleanalysis:Symbol Name Molecular Weight Ignition Temperature Percentagec 1 MethaneC2 EthaneC3 PropaneC4 ButaneC5 PentaneC6 Hexane163044587286540 OC 2.3 %515 OC 0.2 %450 OC 30 Yo405 O C 25 %260 OC 15.5 Yo225 OC 23 YoWave= 16(0.023)+ 30(0.002)+44(.30) + 58(0.25) + 72(0.155)+ 86(0.23)= 58.2 or equivalentto C4The NGL column bottoms has average molecular weight equivalent to normal butane and therefore has anapproximateautoignitiontemperature of 405 OC (761 OF).Figure 1Example of Autoignition Temperature Approximation Method(suitable for paraffinichydrocarbonmixturesonly)
    • Physical Properties of Hydrocarbons 33Vapor DensityVapor density is the measure of the relative density of the pure vapor or gas when compared to air.Technically it is the weight of a vapor per unit volume at any given temperature and pressure. Vaporswith a vapor density of greater than 1.O are heavier than air and will follow the surfaceof the ground untildissipated. Vapors with a vapor density less than 1.O will rise into the atmosphere, the lower the densitythe faster they will rise.Common petroleum materials with some of the highest vapor densities under normal conditionsare listedbelow:Material Vapor Densitv RatioHydrogenMethaneEthanePropaneButanePentaneHexaneHeptane0.0690.5541.0351.562.012.482.973.45Vapor PressureThis is the property of a substanceto vaporize. Liquids are usually classified by the Reid vapor pressure,which is calculated on the basis ofa specificoil at a temperature of 37.8 OC (100 OF).SpecificGravityThe specificgravity is the ratio of weight of equal volumes of a substance to that of another substanceusuallywater. For petroleumproducts it is customaryto measure the ratio at 15.6OC (60 OF)FlammableCapable of being easily set on fire; combustible. Inflammable isconsidered an obsolete term in the U.S.A. because of the connotation of the negative prefix thatincorrectlysuggeststhe material is not flammable.It is a synonym to inflammable.CombustibleIn a general sense any material than can burn. This implies a lower degree of flammability,althoughthereis no precise distinction between a material that is flammable and one that is combustible (NFPA 30,Combustible and FlammableLiquids Code, defines differences between the classification of combustibleliquids and flammableliquidsbased on flash point and vapor pressure).Heat of CombustionThe heat of combustion of a fie1 is defined as the amount of heat released when unit quantity is oxidizedcompletelyto yield stable products.
    • 34 Handbook of Fire and Explosion ProtectionDescription of Some Common HydrocarbonsNatural GasNaturally occurringmixtures of hydrocarbongases and vapors, the more important of which are methane,ethane, propane, butane, pentane and hexane. Natural Gas is lighter than air, non-toxic and contains nopoisonous ingredients. Breathing natural gas is harmful when there is not an adequate supply of oxygenin the atmosphere.Crude OilCrude oils consist primarily of hydrocarbons and compounds containing sulfur, nitrogen, oxygen, andtrace metals as minor constituents. The physical and chemical characteristics of crude oils-varywidely,depending on the percentages of the various compounds that are present. Its specific gravities cover awide range, but most crude oils are between 0.80 and 0.97 g/ml or gravity between 45 and 15 degreesMI. There is also a wide variation in viscosities, but most crude oils are in the range of 2.3 to 23centistokes.All crudes are a variation of the hydrocarbon base CH2. The ultimate composition shows 84 to 86%carbon, 10 to 14% hydrogen, and small percentages of sulfbr (0.06 to 2%), nitrogen (2 %), and oxygen(0.1 to 2%). The sulfur content is usually below 1.0%but may be as high as 5.0%. Physically crude oilmay be water-white, clear yellowish, green, brown, or black, heavy and thick like tar or asphalt.Because of the variations in the quality of crude oils, the flash point of any crude oil it must be tested,however because most crude oils contain a quantity of light vapors they are considered in a low flashpoint classification. In atmosphericburning heavy smoke production normally occurs.Methane (Cl)Methane, also referred to as marsh gas, is a gas composed of carbon and hydrogen with a chemicalformula of CH4. It is the first member of the paraffin or alkane series of hydrocarbons. It is lighter thanair, colorless, odorless, tasteless and is flammable. It occurs in natural gas and as a by-product ofpetroleum refining. In atmosphericburning no smoke production normally occurs. In air methane burnswith a pale, faintly luminous flame. With excess air carbon dioxide and water vapor is formed duringcombustion, with an air deficiencycarbon monoxide and water is formed. It forms an explosive mixturewith air over a moderate range. Its primary uses are as a fuel and raw feedstock for petrochemicalproducts.Methane melts at -182.5 OC (-296.5 OF) and boils at -161.5 OC (-258.7 OF) Its fuel value is 995 Btu percubic ft.LNG, Liquefied Natural Gas (Cl)Commercial liquefied natural gas (NGL) is composed of at least 99% methane that has been cooled toapproximately-160 OC (-256 OF), at atmosphericpressure. At this temperature is occupies only 11600ofits original volume. LNG is less than half as dense as water, is colorless, odorless, non-toxic and sulfurfke. In atmospheric burning no smokeproduction normally occurs.It is vaporized as needed for use as a high quality fbel.
    • Physical Properties of Hydrocarbons 35Ethane (C2)A gaseous paraffinichydrocarbon,CH3,CH3 that is colorless and odorless and normally found in naturalgas, usually in small proportions. It is slightly heavier than air and practically insoluble in water. Whenignited in atmospheric burning it produces a pale faintly luminous flame with little or no smokeproduction. With excess air during combustion it produces carbon dioxide and water, with limited airsuppliesthe combustion process will produce carbon monoxide and water. It forms an explosive mixturewith air over a moderate range.Ethane has a boiling point of -88 OC (-126 OF). The fuel value ofEthane is 1730Btu per cubic ftPropane(C3)Propane is a colorless, odorless gas of the alkane series of hydrocarbons, of formula C3H8. It occurs incrude oil, natural gas, and as a by-product of refinery cracking gas during petroleum refining. Propanedoes not react stronglyat room temperature. It does react, however, with chlorine at room temperature ifthe mixture is exposed to light. At higher temperatures, propane burns in air, producing carbon dioxideand water as final products, and is valuable as a fitel. In atmosphericburning smoke production normallyoccurs.About half the propane produced annually in the U.S.is used as a domestic and industrial fuel. When it isused as a fuel, propane is not separated from the related compounds, butane, ethane, and propylene.Butane, with boiling point -0.5 OC (31.1OF), however, reduces somewhat the rate of evaporation of theliquid mixture. Propane forms a solid hydrate at low temperatures, and this causes great inconveniencewhen a blockage occurs in a natural-gas line. Propane is used also as so-called bottled gas, as a motorfuel,as a refrigerant, as a low-temperaturesolvent,and as a source of propylene and ethylene.Propane melts at -189.9 OC (-309.8 OF) and boils at -42.1 OC (-43.8 OF)Butane (C4)Butane, is the either of two saturated hydrocarbons, or alkanes, with the chemical formula of C4H10 ofthe paraffin series. In both compounds the carbon atoms are joined in an open chain. In n-butane(normal), the chain is continuous and unbranched whereas in i-butane(iso) one of the carbon atoms formsa side branch. This difference in structure results in small but distinct differences in properties. Thus, n-butane melts at -138.3 O C (-216.9 OF) and boils at -0.5O C (31.1 OF), and i-butane melts at -145 OC (-229OF) and boils at -10.2 OC (13.6 OF).Both butanes occur in natural gas, petroleum, and refinery gases. They show little chemical reactivity atordinary temperatures but burn readily when ignited in air or oxygen. In atmospheric burning smokeproduction normally occurs.They make up the most volatile portion of gasoline and are sometimes added to propane to be marketedas bottled gas. Most n-butane, however, is converted to butadiene, which is used to make syntheticrubber and latex paints.LPG, Liquefied PetroleumGas (C3 & C4)Commercial Liquefied Petroleum Gas (LPG), is a mixture of the liquefied gases of propane (C3) andbutane (C4). It is obtained from natural gas or petroleum. LPG is liquefied for transport and thenvaporized for use as a heating fuel, engine fitel or as a feedstock in the petrochemical or chemicalindustries. It has a flammabilityrange of 1.8%to 10% and the vapor has a density of 1.5 to 2.0 that of
    • 36 Handbook of Fire and Explosion Protectionair. One volume of LPG liquid may form 2,300 to 13,500time the volume of gas in air. LPG vapor is ananesthetic and asphyxiant in high concentrations. LPGs are odorless, colorless, non-corrosive and non-toxic. It has a low viscosity and therefore is more likely to find a leakage path than other petroleumproducts. In case of a leakage it tends to spread on the surface accompanied by a visible fog ofcondensed water vapor, however the ignitablevapor mixtureextendsbeyond the visiblearea.Gasoline(C5 to C11)Gasolineis a mixture of the lighter liquid hydrocarbonsthat distillswithin the range of 38 to 204 OC (100to 400 OF). Commercial gasolines are a mixture of straight -run, cracked, reformed, and naturalgasolines. It is produced by the fractional distillation of petroleum; by condensation or adsorption fromnatural gas; by thermal or catalytic decomposition of petroleum or its fractions; by the hydrogenation ofproducer gas or by the polymerizationof hydrocarbonsof lower molecular weightGasoline produced by the direct distillation of crude petroleum is known as straight-run gasoline. It isusually distilled continuously in a bubble tower, which separates the gasoline from the other fractions ofthe oil having higher boiling points, such as kerosene, &el oil, lubricating oil, and grease. The range oftemperatures in which gasolineboils and is distilled off is roughly between 38 and 205 OC (100 and 400OF). The yield of gasoline from this process varies from about 1 percent to about 50 percent, dependingon the petroleum. Straight-rungasoline now makesup only a small part of gasolineproduction because ofthe superior merits of the various crackingprocesses. The flash point of gasoline is well below -17.8 OC(0 OF) at atmosphericpressure. In atmosphericburning smoke production normally occurs.In some instances natural gas contains a percentage of natural gasoline that may be recovered bycondensation or adsorption. The most common process for the extraction of natural gasoline includespassing the gas as it comes from the well through a series of towers containing a light oil called straw oil.The oil absorbs the gasoline, which is then distilled off. Other processes involve adsorption of thegasolineon activated alumina, activated carbon, or silica gel.High-grade gasoline can be produced by a process known as hydrofining, that is, the hydrogenation ofrefined petroleum oils under high pressure in the presence of a catalyst such as molybdenum oxide.Hydrofining not only converts oils of low value into gasoline of higher value but also at the same timepurifies the gasolinechemicallyby removing undesirable elements such as sulfir. Producer gas, coal, andcoal-tar distillatescan also be hydrogenatedto form gasoline.Condensate(C4, C5, C6 & >)Condensate is normally considered the entrapped liquids in process or production gas streams due totemperature or pressure, in the typically in the range of C3,C4, CS or heavier hydrocarbon liquids. It isalso known as natural gasoline C5 plus and pentanes plus, and as a liquid at normal temperatures andpressures it generally consists of a mixture of the C5 (pentanes) and heavier hydrocarbons. It is normallycondensed (i,e., by expansion and cooling of the gas) out of the process stream in primary separationprocesses, where it is then sent to other refinery processes to firther separate the condensate into itsprimary fractions,Le., propane, butane, and liquidsconstituents.The flash point of condenstate is generallytaken as that of hexane, where precise measurements have notbeen taken. Hexane has the lowest flash point of any material in the constitution of condensate. Inatmospheric burning smoke production normally occurs.
    • Physical Properties of Hydrocarbons 37Gas and Fuel Oils (C12 to C19)Gas oil or fbels oil is a generic term applied to petroleum distillates boiling between kerosene andlubricating oils. The name gas oil was originally derived from its initial use for making illuminating gas,but is now used as a burner fuel, diesel engine fuel, and catalytic cracker charge stock. Gas oils containfkel oils such as kerosene, diesel fkels, gas turbine fuels, etc. In atmospheric burning smoke productionnormally occurs.KeroseneKerosene or sometimesreferred to as Fuel Oil # 1 is a refined petroleum distillate. Kerosenesusuallyhave flash points within the range of 37.8 OC to 54.4 OC (100 OF to 130 OF). Therefore unlessheated, kerosene will usually not produce ignitablemixtures over its surface. In atmosphericburningsmoke production normally occurs. In someapplications it is treated with sulfuric acid to reduce the content of aromatics, which burn with asmoky flame.It is commonly used as a firel and a solvent.DieselDiesel or sometimes referred to Fuel Oil #2 is the fraction of petroleum that distills after kerosene;which is in the family of gas oils. In atmospheric burning smoke production normally occurs.Several grades of diesel are produced depending on the intended service. The combustioncharacteristics of diesel fbels are expressed in terms of a centane number, which is a measure ofignition delay. A short ignition delay, i.e., the time between injection and ignition is desirabie for asmooth running engine.Fuel Oils # 4, 5, & 6These are fuels for low and medium speed engines or as a feedstock for catalytic cracker refiningprocesses.LubricatingOils and Greases (C20 to C27)Vacuum distillates or residual fraction of vacuum distillates are the main source of lubricating oilsfrom the petroleum industry. Although they account for only 1% of the volume of petroleum fuelsalesthey are a high value unit. Besides lubricationthey are used as heat transfer mediums, hydraulicfluids, corrosion protection, etc.,both in industry and society.Grease is a thick, oily, lubricating material that typically has a smooth, spongy or buttery feel.Lubricating greases are made by thickening lubricating oils with soaps, clays, silica gel or otherthickening agents. Greases range from soft semi-fluids to hard solids, the hardness increasing as thecontent of the thickening agent increases. Greases are classified according to the type of thickenerused, e.g., lithium, calcium, organic, etc., and their consistency.Petrolatum is produced from lubricating oils. Petrolatum is used in the medicinal field where it iscombinedwith other compoundsto form salves, creams, ointmentsand petroleumjelly.Asphalts and Waxes (C28 & >)AsphaltAsphalt is a bituminous substance that is found in natural deposits or as the residual of in petroleum orcoal tar refining processes. It has a black or brownish-black color and pitchy luster. It is cement-like in
    • 38 Handbook of Fire and Explosion Protectionnature varying in consistency at room temperature from solid to semisolid depending on the amount oflight hydrocarbon fiactions that have been removed. It can be poured when heated to the temperature ofboilingwater. The quality of asphalt is affected by the nature of the crude oil and the refiningprocess. Itis used in surfacing roads, in water-retaining structures such as reservoirs and swimming pools, and inroofing materials and floor tiles. Asphalt should not to be cohsed with tar. Tar is a black fluidsubstancederived from coal.About 75 percent of U.S.production of petroleum asphalt is used for paving while 15 percent is used forroofing. The remaining 10percent is used for the more than 200 other known uses of asphalt.WaxWax is a soft impressionable semi-solid material having a dull luster and a somewhat soapy or greasytexture. It softensgraduallyupon heating, going through a soR, malleable state before ultimatelyforminga liquid. Paraffin wax is a mixture of saturated hydrocarbons of higher molecular mass, produced duringthe refining of petroleum. Natural petroleum waxes may occur during the production of somehydrocarbon reservoirs containing heavy oils. Most commercial waxes now come from petroleum.Chlorinatedparaffin waxes have come into considerableuse because of their fire resistant properties.
    • Table 2Characteristics of Selected Common HydrocarbonsPhysical Properties of Hydrocarbons 39
    • 40 Handbook of Fire and Explosion Protection1.2.3.4.5.6.78BibliographyCompressed Gas Association,Handbook of CommessedGases, Third Edition, Van Nostrand Reinhold, New York,NY, 1990.Fenstemaker, R. W., "Study of Autoignition for Low Pressure Fuel-Gas Blends Helps Promote Safety", Oil andGas Journal, February 15, 1982.Factory Mutual, Handbook of IndustrialLoss Prevention,Second Edition,McGraw-Hill, New York, NY, 1967Maxwell, J. B., Data Book on Hvdrocarbons. Apolication to Process Engineering, Krieger Publishing Company,Malabar,FL 1968.National Fire Protection Association(NFPA),Fire ProtectionHandbook, 17thEdition,NFPA, Quincy, MA, 1991National Fire Protection Association (NFPA), NFPA 30. Flammable and Combustible Liauids Code, NFPA,Quincy, MA, 1993.National Fire ProtectionAssociation (NFPA), NFPA 325M, Fire Hazard Properties of Flammable Liauids. Gasesand VolatileSolids,NFPA, Quincy, MA, 1991.Societyof Fire Protection Engineers (SFPE),Handbook of Fire Protection Engineering, NFPA, Qwncy, MA, 1988.9. Zabetakis, M. G., Bulletin 627, Flammabilitv Characteristicsof CombustibleGases and Vapors, Bureau of Mines(BOM),U. S.Departmentof the Interior,Pittsburgh, PA, 1965.
    • Chapter 5Characteristics of HydrocarbonReleases, Fires and ExplosionsPetroleum (oil and gas), is a highly dangerous commodity that should be recognized for its hazards andhandled with the proper precautions. The ignition of combustible gas clouds or vapors can produce highlydamaging explosionsand high temperature fires. These events can completely destroy an entire installationif allowed to developed or left uncontrolled. Ordinary wood and combustiblesburn with a relativelygradualincrease in temperature to a moderate levei while hydrocarbon fires immediate reach a high temperaturelevel within minutes and continue at this level until exhausted. By comparison to ordinary combustibletires,hydrocarbonfires are a magnitude greater in intensity. Fire barriers or suppressionmechanismsadequate forordinary occupanciesare quite easily overtaxedwhen a high intensity hydrocarbonfire is prevalent.The most destructive incidents in the petroleum and related industries are usually initiated by an explosiveblast that can damage and destroy unprotected facilities. These blasts have been commonlyequated with theforce of a TNT explosion and are quite literally a "bomb". The protection of hydrocarbon and chemicalindustries is in rather a unique discipline by itself, which requires specialized techniques of mitigation andprotection in a systemsbased approach. The first step in this approachis to understand the characteristicsofhydrocarbon releases, tires and explosions.There is a great degree in variation in the degree of intensity that can be experienced in hydrocarbon fires.This is due to the variationsin the properties of the hydrocarbonmaterials involved. Open fires of any kindgenerally involve flame and combustion products that flow upward. Where less volatile materials (i.e.,liquids) are involved, they may tend to accumulate towards the ground in "pools". The more volatile thematerial becomes from heat effects, uncontained pressure releases or other factors, the fire will bum withflames rising to higher elevations, with less tendency to bum at the point of origin. There may be localizedeffectsthat determinethe shapeand configurationof the upward flamesand products of combustion.Localized failures of pressurized piping, process pumps, vessels or other parts of the process under pressurewill cause a "torch" or "jet" fire. These fires may project flamesin any direction, for a considerable distance,depending on the contained pressures and volumes of the source. Any facility that retains large amounts ofhigh pressure liquids or gases can producejet for extendedperiods if adequate isolation and depressurizationcapability is unavailable. The worst offenders in these cases are wellheads, high pressure gas pipelines andstorage facilities.41
    • 42 Handbook of Fire and Explosion ProtectionHydrocarbon ReleasesHydrocarbon releases in the petroleum industry are either gaseous, mists or liquids and are eitheratmospheric releases or pressurized. Gas and mist releases are considered more significant since they arereadily ignitable since they are in the gas state and due to the generation of vapor clouds which if ignited areinstantly destructive in a widespread nature versus liquid fires that may be less prone to ignition, generallylocalized and relatively controllable.The cause of a release can be external or internal corrosion, internal erosion, equipment wear, metallurgicaldefects, operator errors third party damageor for operationalrequirements.Generallyreleases are categorized as:1.Catastrophic Failure: A vessel or tank opens completely immediately releasing its contents. Theamount of release is dependentof the size of the container.2. Long Rupture: A section of pipe is removed leading to two sources of gas. Each section beingvented in an opening whose cross sectional areas are equal to the cross sectional area of the pipe(e.g., pipeline external impact and a section is removed).3.Open Pipe: The end of a pipe is hlly opened exposingthe cross sectional area of the pipe (e.g.,drillingblowouts).4. Short Rupture: A split occurs on the side of the pipe or hose. The cross sectional area of theopeningwill typically be equal to the cross sectionalarea of the pipe or hose (e.g., pipe seam split).5. Leak: Leaks are typically developed from valve or pump seal packing failures, localized corrosionor erosioneffects and are typically "small"to "pin-hole" sized (e.g., corrosion or erosion leakages).6. Vents, Drains, Sample Ports Failures: Small diameter piping or valves may be opened or failwhich release vapors or liquids to the environmentunexpectedly.7. Normal Operational Releases: Process storage or sewer vents, relief valve outlets, tank seals,which are considered normal and acceptablepracticesthat release to the atmosphere.Gaseous ReleasesThere are a number of factors that determine the release rate and initial geometry of a hydrocarbon gasrelease. The most significant is whether the gas is under pressure or released at atmospheric conditions.Depending on the release source the escaping gas can last from several minutes or days, until the supply isisolated, depleted or hlly depressured. Common long duration sources are underground reservoirs (e.g.,blowouts), or long pipelineswithout intermediateisolation capabilities.If released under atmospheric conditions the gas will either rise or fall depending on its vapor density andwill be directed in the path of the prevailingwind. In the absence of a wind, heavier gases will collect in lowpoints in the terrain. Normally atmospheric gas releases are dispersed within relatively close distances totheir point source, usually about 3 meters (10 ft.) (ReferenceNFPA 30, Table 5-3.5.3). These atmosphericreleases, if ignited, will burn relativelyclose to the source point, normally in a vertical position with flames ofshort length.For gases released under pressure, there are a number of determining factors that influencethe release ratesand initial geometry of the escaping gases. The pressurized gas is released as gas jet and depending on thenature of the failure may be directed at any direction. All or part of a gas jet may be deflected by
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 43surroundingstructures or equipment.If adequate isolation capabilities are available and employed, the initial release will be characterizedby highflow and momentum which decreases as isolation is applied or supplied are exhausted. Within a few pipediameters of the release point, the pressure of released gases decreases. Escaping gases are normally veryturbulent and air will immediately be drawn into the mixture. The mixing of air will also reduce the velocityof the escaping gas jet. Obstacles such overhead platforms or structures will disrupt momentum forces ofany pressurized release. These releases will generally produce a vapor cloud, which if not ignited willeventually disperse in the atmosphere. Where turbulent dispersion processes are prevalent (e.g., highpressure flow, winds, congestion, etc.), the gas will spread in both horizontal and vertical dimensionswhilecontinuing mixing with available oxygen in the air. Initially escaping gases are above the UEL but withdispersion and turbulence effects they rapidly pass into the flammable limits. If not ignited and given anadequate distance they will eventually disperse below the LEL. Various computer software programs arecurrently availablethat can calculatethe turbulentjet dispersion, downwind explosive atmosphericlocations,and volumes for any given flammable commodity,release rates and atmosphericdata input.Generally most gases have a low vapor density and will rise. In any event, the height of a gas plume willmostly be limited by the ambient atmosphericstabilityand wind speed. If the gases are ignited, the height ofthe plume will rise due to the increased buoyancy of the high temperature gases from the combustionprocess.Mists or Spray ReleasesSpray and mists releases generallybehave like a gas or vapor release. The fuel is highly atomized and mixedwith air. Sprays or mists can easily be ignited, even below the flash point temperature of the materialinvolved, sincemixing of the fuel with the air has already occurred.Liquid ReleasesLiquidsreleasescan be characterizedby either being contained, allowed to runoff or spread to lower surfaceelevations. If they are highly volatile, dissipation by vaporization may occur when the vaporization rateequals the spread rate. Depending on the viscosity of non-volatile liquids, they will spread-out immediatelyand foim into a "pool" of liquid that is somewhat localized to the immediate area. The higher the viscosity,the longer it will take to spread. As a general rule of thumb, 3.8 liters (1 gal.), of unconfined liquid on alevel surfacewill cover approximately 1.8square meters (20 sq. ft.), regardless of viscosity. A pool on calmwater will spread under the influence of gravity until limited by surface tension, typically giving a minimumoil slick thickness of 10 mm (0.04 inches) on the water. A pool on the water will also drift in the directionof wind and current If not ignition occurs, the lighter ends will evaporate and eventuallythe residual oil willbe broken up by wave action and bacteriological digestion. During the evaporation of the lighter fractions,combustiblevapors may form immediately above the oil spill for a short distance.Liquidsunder pressure (pipelineleaks, pump seal failures, etc.), will be thrown some distance from the pointsource, while atmospheric leakages will emit at the point of release. The other characteristic of liquidreleases is their flash points. High flash point liquids, not operating above their flash point temperatures, areinherently safer than low flash point liquids. Most liquid fires are relatively easy to contain and suppresswhile gas fires are prone to explosionpossibilitiesif extinguishedand source points are not isolated.
    • 44 Handbook of Fire and Explosion ProtectionLiquid releases are characterizedby the followingfeatures:1. Leaks and Drips: Leaks and drips are characterized by small diameter releases of highfrequencies. They are typically caused by corrosion and erosion failures of piping, mechanical andmaintenancefailures of gaskets and valves.2. Streams: Medium size releases of moderate to low frequencies. Typically small diameter pipeopeningsthat have not be adequately closed, i.e., sampleor drain lines.3. Sprays and Mists: Medium sized releases of moderate frequenciesthat are mixed immediately into air upon release. Typically pipe gasket, pump seal and valve stem failures under high pressure.On occasionreleases occur from flare stacks.4. Ruptures: Large releases of very low frequencies. Typically vessel, tank pipeline or hose failuresfrom internal, external, or third party sources and fire conditions(i.e.,BLEW conditions).Nature and Chemistry of HydrocarbonCombustionSimplehydrocarbon fires combinewith oxygen to produce carbon and water, through a combustion process.Combustion is a chemical process of rapid oxidation or burning of a %el with simultaneous evolution ofradiation energy, usually heat and light. In the case of common fuels, the process is one of chemicalcombination with atmospheric oxygen to produce as the principal products carbon dioxide, carbonmonoxide, and water. Hydrocarbonsare freely burning and generallyeasily ignitablein open air situations.The energy released by the combustion causes a rise of temperature of the products of combustion. Thetemperature attained depends on the rate of release, ‘dissipation of the energy, and the quantity ofcombustion products. Air is the most convenient source of oxygen, but because air is three-quartersnitrogen by weight, nitrogen becomes the major constituent of the products of combustion, and the rise intemperatureis substantiallyless than if pure oxygen was used. Theoretically,in any combustion, a minimumratio of air to fuel is required for complete combustion. The combustion, however, can be made morereadily complete, and the energy released maximized, by increasing the amount of air. An excess of air,however, reduces the ultimate temperature of the products and the amount of the released energy.Therefore, an optimum air-to-he1 ratio can usually be determined, depending on the rate and extent ofcombustion and the final temperature desired. Air with enriched oxygen content or pure oxygen, as in thecase of the oxyacetylenetorch will produce high temperatures. The rate of combustion may be increased byfinely dividingthe fuel to increase its surface area and hence its rate of reaction, and by mixingit with the airto provide the necessary amount of oxygen to the hel.Hydrocarbon materials must first be in a vapor conditionbefore combustion processes can occur. For anygaseous material this is an inherent property. Liquids however must have significant vapor emissions inorder for flammable concentrations to be present for combustion processes to occur. Thereforehydrocarbonliquid releases are nominallyless dangerousthan a gas release.Gases by their nature are immediately ignitable (versus liquid releases that must vaporized to supportcombustion), and can produce a fast burning flame front that generates into an explosive force in confinedareas. If pressurized gas leak fires are extinguished, but the leakage is not stopped, the vapors can again bere-ignited and produce an explosiveblast.When an ignition source is brought into contact with a flammable gas or mixture of gases, a combustionchemical reaction will occur at the point of introduction provided an oxidizer is present, normally oxygen.The combustion componentsare commonly referred to as a simple fire triangle:
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 45Ignition Source OxidizerFire TriangleA more scientificrepresentation is a fire tetrahedron with the combustion chemical reaction considered as afourth parameteror side of the tetrahedron.Combustionwill occur which travels from the point of originthroughout the body of the gas and air mixture.Combustion continues until the fuel is exhausted, if sufficient air (i.e., oxygen) is available or until asuppressionmechanisminterrupts the process.The basic equation for the chemical reaction of hydrocarbon molecules in ideal combustion is provided bythe following:In ideal combustion 0.45 kgs (1 lb.) of air combineswith 1.8kgs (4 Ibs.) of oxygen to produce 1.2kgs (2.75lbs.) of carbon dioxide and 1.02kgs (2.25lbs.) of water vapor. Carbon monoxide, carbon dioxide, nitrogenand water vapor are the typical exhaust gases of ordinary combustion processes. If other materials arepresent they will also contributeto the exhaust gases forming other compounds,which in some cases can behighly toxic. Imperfect combustion will occur during accidental fires and explosion incidents. This mainlydue to turbulence,lack of adequate oxidizer suppliesand other factors that produce free carbon @e.,smoke)partjcles, carbon monoxide, etc.The combustion process is accompanied by the evolution of radiation - heat and light. A typical liquidhydrocarbon combustion process produces approximately I5 kgs (33 Ibs.) of combustion products per kg(2.2 lbs.) of hydrocarbon consumed. Because of the high proportion of nitrogen in the atmosphere(approximately 78 % by weight), nitrogen tends to dominate in the combustion exhaust products (it ismixed-in during the free air combustion process). Because of this, it is sometimes used as the mainconstituent in tire mass release dispersion modeling. The mass flow rate is normally taken as fiReen timesthe burning rate of the hydrocarbonmaterial. A typical fuel burning rate for liquid hydrocarbonsis 0.08 kg/sq. nds(O.0164 lbs./sq.ft./s).Depending on the fuel involved, a specific amount of heat (i.e., calories or Btu) is released. Ordinarycombustibles produce a moderate level of heat release but hydrocarbon molecules have a very high level ofheat release. In ideal combustion of 0.45 kgs (1 lb.) of methane, approximately 25,157 kilo-joules (23,850Btu) are released. The temperature of the combustionproducts is normally taken to be 1200OC (2192 OF),which is a typical hydrocarbonfiretemperature.A heat flux rate is commonly specified during consequent modeling of hydrocarbon fires. Heat flux isconsidered the more appropriate measure by which to examine the radiation effects from a fire. A radiantheat flux of 4.7kw/m2 (1,469 Btu/fk2) will cause pain on exposed skin, a flux density of 12.6kw/m2 (3,938Btu/il2) or more may cause secondary fires and a flux density of 37.8 kw/m2 (11,813 Btu/fL2) will causemajor damageto a process plant and storage tanks.Under atmosphericconditions flame travel in an unconfined gas cloud precedes as definite flame front at adeterminable velocity. For example, where the ignition point is located in the middle of a volume of a gas,the flame front tends to generally proceed as an expanding sphere from the point of origin. Flame
    • 46 Handbook of Fire and Explosion Protectionpropagationresults from the conductiontransfer of energy from the flame front to the layer of gases in frontof it. These gases are in turn ignited, which continues the process. In mixtures that contain the fuel andoxidizer in proportions outside the LELMiL, insufficientheat energy is released by combustion heat to theadjacent layers of gases to produce sustained combustion. Where the combustion is within the LEL/UELlimits flame propagation appears most rapid in an upward direction, which is chiefly due to convectioncurrents. When any large accumulation of gaseous fuel and air mixtureis ignited, convection currents causeflamesto be carriedupwards, while burring in the horizontal directionis relatively slower.In normal atmosphericconditions,fire usually is initialedby a combustible material coming in contact with aheat source. The spread of fire occurs due to direct flame impingement or the transfer of heat to thesurrounding combustible materials. Heat transfer occurs by three principal mechanisms - conduction,convection,and radiation. Conductionis the movement of heat through a stationary medium, such as solids,liquids or gases. Steel is a good conductor of heat as is aluminum, therefore they can pass the heat of a fireif left unprotected.Convection signifiesthe transfer of heat from one location to another by a carrier medium moving betweenthem, such as when a gas is heated at one point and travels to another point at which it gives up its heat.Convectioncurrents of heated hot air and gases normally account for 75 to 85% of the heat generated froma fire. Large masses of heated air by flame convection currents will quickly raise the temperature of allcombustible material in their path to the required ignition temperature. Where prevented by rising bystructural components(i.e.,ceilings, decks, etc.), the fire will spread out laterally and form a heat layer withincreasingdepth and intensityas the fire progresses. Within enclosed spacesthe ambient conditionssoon areraised to a temperature above the ignition point and combustion occurs simultaneouslyeverywhere, knownas a flashover.Radiation is the transfer of energy by electromagneticwaves and can be compared to the transmission oflight through the atmosphere. When radiationwaves meet an object, their energy is absorbed by that objectat its surface. The rate of heat transfer by conduction is proportional to the temperature differencebetweenthe point giving up and receiving the heat. In convection the rate of heat transfer is dependent upon the rateof movement of the carrier medium. This movement may be caused by differencesin density of the materialor due to mechanical pumping (e.g., hot air blowing systems). In the radiation of heat, the transfer rate isapproximately proportional to the fourth power of the temperature difference between the radiating sourceand the receiver. Thus the radiant heat transmission from fires is a high factor to consider for any fireincident and hence the importance placed on cooling exposed surfaces of processes and preservation ofstructural support by fireproofingmaterials.If a hydrocarbon release is ignited, various possible fire and explosion events may result. The events areprimarily dependent on the type of material, the rate of release, the item at which it is ignited and nature ofthe surroundingstructure.Eydrocarbon FiresTypicallyhydrocarbon fire events can be categorized as follows:Jet FireAMost fires involving gas in the oil and gas industry will be associated with a high pressure andlabeled as "jet" fires. A jet fire is a pressurized stream of combustible gas or atomized liquid(such as a high pressure release from a gas pipe or wellhead blowout event) that is burning. Ifsuch a release is ignited soon after it occurs, (i.e., within 2 -3 minutes), the result is an intensejet
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 47flame. Thisjet fire stabilizesto a point that is close to the source of release, until the release isstopped. Ajet fire is usually a very localized, but very destructiveto anything close to it. This ispartly because as well as producing thermal radiation, the jet fire causes considerableconvectiveheating in the region beyond the tip of the flame. The high velocity of the escaping gas entrainsair into the gas "jet" causing more efficient combustion to occur than in pool fires.Consequentially,a much higher heat transfer rate occurs to any object immersedin the flame, i.e.,over 200 kw/sq. m (62,500 Btdsq. ft) for a jet fire than in a pool fire flame. Typically the first10% of ajet fire length is conservativelyconsideredunignited gas, as a result of the exit velocitycausing the flame to lift off the gas point of release. This effect has been measured onhydrocarbon facility flares at 20% of the jet length, but a value of 10%is used to account for theextra turbulence around the edges of a real release point as compared to the smooth gas releasefrom a flare tip. Jet flames have a relatively cool core near the source. The greatest heat fluxusually occurs at impingement distances beyond 40% of the flame length, fiom its source. Thegreatest heat flux is not necessarilyon the directly impinged side.Pool FirePool fires have some of the characteristicsof a vertical jet fire, but their convective heating willbe much less. Heat transfer to objects impinged or engulfed by pool fires is both by convectionand radiation. Once a pool of liquid is ignited, gas evaporates rapidly from the pool as it isheated by the radiation and convective heat of the flame. This heating mechanism creates afeedback loop whereby more gas becomes vaporized fiom the liquid surface. The surface fireincreases in size in a continuingprocess of radiation and convection heating to the surroundingarea until essentiallythe entire surfaceof the combustibleliquid is on fire. The consequencesof apool fire are represented numerically by a flame zone surrounded by envelopes of differentthermal radiationlevels. Heat transfer rates to any equipment or structure in the flame will be inthe range of 30 to 50 kw/sq. m. (9,375 to 15,625Btdsq. ft.).Flash FireIf a combustible gas release is not ignited immediately,a vapor plume will form. This will driftand be dispersed by the ambient winds or natural ventilation. If the gas is ignited at this point,but does not explode, it will result in a flash fire, in which the entire gas cloud burns very rapidly.It is unlikely to cause any fatalities, but will damage steel structures. If the gas release has not beisolated during this time, the flash fire will burn back to a jet fire at the source of the release. Aflash fire is represented by its limiting envelope, since no damage is caused beyond it. Thisenvelopeis usually taken asthe LEL of the gas cloud.Mathematical estimates are available that can calculate the flame and heat effects (i.e., size, rate andduration) for pool, jet and flash hydrocarbonfires. These estimatesare based on the "assumed"parameter ofthe materialrelease rate. To some extent, the ambientwind speed also has a varying influence.All hydrocarbonfire mechanisms and estimateswill be affected by to some extent of flame stability featuressuch as varying fuel composition as lighter constituents are consumed, available ambient oxygen supplies,ventilation patterns, and wind effects. Studies into these effects have generally not progressed to the levelwhere precise estimationscan be made without scalemodel tests or on site measurements.
    • 48 Handbook of Fire and Explosion ProtectionNature of HydrocarbonExplosionsA combustiblevapor explodesunder a very specific set of conditions. There are two explosive mechanismsthat need to be considered when evaluating combustible vapor incidents - detonations or deflagrations. Adetonation is a shock reaction where the flames travel at supersonic speeds (ie., faster than sound).Deflagrationsare where the flames are traveling at subsonicspeeds.During the 1970s, considerable progress was made in the understanding of supersonic explosions, i.e.,detonations. It was shown that the conditionsneeded to initiate a denotation - whether by shock, flamejetignition or flame accelerationare too extreme to occur in everyday operation for all non-pressurized naturalgas and air systems. However they can still occur in pressurized gas and air systems (i.e., process vesselsand piping). It is generallyrecognized that vapor cloud explosions have flames that travel at subsonic speedsand are therefore technicallyclassified as deflagrationsbut are stillcommonlyreferred to as explosions.Process System Explosions (Detonations)Detonations can occur in solids and liquidsbut are particularly frequent in petroleum facilities in mixtures ofhydrocarbon vapors with air or oxygen. Detonations will develop more rapidly at initial pressures aboveambient atmospheric pressure. If the initial pressure is high the detonation pressure will be more severe anddestructive.Detonations produce much higher pressures than what be considered ordinary explosions. In most cases aprocess vessel or piping systemswill be unable to contain detonation pressure. The only safe procedure is toavoid process system detonations is to preventing the formation of flammable vapor and air mixtures withinvessels and piping systems. While the flame speed of explosions is at relatively slow speed, detonationstravel at supersonicspeeds and will be more destructive.Vapor Cloud ExplosionsAn unconfined vapor cloud explosion (UCVE) is a popular term that tries to explain the ignition ofcombustible gas or vapor releases in the open atmosphere. In fact a considerable amount of publishedliterature states that "open" air explosion will only occur if there is sufficient congestion or in some casesturbulence of the open air is occurring, Gas or vapor clouds ignited under certain conditions produce anexplosion. Two types of explosionsare classified, detonation (supersonic, shock reaction) and deflagration(subsonic, turbulent flame). Research into the mechanism of flames indicates that vapor cloud explosionsare high-speed, but have subsonic combustionresultingin a deflagrationnot a detonation. Experimentshavealso demonstrated that flames traveling though unenclosed gas and air clouds produce negligibleoverpressures. When objects such as pipes and vessels are near or in the presence of an ignited gas cloudthey generate turbulenceproduce damaging explosionoverpressures ahead of the flame front.In order for a vapor cloud explosionto occur in a hydrocarbon facility, four conditionshave to be achieved:(1) There has to a significant release of flammablematerial.(2) The flammablematerialhas to be sufficientlymixed with the surroundingair.(3) There has to be an ignition source.(4) There has to be sufficientconfinement,congestion,or turbulence in the released area.
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 49The amount of explosion overpressure is determined by the flame speed of the explosion. Flame speed is afknction of the turbulence created within the vapor cloud that is released and the level of &el mixture withinthe combustible limits. Maximum flame velocities in test conditions are usually obtained in mixtures thatcontain slightly more he1 than is required for stoichiometric combustion. Turbulence is created by theconfinement and congestionwithin the particular area. Modern open air explosion theories suggest that allonshore hydrocarbon process plants have enough congestion and confinement to produce vapor cloudexplosions. Certainly confinement and congestion are available on most offshore production platforms tosome degree.Two types of open air explosions are possible, representingtwo differentmechanismsfor pressure buildup.Semi-confined Vapor Cloud ExplosionsThese require some degree of confinement, usually inside a building or module. The mechanism ofpressure buildup is the expansion of hot gas as it burns, exceeding the vent capacity of the enclosure.No significant shock wave is created, because in general the space is too small or there is insufficientgas for the flame fiont to accelerate to the necessary speed. These explosions can occur with smallamountsof gas.Vapor Cloud ExplosionsThese explosions may occur in unconfinedareas, although some degree of congestion is still required.The overpressureis created by the rapid and acceleratingcombustion of the gas and air mixture. Thespeed of the flame front can reach over 2,000 meters per second, (6,000 fth)creating a shock waveas it pushes the air ahead of it. Vapor cloud explosionscan only occur in relatively large gas clouds.Once the explosion occurs it creates a blast wave that has a very steep pressure rise at the wave front and ablast wind that is a transient flow behind the blast wave. The impact of the blast wave on structures near theexplosion is known as blast loading. The two important aspects of the blast loading concern is theprediction of the magnitude of the blast and of the pressure loading onto the local structures. Pressureloading predicationsas a result of a blast, resemble a pulse of trapezoidalor triangular shape. They normallyhave a duration of between approximately 40 msec and 400 msec. The time to maximum pressure istypically 20 msec.Primary damage from an explosion may result from several events:1. Overpressure - the pressure developed between the expanding gas and it’s surroundingatmosphere.2. Pulse - the differentialpressure across a plant as a pressure wave passes might cause collapseor movement, both positive and negative.3. Missiles and Shrapnel - are whole or partial items that are thrown by the blast of expandinggases that might cause damage or event escalation. These items are generally small in nature(i.e., hard hats, nuts, bolts, etc.), since the expanding gases do not have enough energy to liftheavy items such as vessels, valves, etc. This is in direct opposite to a rupture, in which therupture or internal vessel explosion, causes portions of the vessel or container to be thrown fardistances. In general these “missiles”from atmospheric vapor cloud explosions cause minorimpacts to process equipment since insufficient energy is available to lift heavy objects andcause major impacts. Small projectile objects are still a hazard to personnel and may causeinjuries and fatalities. Impacts from rupture incidents may produce catastrophic results @e.,puncturing other vessels, impact onto personnel, etc.), hence the tremendous reliance on
    • 50 Handbook of Fire and Explosion Protectionpressure relief systems (overpressure safety valves, depressuring capability, etc.) in thehydrocarbonand chemical industries.In oil and gas facilities,these effects can be generally related to flame velocity, where this velocity is below100 m/s (300 ft./s), damage is considered unlikely (Note: This is generally within the limits of confinementnormally found in offshorefacilities). The size of a vapor cloud or plume in which such velocitiescan occurhas been experimentallyinvestigated at the Christian Michelsen Institute (CMI, Norway). The experimentsdemonstrated that flames need a "run-up" distance of approximately 5.5 meters (18 fi.) to reach damagingspeeds. Therefore vapor clouds with dimensionsless than this may not cause substantial damage. This is amuch over-simplificationof the factors and variables involved, but does assume the WCCE of congestion,confinementand gas concentrations.Semi-confined Explosion OverpressuresThe overpressuredeveloped in semi-confined explosionsdepends on the followingkey parameters:- The Volume of the Area: Large confined areas experiencesthe largest overpressures.- Ventilation Area: The degree of confinement is of vital importance. The existence of openings,whether permanent vents or coveredby light claddingsgreatly reduce the predicted overpressure.- Obstacles. Process Equipment, and Piping: Structural steel and other obstaclescreate turbulence inthe burning cloud, which increases the overpressure The profile, size and location of obstacleswill all influencethe amount of overpressuredeveloped.- Ignition Point: Ignition points at long distancesfrom the vent areas increasethe overpressure.- Gas Mixture: Most studies have been on methane and air mixtures, but propane and air mixturesare known to be slightly more reactive and create higher overpressures. Increasingthe content ofthe higher hydrocarbon gases is therefore expected to have a similar effect. The initial temperatureof the mixture may also influenceoverpressureoutcomes.-Gas:Combustible gasses must be mixed with air to achieve the explosive range limits forthe particular gas. A worst case mixture, slightly richer in fuel than stoichiometric,correspondingto the fastest burning mixture is normally used in calculation estimates providing a conservativeapproach.Some consulting companies and the risk engineering departments of insurance agencies have softwareavailable to perform estimates of overpressures for semi-confined explosions, taking in account theseparticular parameters. These proprietary software models are generally based on empirical formulas, withvalidation against 1:5 scale experimental testing and studies against actual historical incidents, Le., PiperAlpha, Flixborough and others.Vapor Cloud Explosion OverpressuresPrevious studiesof Vapor Cloud Explosions(VCE) have used a correlationbetween the mass of a gas in thecloud and equivalent mass of TNT to predict explosion overpressures. This was always thought to giveconservativeresults, but recent research evidence indicates that this approach is not accurate to natural gasand air mixtures. The TNT models do not correlate well in the areas near to the point of ignition, andgenerally over estimate the level of overpressures in the near field. Experiments on methane explosionsin"unconfined"areas have indicated a maximum overpressure of 0.2 bar (2.9 psio). This overpressure thendecays with distance. Therefore newer computer models have been generated to better simulate the effects
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 51of real gas and air explosion from historical and experimentalevidence.The criteria selected for an overpressure hazard is normally taken as 0.2 bar (3.0 psio). Although fatalitiesdue to direct effects of an explosion may require up to 2.0 bar (29.0 psio) or higher, significantly lowerlevels result in damages to structures and buildings that would likely cause a fatality to occur. Anoverpressure of 0.2to 0.28 bar (3.0 to 4.0 psio) would destroy a framelesssteel panel building, 0.35 bar (5.0psio) would snap wooden utility poles and severely damage facility structures, and 0.35 to 0.5 bar (5.0 to7.0 psio) would cause complete destruction of houses.Historically, all reported vapor cloud explosions have involved the release of at least 100 kgs (220 lbs.) ofcombustiblegas, with a quantity of 998 kgs to 9,979 kgs (2,200 lbs. to 22,000 lbs.) being the most common.In the United States, OSHA regulations require only processes containing 4,536 kgs (10,000 lbs.) ofmaterial or more be examined for the possibilities of explosions. Additionally the possibilities associatedwith vapor clouds exploding that are 4,536 kgs (10,000 lbs.) or less, are considered very low. Most majorcatastrophicincidentsin the process industrieshave occurred when the level of material released has been ofa large quantity. Generally for vapor cloud explosions that are less than 4,536 kgs (10,000 lbs.), lessdamage occurs than at greater volumes (Le., greater than 4,536 kgs (10,000 lbs.)).A natural gas and air mixture is only likely to explodeif all of the following conditionsare met:(1) A high degree of congestionfrom obstaclescreating turbulence.(2) A large area, allowingthe flamefront to accelerateto high velocities.(3) A minimum flammable mass of 100 kgs (220 lbs.) is generally required flame frontacceleration.It could be argued that vapor cloud explosionsfor hydrocarbon facilities need only be calculated for thosefacilities that contain large volumes of volatile hydrocarbon gases that can be accidentally released andwhere some degree of confinementor congestion exist. The most probable amount for an incidentto occuris taken as 4,536 kgs (10,000 lbs.), however incidents have been recorded where only 907 kgs (2,000 lbs.)has been released. Additionally, an actual calculation of worst case releases to produce 0.2 bar (3 psio) atsay 46 meters (150 ft.), indicates a minimum of 907 kgs (2,000 Ibs.) of material is needed to cause thatamount of overpressure. A limit of 907 kgs (2,000 lbs.) release of hydrocarbon vapor is considered aprudent and conservativeapproach.Boiling Liquid Expanding Vapor Explosions (BLEVE)BLEVE types of incidentsarise from the reduction in yield stress of a vessel or pipe wall to the point that itcannot contain the imposed stresses by the design and construction of the container and are also influencedby the relief valve set point. This results in a sudden catastrophic failure of the containment causing theviolent dischargeof the contents and producing a large intense fireball.Typically a BLEVE occurs after a metal container has been overheated above 538 OC (1,000 OF). Themetal may not be able to withstand the internal stress and therefore failure occurs. The contained liquidspace of the vessel normally acts as a heat absorber, so the wetted portions of the container are usually notat risk, only the surfacesof internal vapor spaces. Most BLEWs occur when containers are less than 1/2 to113 full of liquids. The liquid vaporization expansion energy is such that container pieces have been thrownas far as 0.8 km (1/2 mile) from the rupture and fatalities from such incidents have occurred up to 244meters (800 ft.) away. Fireballs may occur at the time of rupture, that are several meters in diameter,resulting in intense heat exposure to nearby personnel . Fatalities due to burns from such incidents haveoccurred to personnel as much as 76 meters (250 Ft.) away from the point of rupture.
    • 52 Handbook of Fire and Explosion F’rotectionA study of BLEW occurrences in LPG storage vessels ranging from 3.8 to 113 cubic meters (32 to 947bbls) capacity, showed a time range to rupture of 8 to 30 minutes, with approximately 58% occurringwithin15 minutes or less.Smoke and Combustion GasesSmoke is a by-product of most fires caused by the incomplete oxidation of the fuelsuppIy during the chemical process of combustion. It accounts for a large majority offatalities of from fire incidents at both onshore and offshore petroleum facilities In thePiper Alpha incident of 1988, probably the worst petroleum industry offshore life lossincident,the majority of deaths were not fromburns, drowning or explosionimpactsbutfrom smoke and gas inhalation. The report on the incident concluded that, of thebodies recovered from the incident, 83% were as a result of inhalation of smoke andgas. Most of these victims were assembled in the accommodationawaiting evacuationdirectionsor as they may have thought - a possible rescue.Smokes from hydrocarbon fires consist of liquid or solid particles of usually less than one micron in size,suspended in the combustion gases, which are primarily nitrogen, carbon monoxide and carbon dioxide,existing at elevated temperatures. At normal temperatures carbon is characterized by a low reactivity. Athigh combustion temperatures, carbon reacts directly with oxygen to form carbon monoxide (CO) andcarbon dioxide(C02).The main dangers of smoke are the presence of narcotic gases principally carbon monoxide (CO), hydrogencyanide (HCN), carbon dioxide (C02) and the asphyxiating effects of an oxygen depleting atmosphere dueto the combustion process that severely affect human respiration. Inhaling narcotic gases often leads to ahyperventilationand therefore increased inhalation of gases as the breathing rate increases. Narcotic gasesalso cause incapacitationby an attack on the centralnervous system.A low level of oxygen in the brain leads to psychological disorders which cause impaired judgments andconcentration. These effects may confuse, panic or incapacitate personnel. Carbon monoxide poisoningcauses suffocation by blocking transport of oxygen in the blood. Incapacity occurs in less than 10 minuteswith a 0.2% concentration of CO if heavy activities are being performed. Carbon monoxide kills because itcombines with the hemoglobin of the blood, preventing oxygen to bind with the hemoglobin which isnecessaryfor sustained life. Carbon monoxide has an affinityfor hemoglobin 300 times that of oxygen. Thedegree of poisoning depends on the time of exposure and concentration of the gas. If the percentage ofcarbon monoxide in the blood rises to 70% to SO%, death is likelyto ensue.The precise technical name of HCN is Hydrocyanic Acid. The cyanides are true protoplasmic poisons,combining in the tissues with the enzymes associated with cellular oxidation. They thereby render theoxygen unavailableto the tissues, and cause death through asphyxia. Inhaling concentrationsof more than180ppm of HCN will lead to unconsciousnessin a matter of minutes,but the fatal effectswould normally becaused by carbon monoxide poisoning after HCN has made the victim unconscious. Exposure to HCNconcentrationsof 100to 200 ppm for periods of 30 to 60 minutes can also cause death.Inhaling hot (fire) gases into the lungs will also cause tissue damage to the extent that fatal effects couldresult in 6 to 24 hours after the exposure.
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 53Psychologically the sight and smell of smoke may induce panic and disorientation. When this occursmovement of personal to achieve evacuation objectives may be severely inhibited. This is especially criticalwhere personnel are unfamiliar to the facility. Smokewill also hinder fire fightingand rescue efforts.Smoke travel is affected by the combustion particles rise, spread, rate of bum, coagulation and ambient airmovements. Combustion products due to heating by the fire tend to generallyrise becausethey are lighter inweight than the surrounding air. They will spread out when encountering objects such as a ceiling orstructural components. The smoke particulates will readily penetrate every available opening, such ascracks, crevices, staircases, etc. Rate of bum is the amount of material consumed by combustion in anygiven time period. Particle coagulation is the rate at which combustion particles gather into groups largeenough to precipitate out of the air. Coagulation occurs continuously because of the mutual attraction ofthe combustion particles. Air movement will direct smoke particlesin a particularpattern or direction.Currently a mathematicalmodel for the dispersion of smoke plumes from hydrocarbonliquids is unavailable,but dispersionmodels for combustion gases may be used as a rough comparison. At close distancesto a firethis is provides a reasonable approximation, since the solid particles tend to be entrained in the combustiongases. However gases tend to disperse much more readily in the ambient air than solid particles, so thistechnique is not suited to predict extremely long smoke plumes generated from hydrocarbon fires.Additionally ambient atmosphericconditions at the time of an incident will greatly influence the dissipationor collection of smoke partjculates. For interior locations, smoke generation from hydrocarbon fires isassumed to completelyfill the enclosure.Whenever the effects of smoke will affect personnel adequate respiratory protection must be provided, suchas smoke resistant barriers and fresh air supplies.Mathematical ConsequenceModelingThe use of computers for rapidly and easily estimating the effects from explosion,fire, and smoke events has grown tremendously in the last several years.Specializedrisk consultants and even insurance risk ofices can now offer a varietyof software products or services to conduct mathematical consequencemodeling ofmost hydrocarbon adverse events. The primarily advantage of these tools is thatsome estimate can be provided on the possible effects of an explosion or fireincident where previously these effects were rough guesses or unavailableAlthough these models are effective in providing estimate they still should be usedwith caution and consideration of other physical features that may alter the realincident outcome,All mathematical models require some assumed data on the source of release for a material. Theseassumptionsform the input data which is then easily placed into a mathematicalequation. The assumed datais usually the size or rate of mass released, wind direction, etc. They cannot possibly take into account allthe variables that might exist at the time of the incident. Unfortunately most of the mathematical equationsare also still based on empirical studies, laboratory results or in some cases TNT explosion equivalents.Therefore they still need considerableverification with tests simulationsbefore they can be fully accepted asvalid.
    • 54 Handbook of Fire and Explosion ProtectionThe best avenue is to use input data that would be considered the WCCE for the incident under evaluation.One should then question if the output data provided is realistic or corresponds to historical records ofsimilar incidents for the industry and location. In other cases where additional analysis is needed, severalrelease scenarios (small, medium and large) can be examined and probabilities can be assigned to eachoutcome. This would then essentiallybe an Event Tree exercise normally conducted during a quantitativerisk analysis. Certain releases may also be considered so rare an event they may be outside the realm ofaccepted industry practical protective requirements.Somereadily availablecommercialconsequencemodels includethe following:Gas discharge from an orificeGas dischargefrom a pipeLiquid dischargefrom an orificeLiquid dischargefrom a pipeTwo-phase dischargefrom a orificeTwo-phase dischargefrom a pipeAdiabaticexpansionLiquid "pool"spill and vaporizationVapor plume riseJet dispersionDense cloud dispersionNeutrally buoyant dispersionLiquid "poolrrfireJet flameFirebalVBLEVEVapor cloud explosionblast pressuresIndoor gas build-upFrom the estimatesof fire or explosion exposures,the effectivenessof various fire protection systems can beexamined or compared, e.g., heat absorption of deluge water sprays at various densities, fire proofing atvariousthicknessesor types of materials, etc. Some cases of theoretical fire modelinghave proven very costeffective, by demonstratingfor example that fireproofingwas not beneficial to the subject application sincethe heat transmission to the area was not high enough to weaken the steel to its unacceptable failure point.For offshore structures this is vitally important, not only for cost savings but for topside weight savingsobtainedby decreased amounts of fireproofinginstallation requirements.
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 55Methods of Flame ExtinguishmentIf any one of the principle elements of the combustion process cam be removed from a fire, it will beextinguished. The principlemethods of extinguishmentare discussed below.Cooling (water spray, water injection, water flooding, etc.)Removing heat from or cooling a fire absorbs the propagating energy of the combustion process.When the fuel is lower below its ignitiontemperature results in extinguishmentof the fire. For liquidhydrocarbon fires it also slows and eventually stops the rate of release of combustible vapors andgases. Cooling by water also produces steam, which may partially dilute the ambient oxygenconcentrationlocalto the fire point. Because heat is continuallybeing released by the fire in the formof radiation, convection and conduction it is only necessary that a small amount of a heat absorbingcommoditybe applied to the firein order for it to be extinguishedby coolingmeans.Oxygen Depravation (steam smothering,inerting, foam sealing,C02 application, etc.)The combustion process requires oxygen to support its reaction. Without oxygen the combustionprocess will cease. The normal oxygen level in the atmosphere is approximately 21 percent(approximately20.9 % Oxygen, 78.1%Nitrogen, 1% Argon, C02 and other gases). Combustion ofstable hydrocarbon gases and vapors will usually not occur when the ambient oxygen level is loweredto below 15 percent. Acetylenewhich is an unstable hydrocarbon,requires the oxygen concentrationto be below 4 percent for flame extinguishment. For ordinary combustibles (wood, paper, cotton,etc.), the oxygen concentrationlevelsmust be lowered to 4 or 5 percent for total fire extinguishment.If sufficient amounts of a diluent are added until the oxygen is displaced, the combustionprocess willbe terminated. For some suppression methods, oxygen is not removed from a fire but merelyseparatedfrom it.Fuel Removal (Foam sealing,isolation, pump-out, etc.)If the fuel is removed or consumed by the subject combustion process, no more fuel supplies will beavailable for the combustion process to continue and it will cease. In some cases, a fuel is notliterallyremoved from a fire, but is separated from the oxidization agent. Foam suppressionmethodsare good examples where the a barrier is introduced to remove the fuel from the air @e.,oxidizer).Storage tanks and pipeline fires can use pump-out methods and inventory isolation, respectively, asmethodsof fuel removal.Chemical Reaction Inhibition (Halon, Inergen, etc., applications)The chemical chain reaction is the mechanismby which the fuel and oxidizingagents produce fire. Ifsufficient amounts of a combustion inhibiting agent (e.g., Dry Chemical agents or HalogenatedHydrocarbon agents) are introduced the combustion process will stop. Chemical flame inhibitioninterrupts the chemical process of combustionby inhibitingthe chain reaction.Flame Blow OutFlame extinguishment can be accomplished dynamically through the combined action of oxygendilution and flame blow-out or application of rapid ambient air velocity such as when a candle isblown out. It is achievedwhen the ambient air velocity exceedsthe flame velocity. Techniques suchas these are applied during specialized well blowout control measures. The detonation of a highexplosive results in a pressure wave that "blows out" the wellhead fire by separatingthe flame fromthe available combustible gas. Some specialized apparatus is also available that uses jet engines toliterary "blowout" wellhead fires. Thesejet enginedeviceshave been used to control blowouts in theRussian oil industry and severalwellhead fires in the aftermathof the Gulf War.
    • 56 Handbook of Fire and Explosion ProtectionSelection of Fire Control and Suppression MethodsThe method of fire incident protection, control and suppressioncan be generally determined by reference toNFPA 325M, "Fire Hazard Properties of Flammable Liquids, Gases and Volatile Solids". This referenceprovides a basic guideline to determine the most effective protection method to apply for an emergencysituation. Although this guide is a gross oversimplification of the type of incident and configurations thatmay be involved, it does provide a starting point and supporting documentation to justify the selection of aparticular fire protection, control and suppressionmethodology to a hydrocarbon facility .The first step in this methodology is to fully identiry the type of materials that may be present during the fireincident. Once this is known a Fire Risk Hazardous Zone should be identified which is the most probablelocation of the fire. This is typically the enclosedareaofa spillage or liquid runoff areasat a vessel,pump ortank. Based upon isolatable inventories or risk analysisconsequential modeling, the drawing can be furthersubdivided into specific levels of Fire Risk Hazardous Zones for the duration of fire events. Reference toNFPA 325M can then be made to determine what is the optimum fire protection, control and suppressionmethod to apply. The duration or fire resistanceof the fire protection option can also determined. Once thisis accomplished, suitable fixed passive or active protection equipment and ratings or capacities can bedesigned or specified. The need for primary process safeguards (ESD, isolation, depresurization, andblowdown), can also be determined or reconfirmed. Process safeguards should always be considered theprimary loss prevention system for any process facility and fire protection measures are backups orsecondaryprotection systems.The easiestway to document the selection process is to prepare a table of the materials involved and therequired extinguishing methods. Tables 3 and 4 provide examples of documentation that is prepared in theindustry .Fire Risk Hazardous Zone drawings are prepared using published literature on commodity hazardsand extinguishing methods (Ref. NFPA 325M).Table 3Fire Hazard Zone Identification Example
    • Characteristics of Hydrocarbon Releases,Fires and Explosions 57Table 4Fire Extinguishing Explanations, Fire Hazardous Zone Drawings
    • 58 Handbook of Fire and Explosion ProtectionTerminology of Hydrocarbon Explosions and FiresThe following terminology is used in the description of the various fires and explosionsthat can occur at ahydrocarbonfacility.Blast - Is the transient change in gas density, pressure, and velocity of the air surrounding anexplosionpoint.Blowout - A blowout is a high pressure release of hydrocarbons, which may or may not ignite, thatoccurs when a high pressure oil or gas accumulation is unexpectedly met while drilling and the mudcolumnfails to containthe formationfluid that is expelledthrough the wellhead bore.Boiling Liquid Expanding Vapor Explosion (BLEW) - Is the nearly instantaneous vaporizationand corresponding release of energy of a liquid upon its sudden release from a containment undergreater than atmosphericpressure and at a temperature above its atmosphericboiling point.Deflagration - Is a propagating chemical reaction of a substancein which the reaction front advancesinto the unreacted substancerapidly, but at a lessthan sonicvelocity in the unreacted material.Detonation - Is a propagating chemical reaction of a substance in which the reaction front advancesinto the unreacted substanceat greater than sonicvelocity in the unreacted material.Explosion - Is a release of energythat causes a blast.Fireball - Is a rapid turbulent combustionof a fuel-air cloud whose energy is emitted primarily in theform of radiant heat, usually rising as a ball of flame.Flash Fires - Is a fire resulting from the ignition of a cloud of flammablevapor, gas or mist in whichthe flame speed does not accelerate to sufficiently high velocities to produce an overpressure,because there is not suficient congestion or confinement present to produce a high velocity flamespeed.Implosion - Is an inward rupture normally caused by vacuum conditionsin a vessel or tank.Jet or Spray Fires - Are turbulent diffusion flames resulting from the combustion of a liquid or gascontinuously released under pressure in a particular direction.Overpressure - Is any pressure relative to ambient pressure caused by a blast, both positive andnegative, sometimesreferred to as "psio".Running Fire - Is a fire from a burning liquid &el that flowsby gravity to lower elevations. The firecharacteristicsare similarto pool fires except it is moving or drainingto a lower level.Ruptures or Internal Vessel Explosions - An catastrophic opening of a container (i.e., tank, vesselor pipe), commonly from overpressure or metallurgical failure, resulting in the immediate release ofits contents.Smoke - The gaseous products of the burning of carbonaceous materials made visible by thepresence of small particles of carbon, the small particles which are of liquid or solid consistency, areproduced as a by product of insufficientair suppliesto a combustion process.Spill or Pool Fire - Is a release of a flammable liquid and or condensed gas that accumulates on asurface forming a pool, where flammable vapors burn above the liquid surface of the accumulatedliquid.
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 59Vapor Cloud Explosion (VCE) - Is an explosion resultingfrom the ignition of a cloud of flammablevapor, gas or mist in which the flame speed acceleratesto produce an overpressure.
    • 60 Handbook of Fire and Explosion ProtectionCommodity PoolExplosion Jet SmokeFire FireMethaneLNGEthanePropaneButaneLPGCrude OilGasolineDieselTable 5X XX X XX XX XX XX X X XX X XX X XX XGeneral Hazards of Common Petroleum Commodities(Under typical process operations and conditions)
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 611.2.3.4.5.6.7.8.9.BibliographyA. D. Little, Inc.,ADL FlRST Facilitv Risk Screenin? Tool, AD. Little, Cambridge,MA, 1992.American Petroleum Institute (API), Publication 4545. Hazard Response Modeling Uncertainty (A OuantitativeMethod): Users Guidefor Softwarefor Evaluatin?HazardousGas Dispersion Models, Volume 1, API, Washington,D.C., 1992.American Petroleum Institute (API), Publication 4546. Hazard Response Modelinp Uncertaintv (A OuantitativeMethod):Evaluationof Commodv Used HazardousDispersionModels, Volume2, API, Washington, D.C.: 1992.American Petroleum Institute (API), Publication 4547, Hazard Response Modeling Uncertainty (A OuantitativeMethod): Components of Uncertainw in Hazardous Gas Dispersion Models, Volume 3, API, Washington, D.C.,1992.DNV Technica.Ltd. WHAZAN 11, DNV Technica,London,U.K.Dugan, Dr.K., UnconfinedVapor Cloud Explosions,Gulf Publishing, Houston, TX, 1978.Kreith,F., Principles of Heat Transfer,International TextbookCompany, Scranton,PA, 1965.NationalFire ProtectionAssociation(NFPA),Fire Protection Handbook, 17thEdition,NFPA, Quincy,MA, 1991National Fire Protection Association (NFPA),NFPA 325M, Fire Hazard Prooerties of Flammable Liquids. Gases,and Volatile Solids,NFPA, Quincy, MA, 1991.10. SedgwickEnergy, "Loss ControlNewsletter", SedgwickEnergyLimited, London,U.K. Issue 1,1994.11. Society of Fire Protection Engineers (SFPE), Handbook of Fire Protection Engineering, First Edition, NFPA,Quincy,MA, 1988.12. Stull, D. R., Fundamentalsof Fire and Explosion,The Dow Chemical Company, AIChE, New York, NY, 1976.13. Tunkel, S. J., "Methods for Calculation of Fire and Explosion Hazards", AIChE Today Series, AIChE. New York,NY, 1984.
    • Chapter 6Historical Survey of Fire and Explosionsin the Hydrocarbon IndustriesHistorical records show that there were many fires during the inception of the oil industry that unfortunatelycontinue until today. The general trend is of an ever increasing financial impact. Figure 2 graphicallyportrays the U.S. Dollar amounts of the average of the single major losses for the last several decades. Ascan be readily seen the recent amounts have risen dramatically from past decades and can be financiallydisastrousin real dollar terms.There is a great benefit from reviewing accident data, since we can learn from past mistakes and makedesign improvements. However when analyzing accident data, only the most relatively recent data availabIestatistics and descriptions should be used. Technological improvements and management controls arecontinuallyimproving so that the comparisonsof data from historical records of say, over 15to 25 years old,it may be of little technical value. Although the general categories of loss mechanismsmight be useful fromsuch outdated data, overall the precise data cannot be compared directlyto todays operating environment.Caution must also be used when comparing loss data from different geographicaland political environments.Environmental, cultural and technological differences will influence how a facility is designed and operated,so that direct comparisons to one another cannotbe made.The National Fire Protection Association ("A) and the insurance industry are the most available anddescriptive sources of accident data for the petroleum industry. The Occupational Safety and HealthAdministration (OSHA), collects data on injuries and fatalities and does some inspections, but generallyundertakes no analysisof the causes of fires and explosionsin the petroleum industry. It rather determines iffederal laws are broken and assigns a fine. In fact there is essentially no national (or international)governmental data bank availablewhere fire and explosion incidentsfrom the entire petroleum, chemical orrelated industriesare logged or analyzed. The National Transportation Safety Board (NTSB) investigatesmajor incidents associated with transportation incident, i.e., pipelines, ships, and railroads in the U.S. TheFederal Aviation Administration (FAA) investigatesand analyzes aircraft accidents. The MMS periodicallypublishes brief offshore incident historical data for the U.S.continentalshelf. Insurance agencies such as M& MPC, Sedgwick Energy, and a few others have published comprehensive lists of onshore and offshoreincidents that have become known to them. They have undertaken to perform trend analysis and areconstantly refining the methods used determine the causes and probable consequencesof an incident. Withthese reviews methods of mitigation and protection are evolved. Insurance rates and coverages are alsoformulatedfrom this data.The insurance industry as a whole has a substantial self interest in analyzing accidents, sponsoring researchand issuingpublications in the methodsto prevent accidents or mitigate their effects. Hence their data is the62
    • Characteristics of Hydrocarbon Releases, Fires and Explosions 63most usefbl and more readily available. Because of their own self interest, their recommendations aresometimes considered overzealous, however the petroleum industry has typically not provided the evidenceto prove that their concerns are unduly precautions. Much of the petroleum industry is rather reluctant topublicly divulge such information. Public outcry to have a governmental review and analysis of petroleumincidents is essentially nonexistent. This is probably due to the generally low level of fatalities and theperceived low level of public exposure to hydrocarbon incidents. Since petroleum and chemical industriesgenerally do not directly expose the public, governmental oversight has generally not been necessary.However where such circumstances do not prevail, public oversight may be mandated, as environmentalregulationshave amply demonstratedand the ever increasing magnitude of catastrophic incidents indicates.Nowadays all operating oil companies have considerable legal constraints in divulging information publiclywhen injuriesand property damageare or could be under litigation. Hence much of the relevant information(except for the major incidents during legal request) is not circulated or generally released by the operatingcompanies. They also probably have a concerted or maybe a subconsciousdesire to portray their operationsas safe in order to achieve a lower cost of insurance and achieve a more public acceptance of oil and gasoperations. As anyone in the petroleum industry will confidentiallytell you, not all incidents that occur atfield installations are mentioned or reported and it is probably facetious to think otherwise. This is due tothe business and social pressures that exist to achieve a high production rate, safe man-hour awards,promotions, peer pressures, fear of reprimand, etc. In real life, very little incentives exist to report incidentsin a company other than it may be difficult to deny if physical damage or injuriesresult. The system basicallyresorts to personal honesty. In other cases where the incident is reported, it may be described in such afashionthat it may not be recognized for the risk that it was or could represent.Relevancy of IncidentsIn reviewing accident histories, remember that the technology and operating practices employed in earlierdecades have changed tremendously to the current date and are likely to do so in the fbture. The latestcontrol technology continuously improves operating practices and may also lower manpower requirements.In practice only the last ten years or so of loss histories are generally examined for relevancy to the currentoperating environmentsof most hydrocarbonfacilities.Similarly, only loss histories that can be directly related to the facilityunder review should be studied. Notonly should the type of facilitybe examined for applicability(e.g., refinery versus refinery), but the ambientconditions in which the facility exists should be considered. For example, an oil production facility inNorthern Siberia should not be thought of as having a similar operating environment as the jungles of Peru,either due to the environmental conditions, technology availability or political influences. The Gulf ofMexico cannot be applied to the North Sea, however it could have similaritieswith the Arabian Gulf or theSouth China Sea. Ideally the best loss history is from the facility itself, since every location has its owncharacter and operating practices. For entirely new facilitiesthe closest representationhas to be chosen.
    • 64 Handbook of Fire and Explosion Protection1950 1970 1990DateFigure 2Historical Average Financial Loss for Major Incidents
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 65The following is a brief selective listing of major worldwide fire and explosion incidents within thehydrocarbon and chemical industries during the fast 25 years (I970 - 1994), both onshore and offshore.Numerous smaller incidents have been recorded that are not listed here but may be studied in otherrefaences. Where the number of fatalities has been reported in public accounts they are listed next to thefinancial loss. Financial losses are direct property damage losses and do not include business interruption,legal, or environmental impacts.1970-01.06.70South China Sea, Blowout, ExplosioflireDrillingbarge struck shallowgas followed by explosionand fireball7 Fatalities,extensivedamage to drillingbarge02.10.70Gulf of Mexico,Main Pass Block 41,Platform C, FireUnmmed automatedplatform,causeof accident &own.3 Relief wells extinguishedfire.Totalplatform lost.05.28.70Gulfof Mexico, GalvestonIsland Block 189,Platform A, ExplosionRireOffshoreOil StoragePlatform Fuel Tank Explosiondueto welding on piping connected totanks stillcontainingoil9 Fatalities09.17.70Beaumount TX, USA, Refinery, FireLighting struck slop oil tanklack of intermediatediking let fire spreadto other tanks$6,500,00011.11.70Tulsa, OK, USA, Wellhead, ExplosionExperimental Test for Reservoir Perforationusing liquidexplosive9 Fatalities12.01.70Gulf of Mexico, South Timbalier Block 26, Blowout, ExplosiodFire2 drillingrigs conducting wirelineoperations at fixedjacketplatform4 Fatalities,Platform and two drillingrigs a total loss12.05.70Linden, NJ, USA, Refinery, ExplosionRireFailureof hydrocracker unit reactordueto localized overheating$27,173,000 loss1971-01.11.71English Channel, Natural Gas Tanker,ExplosionEireShipcollided with anothervessel8 Fatalities,Tanker sank01.21.71Mediterranean Sea,Oil Tanker, Fire/Explosion39 Fatalities02.11.71
    • 66 Handbook of Fire and Explosion ProtectionNewark, NJ, USA, Chemical Plant, ExplosionsTwo Chemical plants demolished4 Fatalities02.26.71Longview, TX, USA, Chemical Plant, ExplosionEireDrain fittingfailed at compressorVapor released and ignited from exhaustof engine drivencompressorresultinginexplosion.4 Fatalities,$5,600,000loss.05.26.71Bayport,TX, USA, Chemical Plant, ExplosionlFireExplosionshortlyafterplant turnaround caused impact to incoming power and fire water system$4,500,000loss10.13.71OffshorePeru, DrillingBarge, ExplosiodFireBlowout incident.19Fatalities10.16.71Gulfof Mexico, Eugene Island Block 215,Platform B, Blowout/Explosion/Fire4 Relief wells drilledtoextinguishfire.Production platform lost.1972-02.29.72Delaware City DL, USA, Refinery, FireHot Oil transferline failure,lack of ESD capability$6,002,000 loss.03.30.72Rio de Janeiro,Brazil,Refinery, ExplosionlFireDrain valve of LPG tank left open formingvaporcloud, which exploded,Most ofrefinery damaged37 fatalities,$4,800,000 Loss.05.11.72AtlanticOcean, Oil tanker,FireVessel collided with another in fog and fireerupted83 fatalities,vesselstotal loss08.14.72Billings,MT, USA, Refinery, ExplosionlFireLack of adequatepiping isolationduringmaintenance1Fatality,$5,000,000 loss08.21.72AtlanticOcean, Oil Tanker,ExplosionEireVessel collided with anotherin fog and explosionoccurred50 Fatalities10.25.72CarteretNJ, USA, Barge,ExplosionEireOil barge undergoing loadingoperations$5,000,000 loss
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 671973-01.06.73Bayonne, NJ, USA, Refinery FireLeaking pumpreleasedfuel oilwhich was ignitedby nearby welding and spreadto othertanks.$4,300,000loss02.10.73StatenIsland, NY, USA, LNG StorageTank, ExplosiodFireTank was undergoing refurbishmentfor an internaltom lining40 Fatalities,$14,000,000 loss03.30.73Hong Kong Harbor,Oil Tanker, FireVesselcollided with another and fireensued3 Fatalities07.05,73Kingman,AZ,USA, Railroad Propane tank, BLEVELeaking transfervalveignited when struckwhile tightening13 Fatalities07.08.73Tokuyama, Japan, Chemical Plant, ExplosionEireChemicalprocessupset dueto instrumentationfailurecausedflangefailureI fatality, $1 6,000,000loss07.13.73Potchefstrwm, S.Africa, Chemical Plant, ExplosionBrittle failureof the dishedend of a 50 tonhorizontalpressurevessel released anhydrous ammoniavapors which causedthe explosionto occur.I8 Fatalities08.24.73St. Croix,VI, Refinery FirePipelineweld failure$10,500,000loss10.08.73Goi, Japan, Chemical Plant, ExplosionEireOperatorerrorreleasedvaporsto open vesselunder maintenance.1 Fatality,$7,000,000loss1974-01.31.74SouthChina Sea, Champion 41, Blowout, FireFailureof subsea weUhead,jacket severely damaged04.10.74Philadelphia,PA, USA, Tanker, ExplosionEireIncident occurred duringunloadingof crude oil.$8,l09,000 loss06.01.74Flixborough,UK, Chemical Plant, ExplosionFailureof a temporary pipe installedtwo monthsbefore as a reactor bypass.28 Fatalities, $180,000,000loss08.25.74
    • 68 Handbook of Fire and Explosion ProtectionPetal, MO, USA, Salt Dome Butane Storage,ExplosionOverfillingof storagewell createdvapor cloud.11.11.74Tokyo Bay, Japan, Gas Tanker, Explosion/FireLiquefied tanker vessel collided with freighter33 Fatalities,Tanker sunk.11.29.74Beaumont, TX, USA, Chemical Plant, ExplosionFireFailureof pump expansionjoint inlet.$13,300,0001975-01.31.75Marcus Hook, PA, USA, Tanker,ExplosiodFireTanker was rammed by a chemical tankervessel which loss control.$7,837,000 loss02.10.75Antwerp, Belgium, Chemical Plant, ExplosionEireFailureof vent connection on suctionsideof a compressor.6 Fatalities, $28,325,000 loss03.16.75Avo4 California,USA, Refinery, ImplosionEireOperatorsincreased pump out rate to vessel creatinga vacuum and implosion. Loss of instnunentationcaused a secondfire elsewhere in the facility to occur.$10,374,000 loss04.05.75Iford,Essex,UK, Chemical Plant, ExplosionLeakage of a hydrogen into an oxygen drum caused an explosion to occur in an electrolysisplant, resultingin extensivedamage to the facility.1Fatality08.04.75Texas, USA, Chemical Plant, ExplosionFire$1,500,000loss08.17.75Philadelphia,PA, USA, Refinery, ExplosiodFireStorageTank ExplosionTankoverfillingcaused high vapor release,ignitionresult fromcontactedwithhot surface.8 Fatalities, $13,000,000 loss10.14.75Avon, CA, USA, Refinery, FireLack of inspectionof plug on pump caused leakage, lack of ESD valve activationdue to instrumentationfailure.$6,307,000 loss.11.07.75Beek, Netherlands,Chemical Plant, ExplosionLevel controllerallowed cold liquidto enter pipe causingmetallurgical failureof 1.57inch pipe connection to a feeddrumreleased vapors ignited by furnace14Fatalities, $22,892,000 loss
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 6912.30.75Pacific Ocean, Supertanker,Explosion224,000 ton vesselloss after explosionsoccurred and vessel sunk.30 Fatalities,Insurance claims of $27million.1976-05.24.76Geuismar,LA, USA, Chemical Plant, ExplosiodFireLoss of instrumentationcausechemical reaction upset and explosionwithin the reactoroccurred.$8,875,00007.18.76Big Spring,TX, USA, Refinery, ExplosiodFireTank bending by use of air igmted and spreadwithin the refinery.$6,715,000 loss08.12.76Chalmette, LA, USA, Refinery, ExplosionExplosionin 30 storyrefiningtower13Fatalities08.30.76Plaquemine LA, USA, Refinery, ExplosiodFireInternal vessel failurecaused explosionin storagetank$12,000,000 loss12.17.76Los Angeles Port, USA, Tanker,Explosion70,000 dut tanker refuelingat time of incident, cargotanks not inerted and no vapor recovery systeminstalled. Ignitionbelieved frompump performingballastingoperation.9 Fatalities,$12,000,000 loss.02.24.77PacificOcean, Tanker,ExplosionEireTanker structuralfailure1Fatality, 846 foot Tanker was a total loss and 30 million gallons of oil.03.xx.77Port Arthur, TX, USA, Refinery, FireTexaco, Inc.03.xs.77Fort Arthur, TX, USA, Refinery, Explosion/Fire8 Fatalities04.03.77Umm Said, Qatar, Refinery, FireMassivemetallurgical weld failureof liquidpropane tank$76,350,000 loss05.11.77Abqaiq, SaudiArabia, Pipeline, FireMetallurgical failureof buried pipelinethat spread intoprocess area, lack of automaticplant processEIVs.6 Fatalities,$54,000,000loss and resulted30% reduction in crude oil sales until facility replaced.06.04.77
    • 70 Handbook of Fire and Explosion ProtectionAbqaiq, Saudi Arabia, Pipeline, ExplosionEireFailure of fuel gas line resultingin a vapor cloud$10,600,000 loss07.08.77Pump station# 8, Alaska, USA, Pumphouse, ExplosionEireOil flowfrom valve not isolatedduringmaintenance, ignited by turbineheat1Fatality,$39,610,000 loss09.24.77Romeoville,IL,USA, Refinery, ExplosionEireCone roof storagetank of dieselstruck by lightningresultedin internalexplosiodfire which spread to othertanks.$8,000,000 loss10.18.77Palmyra, MO, USA, Chemical Plant,ExplosionlFireStartupof plant resultedin a detonationoccurringin the reactor$16,100,000 loss12.08.77Logan Township,NJ. USA, StorageTank, ExplosionEireRollins Environmental Services5 Fatalities12.08.77Brindisi,Italy, ChemicalPlant, ExplosiodFireGasreleased occurred and explosion and firesresulted.$28.2 80,00012.16.77AtlanticOcean, Cape of Good Hope, Tankers,FireTwocrudeoil supertankers(each 330,000dwt.)collided and fireoccurredFiresextinguishedand vessels salvaged.1978702.12.78Waverly, TN, USA, RailroadTank Car, ExplosionEireballLPG tank car derailed,explosionoccurringduringpropane transferoperations12 Fatalities04.13.78Calument City,IL, USA, Chemical Plant, FireReactor unit fue.$12,575,000 loss04.15.78Abqaiq, SaudiArabia,Production Facility, ExplosiodFireMetallurgical failureof pipeline$53,700,000 loss05.30.78Texas City, TX, USA, Refinery, ExplosionEireUnidentified releasein tank farm lead to storagetank fues and BLEVEs7 Fatalities,$31,079,000loss72
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 7110.03.78Denver, CO, USA, Chemical Plant, ExplosioflireFollowingstartupreboiler failed and gas released causingexplosionto occur.10.30.78Piteti,Romania, Refinery, ExplosiodFireFailure of pipingreleasing vapors and causingan explosion1979-01.08.79Bantry Bay, Ireland, Tanker, ExplosioflireStructuralfailureof 121,000dwt. Crudeoil tanker during incorrect ballastingled to a release of contents resulting inexplosionsand fires.50 fatalities,$20,566,000loss03.05.79Gulf of Mexico, SouthMarsh Island, Block 281, PlatformC, Blowout, ExplosioflireUnable to closedrill stem safety valve or stand pipe valve, relief valve on mud pump released gas.8 Fatalities,Estimated loss of $2,500,00003.20.79Linden, NJ, USA, Refinery, ExplosioflireFailure of a dead leg pipingreleased vapors$17,500,00004.19.79Port Neches, TX, USA, Tanker,Explosioflire124,000dwt. crude oil tanker struckby lighting after unloading.$32,000,00006.03.79Gulf of Mexico, IxtocWell, Wellhead, Blowout/Fire07.19.79Caribbean Ocean, Supertanker, CollisioflireTwofully loaded crude oil supertankerscollide1fatality,Loss estimated at $150million07.21.79Texas City, TX, USA, Refinery, ExplosionlFireFailure of piping elbow in process unit.$24,000,000 loss08.30.79Good Hope, LA, USA, Barge, FireCargo shipcollided with barge rupturingbutane storagethat ignited$10,500,000 loss09.01.79Deer Park, TX, USA, Refinery, ExplosionlFireLighting stormstruck 70,000 dwt. distillatetanker causinginternal hold explosionsand a 80,000barrel coneroof ethanoltank which startedon fire.$68,000,000loss11.15.79Ponce, PR, USA, Refinery, FirePump failurereleased liquids which ignited.
    • 72 Handbook of Fire and Explosion Protection$10,000,000 loss12.11.79Ponce, PR, USA, Chemical Plant, ExplosionEireVessel failed causingexplosionand fire.,extensivedamageto neighboringplant$15,000,000 loss12.11.79Geelong, Australia,Refinery, FirePump bearing failurereleased crudeoil$11,236,000 loss.1980-01.17.80OffshoreNigeria, Semi-submersible,FireGas FireEstimated 180+fatalities01.20.80Borger, TX, USA, Refinery, ExplosionEirePipeor vessel failurereleased vaporcloud$36,000,000 loss02.26.80Brooks, AK, USA, PipelineCompressor Station,ExplosionEireValve rupturecausingrupture andjet fues which were fed fiornnext station 15miles away.$40,000,000 loss03.24.80Gulf of Mexico, High Island Block A-368, Platform A, Blowout, ExplosionlFireBOP activated,diverter valve closedand hoseruptured6 Fatalities,Platform total loss.05.07.80Deer Park, TX, USA, Refmery, FirePumpseal failurereleased liquidswhich ignited.$29,000,000 loss06.26.80Sydney, Australia,Refinery, Explosioflirehcident OcCuITed duringstartupof facilityafter a shutdown07.23.80Seadrift,TX, USA, Refinery, ExplosionEireInstrumentation failurecaused process upset initiatinginternaldetonationreleasingcombustibleliquids$11,800,000loss08.21.80Gulf of Mexico, Eugene Island 361A, Fire20,000 dwt. gasolinetanker collided with unmarked recently installedjacket. Severedamage to vessel andjacket08.30.80Gulf of Mexico, Matagorda island, Block 669. Blowout, ExplosiodFireAnnular preventer failed,closed pipe rams, casingpipe failed at 7,200psi.5 Fatalities, $30,000,000 loss.
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 7310.21.80New Castle, DE, USA, Chemical Plant, ExplosiodFireReleaseof flammablevaporsfrompipingdueto inadequateisolatiodmaintenance. Explosionimpactedfiresuppressionsystem.$45,750,000 loss12.20.80Ft. McMurray, AK, USA, Oil SandsPlant, FirePossiblehydrateformationin the compressorsecond stagedischargecausingpipingrupturedue to blockage.$9,000,000 loss12.31.80Corpus Christi, TX, USA, Refmery, FireMetallurgical failureof laminated reactor vessel released vapors.$17,000,000 loss.1981-02.11.81Chicago Height, IL,USA, Chemical Plant, ExplosionEireImproperoperatingprocedurecause a chemical process upset resultingin a tank boilover and vapor release. Explosionimpacted fire suppressionsystemcapability.$14,000,000008.20.81Shuaiba,Kuwait, Refinery, FireTank caught fire with spreadto other tanks, causeunknown.$50,000,000 loss1982-01.20.82Ft. McMurray, AK, USA, Oil Sand Plant,FireLube oil fire at compressor.$21,000,000 loss.03.09.82Philadelphia,PA, USA, Chemical Plant,ExplosionEireRelease of combustiblechemical vapors to atmosphereduringprocess upset. Explosionimpacted capabilityof the fuesuppressionsystem.$25,000,000loss.03.31.82Kashima, Japan, Refmery, FireHydrogen embrittlementcaused piping failure$13,800,000 loss04.18.82Edmonton, AK, USA, ChemicalPlant, ExplosionEirePipingfailureat compressordue to vibrationinduced stress. Combustiblegas detectionsystem inoperability contributedto loss.$21,000,000loss08.19.82Osaka, Japan, Chemical Plant, ExplosionEireProcess upset from power intenuptioncaused reactorexplosionadditionatmosphericreleasenext day which resulted inexplosion.$10,000,000 loss
    • 74 Handbook of Fire and Explosion Protection10.04.82Freeport,TX, USA, Chemical Plant, ExplosiodFireOil filledtransformerfailedresultingin a firewhich spread intothe process plant.$14,700,000loss.10.21.82Gulfof Mexico, Eugene Island,Block 361, Platform A, Blowout, ExplosiodFireAnnular preventer leaked.Drilling rig and quarters destroyed.01.07.83Newark, NJ, USA, Bulk Plant, ExplosiodFiretank overfilledspillingliquid and causingvapor cloud to form. Explosioncaused damagetootherpropertiesandadjacent tanks.$35,000,000 loss.04.07.83Avon, CA, USA, Refinery, FireRuptureof a sluny line in a FCC unit which ignited.$48,950,000 loss04.14.83Bontang, India, LNG Plant, RuptureRireRelief header isolationvalveleft closed duringplant startupcaused a heat exchangerto rupture.$50,000,000 loss08.30.83Miford Haven, Wales,UK, Refinery, FireFloatingroof tank seal area ignitedfromflarecarbonparticles from350 foot away$15,000,000 loss10.13.83Gulf of Mexico, East BreaksBlock 610, PlatformA, Blowout, FireDiverter lineruptured.Extensive damage to two drillingrig and platform10.20.83Gulf of Mexico, Eugene Island Block 10,Blowout FireSafetyvalve leakedExtensive damage to rig.1984-02.25.84Sa0 Paulo, Brazil, Pipeline, FirePipelineruptured in the vicinity of a shantytown releasing700 tonsof gasoline.508 Fatalities03.08.84Kerala, India,Refinery, ExplosiodFireLeakmg heat exchangersreleasedvapors which ignited.$12,000,000 loss07.23$4
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 75Romeoville, IL, USA, Refinery, ExplosiodFireBLEVEsCircumferencial weld crack leaded propane which ignited resultingin a vapor cloud. Resultingexplosion and firesseverely damaged facility.$127,000,000loss0815.84Ft. McMurray, Alberta, Canada,Refinery, FireErosionfailureof a pipelinereleased liquidsnear autoignitiontemperature. Vapors spread and ignited causingseveredamage to the facility$76,000,000 loss08.16.84South Atlantic,Offshore Brazil,Enchova 1,Blowout, ExplosiodFireGasreleaseduringdrillingoperations.42 Fatalities09.30.84Basile,LA, USA, Gas Plant, Explosion/FireFailureof a drain lineconnection allowedvapor release and explosionto occur.$30,000,000loss09.14.84Gulf of Mexico, Green Canyon, Block 69, Blowout, FireReopened BOP and released gas4 Fatalities, $15,000,000loss.11.19.84Mexico City, Mexico, LPG Plant, Explosion/Fire/BLEVE8 inch linerupturedreleasingcontentsthat ignitedand spreadto process area.Firewater system was impacted frominitialexplosion.550 Fatalities,$19,900,000 loss12.13.84Las Pedras, Venezuela, Refinery, fireLine failuredue to vibrationinduced metal fatiguereleased hot oil under highpressure which ignited and spreadto otherportionsthe plant.$62,076,000 loss01.23.85Wood River, IL, USA, Refinery, ExplosiodFireDead linecontainingpropane frozerupturingpipe which releasedhydrocarbons$29,400,000 loss05.19.85Priola,Italy,Petrochemical Plant, FireBLEVEFlangefailureat column releasedliquidswhich were immediately igtuted$65,000,000 loss11.05.85Mount Belvieu, TX,USA, NGL Terminal,ExplosiodFireContractorcut liveliquidpropanereleasingcontentswhich were feedby salt dome reservoir.Explosionand fire impactedfire pumps.$40,000,000loss12.21.85Naples, Italy,ProductsTerminal, Fire
    • 76 Handbook of Fire and Explosion ProtectionTank overfilled producing a vapor cloud producing an explosionsettingother tanks on fire and causingextensivedamage.$42,000,000 loss1986-06.15.86Pascagoula, MS, USA, Chemical Plant,ExplosionEireSuspected leaking valves released vapors that were ignited$10,000,000 loss10.06.86North Sea,West Vanguard,Blowout, ExplosioflireDrilling rig encountered shallowgas and riser system had leakage, no BOP installedand divertersystemcould notwithstand blowout forces1Fatality,Rig totally destroyed08.15.87Ras Tanura,SaudiArabia, Refinery, FirePropanereleased possiblyat flangeat relief valve, after facilitypower failure, Ignition caused by nearby vehicle$60,000,000 loss11.14.87Pampa, TX, USA, Chemical Plant, ExplosionEireExplosion at reactor severely damagefacilityand impacted firewatersupplysystem$215,300,000 loss12.21.87Gulfof Mexico, Eugene Island Block 190,Helicopter Crash into Platform, FireHelicopter flew into leg of platform and crashed on landingpad14Fatalities,Helicopter destroyed,platformdamaged01.02.88.Floreffe,PA, USA, Bulk Plant, Tank Rupture48 year old relocated tank rupturedduringinitialfillingoperation.$13,300,000 loss04.24.88SouthAtlanticoffshoreBrazil,Enchova Central,Blowout, FireWorkover of a gas injection well gas releaseoccurred, BOP failed,sparks from fallingpipe ignited gas.Platform total loss05.05.88Norco, LA, USA, Refinery, ExplosionEireCorrosion failureof a carbon steel elbow released propanevapors that exploded in the FCC unit that impacted all utilitiesand firewatersystem$300,000,000loss06.08.88Port Arthur, TX, USA, Refinery, ExplosionEireFailureof a propane line resulted in vapor cloud releasein the tank farm that ignited and impacted other product transferlines.
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 77$16,000,000loss07.06.88North Sea, Block 15/17,PiperAlpha, ExplosionlFireCondensate leakage caused explosionwhich impacted safety systemsand spread incident167Fatalities,total facilityloss estimatedat $1,000,000,000.09.08.88Rafness,Norway, Chemical Plant,ExplosioflirePump seal leakage released vaporcloud$11,000,000 loss09.22.88North Sea, Ocean Odyssey, Blowout, ExplosionEireDrilling Rig encountered gas and choke linedeveloped leak causingvapor cloud, explosionand tire1Fatality,Rig totally destroyed09.23.88Gulf of Mexico, Main Pass Block 133,FireUnmanned platform,pump packing leakageEstimated loss at $5,500,00010.25.88Pulua Merlimau, Singapore,Bulk StoragePlant, FireSubmerged floatingroof tank of gasolinecaught tire while foam was being applied. Fire spread to 3 other tanks.$12,000,000 loss1989-01.xx.89North Sea,DrillingRig, BlowoutTreasureSagaRelief well drilledto controlblowout$250,000,000 loss03.07.89Antwerp, Belgium, Chemical Plant, ExplosionEireA low cycle fatiguecrack in a seam weld of a pipe lead to the releaseof ethyleneoxidewith ignited completely destroyingthe distillationsectionof the plant.$77,000,000 loss03.19.89Gulf of Mexico, SouthPass 60B,, FireMaintenance activitiescut into linestill containinghydrocarbon gases7 fatalities, $50,000,000 loss.06.03.89Ural Mountains,U.S.S.R.,Pipeline,ExplosionLPG pipelineleak exploded impactingtwo passengertrains500+ Fatalities.06.07.89Morris,IL, USA, Refinery; ExplosiodFire
    • 78 Handbook of Fire and Explosion Protection09.05.89Marinez, CA, USA, Refinery, FireWeld failureon hydrogen linecaused high pressurejet fireonto the supportof a 100foot reactor which failed and spreadincident.$90,000,000 loss.10.23.89Pasadena,TX, USA, Chemical Plant, ExplosiodFireEthylene leakage from reactor loop ignited causingan explosionseverely damagingthe facility. Blast estimatedto beequivalent to 10tonsof TNT.23 Fatalities, Greaterthan $750,000,000loss.12.19.89OffshoreLas Palmas, canary Islands,Tanker,ExplosionExplosion opened tanker hull and spilled 19million gallons12.24.89Baton Rouge, LA, USA, Refinery, ExplosiodFirePipeline failurereleasedcombustiblegasesresultingin UCVE which impactedutility services,pipelines,and startedotherfires.Several Fatalities,$43,000,000 loss1990-04.01.90Warren, PA, USA, Refinery, ExplosioflireLPG released by operatorduringwater drainingoperationof debutanizersystem$25,000,000 loss07.05.90Channelview,TX, USA, WastewaterPlant, ExplosionEireFailure of oxygen analyzer for storagetank allowed combustiblevapors to accumulate and ignite17Fatalities,$12,000,000 loss07.10.90Rio de Janeiro, Brazil, Refinery, ExplosionBoiler rupture occurred in the FCC unit.$10,000,000loss07.19.90Cincinnati,OH,USA, Chemical Plant, ExplosionRupturedisk released combustiblevapors from reactor after it overpressureddue to cleaningvaporevolution fromresidualheat in the vessel. Vapors ignited causingan explosionwhich severely damaged the facilities.$23,000,00011.03.90Chalmette, IN, USA, Refinery, ExplosioflireHeat exchangershellfailurereleased gas causinga explosionto occur and process fires to start.$15,000,000 loss11.06.90Naothane,India, Pipeline, ExplosionLeak in a gas pipelineresulted in explosionwhich damaged a nearby gas treatment and compressorfacility$22,000,000 loss11.25.90Denver, CO, USA, Bulk StorageFacility,Firefuel leak at fuel pump ignited by motor
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 79$30,000,000 loss11.30.90Ras Tanura, SaudiArabia,Refinery, FireChemical induced corrosionfailureof main crudefeedline caused a fireto occw at the fractionationcolumns for keroseneand diesel.1Fatality,$30,000,000 loss1991-03.03.91Lake Charles, LA, USA, Refinery, ExplosionEireVessel rupturefollowingturnaroundin which a drain valveleft open allowing water to enter vessel$23,000,000 loss03.11.91Coatzacoalcos,Mexico, Chemical Plant, ExplosioflirePipingrupturecaused explosionand fire.$150,000,000 loss03.12.91Seadrift,TX, USA, ChemicalPlant, ExplosiofliresPlant explosionspreadincident and impacted fue protectionsystems.$80,000,000 loss04.13.91Sweeny,TX, USA, Chemical Plant, ExplosionReactorexplosion$50,000,000 loss05.01.91Sertlngton,LA, USA,, Chemical Plant, FireExplosionSmall fire started explosionsdestroyingthe facility$105,000,000 loss.06.17.91Charleston,SC,USA, Chemical Plant, Explosion/FireStartupfollowingmaintenance produced processupset in reactor,water found in processmaterials,reflux line blockedresultedin overheatingin reactor.$10,000,000 loss06.20.91Dhaka, Bangladesh,Chemical Plant,ExplosionMetallurgicalfailureof pipe weld$70,000,000 loss08.21.91Melbourne, Australia,Chemical Storage,ExplosionEireLightningstruck storagetank, causeexplosionand firewhich spread to other tanks. Fire suppressionsystemimpactedduringexplosionlosingits capability.$24,000,000loss09.07.91Haifa, Israel,Chemical Plant, FireShortcircuit suspectedas cause$22,000,000 loss
    • 80 Handbook of Fire and Explosion Protection1992-04.xx.92Brenham, TX, USA, Gas Storage,Explosion/FireNumerous tecbnical and human failures allowed gas to releasefrom a salt dome storagefacility. Lack of fail safe devicescontributedto the explosionof the resultingvapor cloud.3 Fatalities, $9,000,000 loss.03.25.93Lake Maracaibo,Venezuela, OffshorePlatform,WCE/FireFailureof intercoolerduringstartupofgas compressor,controlroom destroyed10Fatalities,$100,000,000 lossOS.18.93Bilbao, Spain,Refinery, ExplosionExplosion occurred in chimney connected to a conversionunit$8,000.000 loss05.23.93Munich, Germany, Chemical Plant,ExplosionlFireExplosion duringcleaningof peroxideinstallationof pilot plant2 Fatalities,$3,200,000,000 loss06.03.93Sicily,Italy, Refinery ExplosionlFirePipe fracturein feedline to furnace7 Fatalities,Plant closed indefinitely.06.08.93St. Therese,Canada,Petrochemical Plant, FirePlant completely destroyed by fire.08.02.93Baton Rouge, LA, USA, Refinery, ExplosioflireIncorrect metallurgicalvalveleaked cokeresultingin anexplosionunder the coker unit.3 Fatalities08.27.93Elyria, Ohio, USA, Chemical Plant, Explosion/FireOverheated pump caused explosionin catalyst blending building$s,ooo,oooloss09.28.93Caracas,Venezuela, Pipeline, FirePipeline punctured duringexcavationwork51 Fatalities1994-01.07.94MississippiRiver, USA, DrillingBarge, Ruptured PipelineDrill barge spudded into gas pipeline1Fatality04.20.94OffshoreEgypt, OffshoreProduction Platform,FireShipcollided with unmanned platform which ignited.
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 81Platform total loss, est. 150days loss production.05.27.94Belpre, Ohio,USA, Chemical Plant, ExplosiodFireExplosionat storage tanks for styrenestarted major fire.3 Fatalities, major damagesto the facility06.21.94Bristol, Pennsylvania,USA, Chemical Plant, ExplosionlFireUncontrolledreaction in chemicalmixing$5,000,000 loss06.26.94El Tablazo, Lake Maracaibo, Venezuela, Chemical Plant ExplosiodFireFuel leak duringtruck transfer operationscaused storagevessels to BLEVE07.24.94Milford Haven,UK, Refinery, Firepower disruptioncaused plant upset causing liquid overloading$100,000,000 loss07.26.94Inchon,Seoul, South Korea, Chemical Plant, ExplosionlFireexplosion occurredin an overheated furnace5 Fatalities, Major damagesincurred.Overall it can be demonstrated that the majority of these incidents werer the result of small hydrocarbonleakages stemming from failure of system integrity, i.e., mechanical equipment such as engines, compressors,pumps, or metallurgical failures of the process. These leakages are usually ignited by a hot surfaceeventually reached by the release. Most fire incidents (estimated at 90%) are extinguished by manual effortsusing portable fire extinguishers. Where the he1 supply is unable to be isolated the incident grows inproportions becoming uncontrollable.Offshore Oil Production and Exploration (USA)The U.S . MineralsManagement Service (MMS) periodically publishes a listing of all the incidents occurringoffshore in U.S. waters. This list provides a chronological listing of all the reported incidents from 1958 tothe time of printing of the document.An examination of this data has been performed for incidents from 1980 to 1990 in the Gulf of Mexico. Itreveals that the worst fire or explosion events within the last ten years have been from blowouts, while thehighest loss of life is from helicopter crashes. Most fires occur from small integrity leakages and aretypically suppressed by human intervention using hand held portable fire extinguishers. The releases areusually ignited by local equipment containing hot surfaces or from hot exhaust gases off a combustionengine. The major financial risks were from blowout incidents.539 incidents occurred during the period from 1980 to 1990 accounting for 60 fatalities and 246 injuries.The 246 injuries were the result of 140 separate incidents (26%), while the 60 fatalitieswere the result of 29separate incidents (4%). 43 explosions (8% of the total), were also identified as having occurred during thisperiod. There was no damage, injuries or environmental pollution in 154(28%) of the reported incidents.Worst Fatal IncidentsThe five worst fatal incidents in this analysis are stated below. They are mostly associated with
    • 82 Handbook of Fire and Explosion Protection1. Helicopter struck leg of an offshorerig - 14fatalities, (Forest Oil - 1987).2. Cut into Pipeline not hydrocarbonfree, Platform destroyed, - 7 fatalities(Arc0 - 1989)3. Helicopter struck platform - 6 fatalities, (Exxon - 1980)4. Blowout, total platform destroyed - 6 fatalities, (Penzoil- 1980)5. Blowout,jackup rig sufferedcatastrophicdamage - 5 fatalities,(Cities Service- 1980)Worst Property LossesThe worst property losses suffered during this period are highlighted below.associated with blowout incidents.Almost all are1. Blowout, total platform destroyed, (Penzoil- 1980).2. Blowout, Jackup Rig suffered catastrophic damage, (Cities Service-1981)3. Blowout, Major damage to rig and submersiblebarge, (Placid -1981).4. Blowout, Jackup rig and derrick destroyed, (Shell - 1982).5. Blowout, Drilling rig and quarters destroyed, (Chevron - 1982).6. Blowout, Extensivedamageto two rigs and platform (Union - 1993).7. Blowout, Damage to Drillingrig (Conoco - 1984)8.Cut into Pipelinenot hydrocarbonfree, Platform destroyed, (Arc0 - 1989)Although the ultimate cause of a blowout is human error to control the hydraulic wellbore pressurewith drilling mud, in some cases the failure of the BOP to control the situationalso contributedto theincident. The causes of the BOP failures are analyzedbelow:BOP Failures1. Gas divertervalve improperly set and diverter hose ruptured.2. Annular preventer failed, pipe rams closed, casing ruptured at 49,642 kPa (7,200 psi.) below theBOP.3. Fill up l i e opened to release gas, closed pipe ram, unable to close fill up line, well blew outthrough the swivelneck.4. Kelly hose burst during well control procedure, Kelly cock and in-line safety valve could not beclosed.5. Annular preventer leaked, after well "kicked".6. Diverter line ruptured, aAer 35 minutesof gas diversion.7. Drilling string safetyvalve leaked at stem.8. Diverter line leaked.ImmediateCause of DeathSixty fatalitiesoccurred in the Gulf of Mexico related to offshore oil and gas production during 1980to 1990. The immediatecause of death has been identifiedin Table 6.
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 83BlowoutExplosionInadvertent ActivationBurnsDrowningUnknown (during majorfire or explosionincidentPerforatingGun5 18 30.0%5 5 8.4%2 3 5.O%2 2 3.3%1 2 3.3%3 10 16.7%,Table 6Immediate Cause of Death (Gulf of Mexico, 1980-1990)Helicopter and blowout incidents account for the major portion of incidents (63%). It could be inferredthese incidents account for a higher loss of life than other incidents due to the higher concentration ofpersonnel involvedin these specificactivities.The helicopter incidents account for the highest amount of fatalities for any single cause of death. Theywere the result of two separate incidents in which each helicopter struck a facility. These incidents wherenot the result of mechanical failure of the helicopter.There were 13 blowout incidents recorded during the ten year period. They were generally listed as theresult of equipment failures.
    • 84 Handbook of Fire and Explosion ProtectionCauseCause of IncidentsNumber of PercentageIncidentsThe major cause of most Gulf of Mexico offshore incidents was the result of hydrocarbon gas or fluidreleases (approixmately 32%). The next major cause was equipment failure (mechnical or electrical 21%)and then hot work activities (12%). A tubulation ofthe a11the causes is provided in Table 7.Gas release (leakage,venting, etc.)Fluid release (leakage, spillage,etc.)Hot workMechanicalfailureElectrical short/insulationfailureEngine or gearbox oil leakRuptureProcess upset120 22.2%66 12.2%53 9.8%51 9.5%49 9.1%20 3.7%14 2.6%13 2.4%LightningOpen flameuseEngine or compressorbackfireVibration induced failureImproper use of or incorrect type of cleaningfluidMechanicalimpact (friction)Improper procedure/operationBlowouts 13 2.4%Exhaust gases inproximityof combustiblematerial 13 2.4%11 2.0%10 1.8%10 1.8%8 1.5%7 1.3%6 1.1%6 1.1%Unknown 40 7.4%Total 539 100%Table 7Cause of Incidents, Gulf of Mexico
    • Historical Survey of Fire and Explosions in the Hydrocarbon Industries 85SummarvThe New York Times reports this is one of the deadliest periods for the American petrochemical industry’shistory: “Alarm(ing)company executives, the 12 worst explosionskilled 79 people, injured 833, and causedroughly $2 billion in damage”. In the U.S.A.over 34,500 industrial chemical accidentswere reported duringthe period of 1988-1992, nearly one every hour. Over 2,000 of these resulted in injuries, evacuations orfatalities. Some 40 percent occurred concentrated in just two percent of the counties of the U.S.,primarilyin California, Texas and Louisiana, home to most and some of the largest petroleum and chemical facilitiesinthe U.S.A.Any high concentration of personnel activities may suffer a corresponding high fatalilty incident.Concentarated areas of personnel such as on offshore installations, drilling activities, living quarters ortransportation means are all potential candidates where a minor mishap may result in coniderable life loss.Where the equipment involvedin these task is complex, the risk of an accident becomes greater.The majority of incidents occur due to lack of system integrity - leaks and mechanical failures. Ignitionsources generally tend to be associated with local hot surfaces. Large hydrocarbon incidents are the directresult of the inability to isolate fuel supplies from the subject incipient event. Where large volumes ofhydrocarbonsare processed or handled, such as from pipelines ,wellheads or the process arrangments, anyescalationin the incident may result in higher levels of damage or injuriesthan may have otherwiseoccurred.
    • 86 Handbook of Fire and Explosion ProtectionBibliography1. American Petroleum Institute (API), Summary of Occupational Injuries, Illnesses, and Fatalities in the PetroleumIndustry, (AnnualReport), API, Washington,D.C.2. Giddens,P. H., Early Davs of Oil, PrincetonUniversity Press, Gloucester, MA, 19643. Departmentof Energy,The PublicInauirv into the Piper Alpha Disaster,HMSO, London, U.K., 1990.4. Ferrara,G. M., The DisasterFile: The 1970s,Facts on File,New York, NY, 1979.5. Instituteof ChemicalEngineers, "Articles and Case Historiesfrom Process IndustriesThroughout the World", LossPreventionBulletin, 075, June 1987,Instituteof Chemical Engineers,Ruby, U.K., 1987.6. Kletz, T. A., What Went Wrong?,Third Edition,Gulf Publishing,Houston, TX, 1986.7. Lees, F. P. Loss Preventionin the Process Industries,Volume 1, Butterworths,London,U.K., 1980.8. Marsh & McClennan Protection Consultants (M&M PC), LarPe Property Damaye Losses in the Hvdrocarbon-Chemical Industries.A Thirty Year Review, 14thEdition, M&M PC, 1992.9. Minerals ManagementService(MMS), Accidents Associatedwith Oil and Gas Ouerations. Outer Continental Shelf1956- 1990,U.S. Departmentofthe Interior, Herndon,VA, 1992.10. NationalFire ProtectionAssociation(NFPA),"FireJournal",NFPA, Quincy,MA.11. SedgwickEnergy, "LossControlNewsletter", SedgwickEnergyLimited, London,U.K.,Issue 1, 1994.12. Singerman,P., An AmericanHero. The Red Adair Stow, Little Brown & Co. Ltd.?Boston, MA, 1990.13. SINTEF, STF 88A82062. Risk of Oil and Gas Blowout on the Norwegian Continental Shelf, SINTEF, Trondheim,Norway, 1983.
    • Chapter 7Risk AnalysisEveryonein the engineeringprofession is familiarwith Murphys Law, "If anythingcan go wrong, it will.". Ialso prefer to remember the extended version which states, "If a series of events can go wrong, it will do soin the worst possible sequence". Risk analysis is a sort of Murphys Law review in which events areanalyzedto seethe destructivenature that they might produce.Risk analysis is a term that is applied to a number of analytical techniques used to evaluate the level ofhazardous occurrences. Technically, risk analysis is a tool by which the probability and consequences ofaccidental events are evaluated for hazard implications. These techniques can be either qualitative orquantitative.Risk analysiscan be broken down into four main steps:(1) Identifjlaccident occurrences.(2) Estimatethe frequency of the occurrences.(3) Determinethe consequencesof each occurrence.(4) Develop risk estimatesassociatedwith the frequency and consequence.Before safety measures are applied to a facility, it is prudent to identifjl and evaluate the possible hazardsthat may evolve before spending considerableamounts on protection that may not be needed or overlookingrequirements for protection measures that are needed. The first step in fire protection engineering shouldtherefore be to always identifj.the major risks at a facility. When conducting these analyses it is prudentonly to only consider credible events. Farfetched or outlandish event considerations(e.g., a meteor strikingthe facility)are not necessary or practical and lead to a less cost effectiveapproach.Safety Flow ChartSometimes it is easiest to prepare a general flowchart that identifies events which may occur at a facilityduring an incident. This flowchart can identifjl possible avenues the event may lead to and the protectionmeasures available to mitigate and protect the facility. It will also highlight deficiencies. The use of affowchart helps the understanding of events by personal unfamiliar with petroleum risk and safety measures.It portrays a step by step scenariosthat is easy to follow or explain. Preparation of in-depth risk probabilityanalysis can also use the flowchart as the basis of the event trees or failure modes and effects. Figure 3provides a generic example of a typical hydrocarbon process facility Safety Flowchart. API RecommendedPractice RP 14Cprovides an exampleof a SafetyFlowchart for an offshoreproduction facility.87
    • 88 Handbook of Fire and Explosion Protection"0QItI )EVACUATICUc.5JSAFETY FLOW CHARTFigure 3
    • Risk Analysis 89Risk Identificationand EvaluationThe basic methodology adopted for the formal risk evaluation in the petroleum andrelated industries, both for existing facilitiesand new projects, normally contain thefollowing steps:1. Definition of the Facility - A general descriptionof the facility is identified. Input and outputsto the facility are noted, production, manning, basic process control system (BPCS), ESD, fireprotection philosophy, assumptions, hazardous material compositions, etc.2. Identification of Hazards - A listing of the processes and storage of combustible materials andthe process chemistrythat can precipitatean incident.3. Development of Accidental Events - Identified scenariosthat can cause an accident to occur.4. Frequency Analysis - An examination of the probabilities or possibilities of and accident tooccur.5. Consequence Modeling - A descriptionof the possible incidentsthat can occur.6. Impact Assessment - The development of the severity of the incident in terms of injuries,damage, environmentalimpact, business interuptionand public reaction.7. Summation of Risk - The combination of severity and probability estimates an incident tooccur.8. Effect of Safety Measures An evaluation of the mitigation effects of layers of protectivesystemsof different integrities, on the effectsor prevention of an incident.9. Review Against Risk Acceptance Criteria - The comparison of an incident risk which issupplemented by the selected safety measures to achieve the requirements for company safetylevels.During the process hazards identification and definition phase of a project design, a basic process controlsystem (BPCS) strategy is normally developed in conjunction with heat and material balances for theprocess.Both qualitative and quantitative evaluation techniques may be used to consider the risk associated with afacility. The level and magnitude of these reviews should be commensurate with the risk that the facilityrepresents. High value, critical facilities or employee vulnerability may warrant high review levels. Whileunmanned "off-the-shelf, low hazard facilitiesmay suffice with only a checklist review. Specialized studiesare performed when in-depth analysisis needed to determinethe cost benefit of a safety feature or to lllydemonstrate the intended safety feature has the capabilityto fully meet prescribed safety requirements.Generallyoffshore facilitiesand major process plants onshore represent considerable capital investment andhave a high number of severe hazards associated with them (blowouts, ship collisions, line and vesselruptures, etc.). They normally cannot be easily evaluated with a simple safety checklist approach. Somelevel of "quantifiableevaluation"reviews are usually prepared to demonstrate that the risk of these facilitiesis within public, national, industry and corporate expectations.These studies may also point out locations or items of equipment that are critical or single point failures forthe entire facility. Where such points are identified special emphasis should be to ensure that events leadingup to such circumstancesare prevented or eliminated.The followingbrief descriptionsare typical analysesundertaken.
    • 90 Handbook of Fire and Explosion ProtectionA. Qualitative ReviewsQualitative reviews are studies base on the generic experience of personnel and do not involvemathematical estimations. Overall these reviews are essentially checklist reviews in whichquestions or process parameters are used to prompt discussions of the process design andoperations and possible accident scenarios.Checklist or Worksheet - A standardized listing which identifies common protectionfeatures required for typical facilitiesis compared against the facility design and operation.Risks are expressed by the omission of safety systems or system features.Preliminary Hazard Analysis (PHA) - Each hazard is identified with potiential causesand effects. Recommendationsor known protective measures are listed.What-If Reviews - A safety study which by which “What-If’ investigative questions(brainstorming approach) are asked by an experienced team of a hydrocarbon system orcomponents under examination. Risks are normally expressed in a qualitative numericalseries(e.g., 1to 5).HAZOP - A formal systematic critical safety study where deviations of design intent ofeach component are formulated and analyzed from a standardizedlist. Risks are typicallyexpressed in a qualitative numerical series(e.g., 1 to 5) relative to one another.Relative Ranking Techniques (DOW and MOND Hazard Indices) - This methodassigns relative penalites and awards points for hazards and protection measuresrespectiveslyin a checklist accountingform. The penalties and award points are combinedinto an indexwhich is an indication of the relative ranking of the plant risk.B. Quantitative ReviewsQuantitativereviews are mathematicalestimationsthat rely upon historical evidence or estimatesoffailures to predict the occurrence of an event. These reviews are sometimes referred to as aQuantitativeRisk Assessment(QRA).Event Trees (ET) - A mathematical logic model that mathematically and graphicallyportrays the combination of events and circumstancesin an accident sequence, expressedin an annual estimation.Fault Trees (FT) - A mathematical logic model that mathematically and graphicallyportrays the combination of failures that can lead to a specific main failure or accident ofinterest, expressed in an annual estimation.Failure Modes and Effects Analysis (FMEA) - A systematic, tabular method ofevaluating the causes and effects of known types of component failures, expressed in anannual estimation.C. Specialized Supplemental StudiesSpecialized studies are investigations that attempt to veri@ the ability of a facility to performeffectivelyduring an emergency, generallyby mathematical estimates. They are used extensivelytojustifl the necessity or deletion of a safety system. The most common studies are listed belowhowever every facility is unique and may require it’s own investigative requirements (e.g., for anoffshore facility - the potential for ship collisions). For example, for a simple unmanned wellhead
    • Risk Analysis 91platforms, located in the warm shallow waters (e.g.,Gulf of Mexico), these analyses are relativelysimple to accomplish. Conversly, where manned integrated production and separation platformsare located in deep cold waters (e.g., the North Sea), these analysestend to be most extensive.Leak Estimation - A mathematical model of the probability and amount of potentialhydrocarbonreleases that may occur from selected processes or locations.Depressurization and Blowdown Capabilities - A mathematical calculation of thesystem sizing and amount of time needed to obtain gas depressurization or liquidblowdown according to the company’s philosophy of plant protection and industrystandards (i.e., APIRP 521).Combustible Vapor Dispersion (CVD) - A mathematical estimation of the probability,location, and distance a release of combustiblevapors will exist until dilution will naturallyreduce the concentration to below the LEL or no longer considered ignitable (typicallydefined as 50% of the LEL).Explosion Overpressure - A mathematical estimation of the amount of explosiveoverpressurethat may be expected from an incident. It is portrayed as overpressure radiifrom the point of initiation until the overpressure magnitudes are of no concern, i.e., lessthan 0.02 bar (3.0 psio). Evaluations perforned for enclosed areas will also estimate theamount of overpressureventing capabilityavailable.Survivability of Safety Systems - An estimation of the ability for safety systems tomaintain integrity from the effects of explosions and fires. (Safety systems may includeESD, depressurization, fire protection - active and passive, communication, emergencypower, evacuationmechanism, etc.).Firewater Reliability - A mathematical model of the ability of the firewater system toprovide firewater upon demand as required by the design of the system without acomponentfailure, e.g., a Mean Time BetweenFailure (MTBF) analysis.Fire and Smoke Models - A mathematical estimation model depicting the duration andextent of heat, flame and smokethat may be generated from the ignition of a hydrocarbonrelease. The results of these estimates are compared against protection mechanisms (e.g.,firewater,fireproofing, etc.) afforded to the subject area to deterniine adequacy.Emergency Evacuation Modeling - A study of the mechanisms, locations and timeestimates to complete an effective removal of all personnel from an immediatelyendangered location or facility.Fatality Accident Rates (FAR) or Potential Loss of Life (PLL) - A mathematicalestimation of the level of fatalitiesthat may occur at a location or facility due to the natureof work being performed and protection measures provided, may be calculated at anannual rate or for the life of the project.Human Reliability Analysis (HRA) or Human Error Analysis - A reliability analysisthat estimates the potential for human errors to occur due to the work environment,human-machine interfaces, and required operationaltasks.These special analyses are prepared from the quantifiable risk analysis and a total risk scenario can bepresented which depictsthe estimated incident effects. An exampleis shown in Table 8.
    • 92 Handbook of Fire and Explosion ProtectionLarge Gas Le& A ModuleEscalahon to B ModuleNo eacalahonAdditional specialized studies are sometimes specified for offshore facilities. These may include thefollowing,dependingon the type of facilityunder review:AGLO3 I I I II 4,7, in, 12 000163 1 diff I 5 7 k g / s I 3 4 5 m x 1 0 m on3 yes 15-21 I 13, 14, 15, OooO597 pooVM I l9kgis OutofMod 003 Yes 15-21 ,I t I IHelicopter, ship and underwatervessel collisions.Possibility of failing objects(from crane or drillingoperations).Extreme weather conditions.Reliabilityor vulnerabilityof stability,buoyancy, and propulsion systems (for floatinginstallationsor vessels).Survivabilityof the TemporarySafeRefuge (TSR).TABLE 8Example of Quantifiable Accident Scenario Summary
    • Risk Analysis 93Risk Acceptance CriteriaA numerical level of risk acceptance is specified where quantitative evaluation of the probabilities andconsequencesof an accidental event have been performed. The documentationmay also be used by seniormanagement as a justification for budgetary decisions. The values of risk for many industries and dailypersonal activitieshave published and are readily availablefor comparison. This comparisonhas formed thebasis of risk acceptancelevels that have been applied to the hydrocarbon industry in various projects.Usually the petroleum industry level of risk for a particular facility is may be based one of two parametersThe average risk to the individual (FAR or PLL) or the risk of a catastrophic event at the facility (QRA)The risk criteria can be specified in two manners Risk per year (annual) or facility risk (lifetime). Forpurposes of consistency and familiarityall quantifiablerisks are normally specified as annually Where valueanalysisis applied for cost comparisonsof protection options, a lifetimerisk figureis normally used.It has been commonly acknowledged in the hydrocarbon industry the average risk to an individual at afacility should generally not exceed a value in the order of 1 x per year. The facility risk is the totalfrequency of an accidental event for each main type of incident. Similarlyfor most oil and gas facilities,thefacilityrisk should generallynot exceed a value in the order of 1x per year.Where risks are higher that normally acceptable and all reasonable mitigation measures have been examinedto find out value and practicality, the principal of risk as low as reasonably practical applies. Where theavailable risk protection measures have been exhausted and the risk level is still higher that the acceptednumericalvalue, the risk would be considered "AsLow As ReasonablyPractical"(ALARP).In the petroleum industry, insurance agents will typically estimate the maximum losses a facility may sufferby performing a calculation of a potential vapor cloud explosion at the facility (where this is applicable). Byexamining the high loss explosion potentials, a maximum risk level can be determined and thereforeinsurance coveragesthat are necessary will be defined.Relevant and Accurate Data ResourcesRisk evaluation methods shoulduse data that is relevant to the facility under examination. Where other datais used an explanation should be provided to substantiate its use, otherwise inaccurate assumptions willprevail in the analysis. Where highly accurate data is available,the findingsof a quantitativerisk evaluationwill generally only be within an order of magnitude of 10 of the actual risk levels since some uncertainty ofthe data to the actual applicationwill always exist.All quantifiable evaluation documentation should be prepared so that it would conform to the nature of afacility "Safety Case" format which may be required for submittalto governmental agencies at a later date.Cost estimates can be prepared to perform any portion or all the risk evaluation for a particular facility orinstallationbased on the manpower necessary for each portion of the analysis and the size and complexityofthe facility.
    • 941.2.3.4.5.6.7.8.9.101112Handbook of Fire and Explosion ProtectionBibliographyAmericanPetroleumInstitute (API), RP 14C. RecommendedPractice for Analvsis. Desim. Installationand Testingof Basic SurfaceSafetvSvstemsfor OffshoreProduction Platforms,Fourth Edition, API, washington, D.C., 1986.American Petroleum Institute (API), RP 145, RecommendedPractice for Hazard Analvsis for Offshore Platforms,First Edition,API,Washington,D.C., 1994.American Petroleum Institute (API), RP 75. Recommended Practices for DeveloDment of a Safety andEnvironmental Management Promam for Outer Continental Shelf (OCS) Operations and Facilities, API,Washington,D.C., 1993.American Petroleum Institute (API), RP 750. Management of Process Hazards, First Edition, API, Washington,D.C., 1990.Block, A., Murphys Law, Book Two, More Reasons Why Things Go Wronp!, Price/Stem/Sloan, Los Angeles, CA,1980.Center for Chemical Process Safety, (CCPS), Guidelines for Chemical Process QuantitativeRisk Analysis, AIChE,New York, NY, 1989.Center for ChemicalProcess Safety, (CCPS),Guidelinesfor HazardEvaluationProcedures, SecondEdition,AIChE,New York, NY, 1992.Center for Chemical Process Safety, (CCPS), Guidelines for Process Eauiument Reliabilitv Data, AIChE, NewYork, NY, 1989.Des Norske Veritas (DNV), OREDA OffshoreReliabilitv Data, SecondEdition, DNV, Hovik,Norway, 1992.Dow Chemical Company, Fire and ExulosionIndex Hazard ClassificationGuide, Sixth Edition, American Instituteof ChemicalEngineers(AIChE),New York,NY, 1987.Dupont Chemicals, Dupont Safety and Fire Protection Guideline: Use of Process Risk Calculations in HazardsManagement,Dupont,Wilmington,DL, 1981.Health and Safety Executive(HSE). A Guideto the OffshoreInstallations(SafetyCase) Regulations 1992, HMSO,London,U.K., 1992.13. Industrial Risk Insurers, IM.8.0.1.1,Oil and ChemicalProuerties- Loss PotentialEstimationGuide, Hartford, CT.14. Lees, F. P., Loss Preventionthe ProcessIndustries,Gulf Publishing,Houston, TX, 1980.15. National Fire Protection Association (NFPA), NFPA 550. Guide to the Firesafetv Concepts Tree, NFPA, Quincy,MA, 1986.16. Nolan, D. P., Application of Hazor, and What-If Safetv Reviews to the Petroleum. Petrochemical and ChemicalIndustries,Noyes Publications,Park Ridge,NJ, 1994.
    • Chapter 8Segregation, Separation and ArrangementThe most inherent safety feature that can be provided at oil, gas and related facilities is the segregation,separationand arrangement of equipment. Some publications emphasize that separation is the prime safetyfeature that can be employed at any facility. This is true from the viewpoint of preventing exposure topersonnel or facilities outside the area of concern. However this becomes somewhat impractical for thelarge process plants and offshore production platforms that are designed and constructed today.Undoubtedly the manned locations at petroleum facilities should be located remotely as possible fiom highrisk locations. Duplicate process trains, high numbers of vessels, multiple storage tanks and numerousincoming and outgoing pipelines limit the possibilitiesof remotely locating every single high hazard processrisk from each other. Additionally operational efficiencieswould be affected and construction costs wouldincrease. The more practical approachis combinethe features of segregation,separationand arrangement ina fashion that leads to more organized and operationally acceptable process facility. This represents thelowest practical risk but still avoidscrowding.Potential future expansion should be assessed and space provided for known and unknown needs. Logicaland orderly expansion can only be made if provision at the time of original facility installation. The masterplan shouldbe frozen and only altered if a risk analysisof the changes is acceptable.Surfacerunoff should be considered coincident with equipment layout. If surfacerunoff from one area goesdirectly to another area the feature of separationhas be lost.SegregationSegregation is the grouping of similar hydrocarbon processes into the same major area. This allows aneconomical approach to achieve the maximum protection to all the high risk units while lessor protection isgiven to low risk equipment. The segregated high hazard areas can then also be further separated as far asnecessary from other areas of the facilityand the public. Some offshorefacilitiesthat do not have the luxuryof large amounts of space, generallyhave to use segregation as the prime means of protection supplementedby tire and explosive resistant barriers for most areas.The major facility segregation categories are process, storage, loading, flaring, utilities and administrative.Each of these categories can be further subdivided into smaller risk such as individual units for the processareas. The major segregation areas would be provided with maximum spacing distances while thesubdivided areas are provided with lessor amounts depending on the protection afforded the area andindividual risk of the units. Most petroleum and chemical processes are arranged in a systematic fashionfrom reception of raw materials, manufacturing and output to finished products. This arrangement iscomplementary to the needs of segregation for the purposes of loss prevention. Layout cost controls for95
    • 96 Handbook of Fire and Explosion Protectioncontinuos flow operations also require that the distance personnel, information move is minimized. Theexact technical process selected for a hydrocarbon process will also ultimatelyinfluencethe general layout.Some of the latest designs for platforms in the North Sea has segregated the process (i.e., separation, gascompression, etc.) facilities hrthest from accommodations and utility support. Drilling modules are sitedbetween the process and utility support modules based on the level of relatively lower risk drilling in adefined reservoir represents versus possible process incidents.Safety systems should not be segregated together. Each safety system should be diversified as much aspossible to avoid the possibility of a single point failure. A prime example is the firewater supply whichshouldbe pumped into a facilityfiremain at several separate and remote locations.Tank farm areas are usually segregated based on the service and type of tank for economic reasons, besidessegregatingby levels of risk.SeparationThere has much analysisin the petroleum industry as what is the prudent spacingtable to use in the layout ofan onshore facility. Attempts have even been made to compare the spacing tables used by individualscompanies. This would provide a consolidatedtable the entire industry could apply. Although such an ideais admirable, there are several obstaclesin achievingsuch a goal.First, the original insurance spacing tables (i.e., OIL, 01.4, IRI,etc.), although commonly used in somesectors of the industry, have been formulated based on a few selective historical incidents and do not appearto be scientifically based on the current methods of determining the explosive or fire damage that can bereleased. They cannot account for all the possible design quantities of production processes They mayprovide too much or too little spacing in some instancesfor the risk involved. Second, some facilitieswereconstructed before the spacingtables were widely applied or were modified without too much considerationto a spacingtable. Therefore any relocationof facilitiesunder an "industry" spacingtable will be very costlyto retroactively apply or enforce. Some petroleum companies may also consider that the values listed in an"insuranceindustry" table are too conservative. On the basis of their own analysis,they may desire to applylessor values. A survey of most industry spacing charts indicates they are not all similar. An obviousdisparity exists between the operating company spacing charts and the recommended distances of theinsurance industry, Ref Table 7. Also the mandate for any facility project engineer is to save space andmaterials to achieve a less costly and easily built facility. He will therefore always desire to congest orcompressthe area for shorter piping runs, fewer pipe racks, etc., and be at odds for the requirementsof lossprevention.The ideal solution is to perform a risk analysisfor each item in a facility to determine the probable maximumfire and explosive range the location may produce. The calculations and expense to accomplish such a tasktoday does not appear to justify a unilateral application to every piece of equipment at a facility.Consequentially the use of a spacing table for a facility design provides for an economical and expedientsolution. This is especially important when several options on the layout of the facility are available.However in some instances the use of risk analysis may demonstrate less spacing is necessary that what aspacing chart requires.The first task in applying a spacing table to a facility is to ensure it corresponds to the philosophy ofprotection adopted by the company. Where limited space is available to provide the required spacing, anexamination of the equivalent fire and explosive barriers or active fire suppression system should beconfirmed. This analysisshould be accepted by the company as part of the design risk analysis.In establishingprocess spacingphilosophyor if used, the ratings of fire and explosion barriers (as may be thecase offshore), fire suppression effectiveness, a number of principle factors should be considered. These
    • Segregation, Separation and Arrangement 97include1. Fire, explosion, rind toxic health hazards of the processes and of the materials being handled2 The volume of material contained in the process, how it is isolated or removed during anemergency.3. The strength of process vessel to maintain integrity during exposure to a hydrocarbon fire4. The manningand location of employees in the facility.5. The concentrationand valve of equipment in a particular area.6. The criticalityof the equipment to continuedbusiness operations.7. Possible fire exposuresto the facilityfrom adjacent hazards.8. The effectivenessof fire protection measures,both passive and active.9. The possibilityof the flareto release liquids or unignited combustiblevapors.To achievethese principalsthe followingfeatures are usually adopted:1. Individual process units should be spaced so that an incident in one will have minimal impact onthe other.2. Utilities such as steam, electricity, fire water should be separated protected by the effects of anincident so that they may be continuouslymaintained. Where large facilitiesor critical installationsare present the supply of these servicesfrom two or more remote locations shouldbe evaluated.3. The most critical important single equipment for continued plant operation or highest valued unitshould be afforded the maximum protection by way of location and spacing.4. Unusually hazardous locations should be located as far away as practical from other areas of thefacility.5. Considerationshould be given to use the general prevailing environmentalconditionssuch as windand terrain elevation to best advantage for spill and vapor removal. Facility equipment should notbe located where they would be highly vulnerable to a major spill or vapor release.6. Considerationshould be given to the adjacent exposures or other utilities which may transversethesite, i.e. pipelines, railroads, highways, power lines, aircraft, shippingroutes (if offshore), etc.7. Adequate arrangementsfor emergency service access to all portions of the facilityfor fire fighting,rescue, evacuation means.8. Placement of the flare at the most remote downwind location of the facilityManned Facilities and LocationsThe primary design consideration at any oil, gas 01- related facility should be the protection of employeesandthe general public from the effects of an explosion or fire. In all cases highly populated occupancies shouldbe located as far as practical upwind of the process oI storage areas. Where this cannot be practically
    • 98 Handbook of Fire and Explosion Protectionachievethe manned location should be provided with fire and blast resistant features commensuratewith theexposureit faces.The siting of manned locations should be considered the highest safety priority in the layout of ahydrocarbon facility. The primary locations where high levels of personnel may be accumulated relativelyclose to the hazards of hydrocarbonoperations are control rooms and offshoreaccommodations.Control rooms and offshore accommodations are also the most vulnerable fixed locations where a highfatality possibility can occur at hydrocarbon facility. In both of these installations a high number ofemployees may be present during most periods. Consequentially, an adequate risk analysis for bothlocations should be accomplished as part of any facility design scope. There is really no overwhelmingreason why both need to be near operating processes other than cost impacts and convenience to operatingpersonnel. Historical evidence has dramatically shown that control rooms, and in the case of offshoreplatforms - accommodations, can be highly vulnerable to the effects of explosions, fires, and smoke if notadequately protected.The ideal situation for offshorefacility is to locate the accommodationon a separateinstallationjacket that isspaced as far as practical from the production processes and the process platform oil or gas pipeline risers.Inclusion of the facility control room can also be conveniently provided in the accommodation increasingpersonnel safety and providing a cost benefit.The latest designs for onshore installations cater for a centralized control room, well distanced from theoperating facility with sub control areas as part of a distributed control system (DCS). The sub-controlareas are closer to the processes but contain fewer personnel and process control systems for the overallplant, so the overall risk level for the facility from a major incident is lowered. The outlying controlbuildings(sometimes referred to as PIBs or SIHs) still need to be sited against impactsfrom explosions andfires.Storage Facilities- TanksTank farm areas require additional consideration for spacing not only between other process hazards butfrom other storage tanks. Minimum shell to shell spacings for storage tanks are provided in NFPA 30. Italso includesrequirements for minimum spacingsfrom other exposures such as property lines and buildings.The provisions for spacings are based on the commodity stored, pressure, temperature, and fire protectionmeasures afforded to each tank. Each parameter adjusts the minimum requirements. For large tanks andthose containing crude oil, heated oil, slop oil or emulsion breading materials additional spacingrequirementsshouldbe considered. These includethe following:Where tanks exceed 45.7 meters (150 ft.) in diameter, the spacing between tanks should be aminimum of 1/2 the diameter of the largest tank.Tanks 45.7 meters (150 ft.) or more in diameter containing crude oil should be arranged suchthat the tanks are a minimum of one diameter apart.Hot oil tanks heated above 65.6 OC (150 OF), excluding flash asphalt, slop oil and emulsionbreaking tanks should be spaced apart by the diameter of the largest tank in the group.A major factor in location of storage tanks within a tank farm is the topography of the tank farm area. Theslope of the natural topography can be used to assist in the drainage requirements for a diked area andminimized the accumulationof spilled liquids near a storage tank. Diversion dikes or curbing can be used todivert spillageso it runs off remotely to a safe location.The prevailing wind conditions should also be used to the best extent. Where rows of tanks are designed,
    • Segregation, Separation and Arrangement 99they should be arranged so they are perpendicular to the prevailing wind instead of parallel. This allowssmoke and heat from a fire to dissipatewith respect to impactsto other storage facilities.The location of storage tanks to adjoiningproperty or exposures on adjacent exposures should be treated thesame as would be case with exposure to or from a refinery process, however the added consideration ofpublicexposure should not be overlooked.Process UnitsUnits operating at high pressures, at high or low (refrigerated) temperatures,having a large inventory of flammable fluid above its atmosphericboiling point,or handling of toxic materials are more hazardous than other process units.Historical evidenceof the petroleumindustry indicatesthat pumps, compressors,heaters are a common high volume source of leakage and should be as far aspractical from ignition sources and other critical equipmentFlaresThe general principlesfor the location of flares should be governedby the following0 They should be located as close as practical to the process units being served. This allows the shortestand most direct route for the disposal gas header and will also avoid passagethrough other risk areas.0 Flare should be located as remote from the facility and property line due to their inherent hazardousfeatures. They should be well away from high hazard areas or public occupied areas. A locationperpendicular to the prevailing wind direction remofe from the major sources of vapor releases andprocess or storage facilities is preferred. The chosen location should not allow liquids which may beejected from the flare system to expose the facility. This principal should apply even if a liquid knockout feature is incorporated.0 Where more than one flare is provided, the location of each should be mainly influenced by operationalrequirements, but the need for maintenanceand independent operation should also be considered.Critical Utilities and Support SystemsDuring a fire or explosion incident the primarily utilities may be effected in not adequately protected. Theseutilities may provide critical services to emergency systems that should be preserved. The most commonservices are mentioned below:FirewaterPumpsSeveral catastrophic fire incidents in the petroleum industry have been the result of the facilityfirewater pumps being directly affected by the initial effects of the incident. The cause of theseimpactshas been mainly due to the siting of the fire pumps in vulnerablelocations without adequateprotection measures from the probable incident and the unavailability or provision of other backupwater sources. A single point failure analysis of firewater distribution systems is an effectiveanalysis that can be performed to identify where design deficiencies may exist. For all high risklocations, fire water supplies should be available from several remotely located sources that aretotally independent of each and utility systemswhich are required for support.
    • 100 Handbook of Fire and Explosion ProtectionPower SuppliesPower is necessary to operate all emergency control devices. Where facility power sources ordistribution networks are unreliable or vulnerable self contained sources should be provided toemergency systems and equipment. Unless protected power, control and instrumentationcablingwill be the first items destroyed in a fire. The most obvious is local engine drives at fire pumps,batteries for emergency lighting, etc. However where ESD components located close to possiblefire or explosion exposures, simple and direct backup power supplies are usually provided forhigher reliability factors during an incident. These include spring return fail safe valves, local airreservoirs, etc. The capacity of the selected backup sources should be based on the WCCECommunicationFacilitiesCommunications plays a vital role in alerting and notifjing both in facility personnel and outsideemergency agencies that a major incident has occurred. Communication systems should not bearranged so a single point failure exists. Of primary concern is the provision of a backup source ofpower and a remote backup activation and signalingpost.Buoyancv and Propulsion CapabilityFloating vessels for offshore operations offer reduced installation costsbut also present additional vulnerability factors. All floating structuresmust ensure buoyancy integrity is maintained otherwise the vessel maysink with catastrophicresults. Similarlypropulsion are provided at someinstallationsto provided position stability. All major vessels are requiredby insurance requirements and most marine regulations to maintainbuoyancy systems and loss of position stability will impact ongoingoperations. Both of these systems can therefore be considered criticalsupport systemsand must be evaluated for risk and loss control measureseither thorough duplication and protection measures or a combination ofboth.Air IntakesAir intakes to heating and ventilation systems, air compressors for process, instrument andbreathing air, and to prime movers for gas compressors, power generation and pumps should belocated as far as practical from contamination by dust, toxic and flammable materials releasesources. They should not be located in electrically classified areas. If close to possible vaporreleases (as confirmed by dispersion analyses( they should be fitted with toxic or combustible gasaktection clevices to wam bi posslble aii intaltts naiai-asana snutdowh anaisolate tne incomingairductwork and fans.Fire ZonesPetroleum facilities located both onshore and offshore can be identified into "fire zones". These are areaswhere a fire can be expected to occur and be contained provided all safety and process emergency systemsare operable in addition the arrangement of the facility should be kept to the original design intent forsegregation and spacing factors that would prevent to spread of an incident. They are essentially based onthe area a liquid spillage might encompass or highly probable high pressure gas release fires. In this fashionthey are similar to electrical area classification drawing which outline areas vapors may be present but aregenerally smaller.The fire zone drawings serve as an aid in determining which areas need special protection measures such asadequate fireproofing, firewaterprotection systems,drainagefacilities,etc.
    • Segregation, Separation and Arrangement 101ArrangementArrangement means the orientation and assemblage of the equipment in a facility. By far the highestconcern is the arrangement vessels, columns, tanks and process trains containing combustible materials oflarge capacity, especially at high pressures or temperatures. To meet the needs of loss control but stillmaintain efficient operations high risk plots are arranged so they are never completely enclosed by otherprocesses or risks. A fire break, usually a road and sometimes pipe racks or open drainage system areprovided for both economical process pipe routings, access convenience and as a convenient method forseparation arrangement of related processes or storage areas. The possible loss of common pipe racks(piping and structural steel) are minimal compared to long lead time vessel and process equipment with hightechnology process control and instrumentation.Tanks should be grouped so that no more than two rows of tanks are provided within diked areas separatedby roads to ensure fire fighting access is available. Large tanks within a common diked area should beprovided with intermediate spill dikes or drainage channels between the tanks, as an intermediate level ofprotection against spill spread. When a small number of small tanks are located together the level of majorimpacts is less and therefor the financial risk is lower. In these cases it is acceptable not to provide full orintermediatedikes.A high pressure process or storage vessel should never be "pointed" at manned or critical facilities or otherhigh inventory systems for concerns of a BLEW of the container with the ends of the vessel rocketingtowards the vulnerablelocation. As a hrther inherent safety enhancement, spheroid separation vessels maybe used in some instances instead of horizontal pressure vessels (bullets). This reduces the possibility of aBLEVE incident directedtowards other exposures.Pipe racks normally divide a facility into major areas. For economy and process efficiencies the pipingarrangement is typically a central corridor in any facility. On either side of this pipe corridor or rack theprocess units are provided buy its nature dividesthe facility into units or process areas.Facility Access and EgressThe main access and egress to a facility preferably should be from the upwind side, with secondary points atcross wind locations. These locations should also be at a relatively higher elevations that the process areasso that possible spillageswill not hinder supplementalemergency aid measures from outside the facility. Asa minimum two access point should be provided to each facility.
    • 102 Handbook of Fire and Explosion ProtectionTable 9Comparison of Industry and Insurance Spacing Tables*Averageof Six Integrated Petroleum Operating Companies
    • Segregation, Separation and Arrangement 103Bibliography1. American Petroleum Institute (API), Recommended Practice 752. Management of Hazards Associated withLocation of ProcessPlant Buildings,Draft #6, API, Washington,D.C., 1994.2. Bland, W. F. and Davidson, R. L., PetroleumProcessinvHandbook,MrGraw-Hill,New York, NY, 1967.3. FactoryMutual (FM), FM 7-44. Spacingof Facilitiesin OutdoorChemicalPlants, FM, Norwood, MA4. Factory Mutual (FM), FM 7-458. Process Control Houses and Other Structures Subiect to External ExplosionDamage,FM, Norwood, MA.5. IndustrialRisk Insures (IRI), IM.2. Section 2.5.2.Plant Lavout and Spacingfor Oil and Chemical Plants, Tables 1and 2, IRI, Hartford, CT, 1992.6. Industrial Risk Insures (IRI), IM.8.0.1.1, Oil and Chemical Properties Loss Potential Estimation Guide, IRI,Hartford,CT, 1992.7. National Fire Protection Association (NFPA), NFPA 30. Flammable and Combustible Liauids Code, NFPA,Quincy, MA, 1993.8. United States Army (USA), TM 5-1300. Structures to Resist the Effects of Accidental Explosions, U.S.GovernmentPrintingOffice, Washington,D.C. 1975.
    • Chapter 9Grading, Containment, and Drainage SystemsDrainage and surface liquid containment systems are usually thought of as a supplemental process systemthat has little input into the risk analysis of a facility. Without adequate drainage capabilities spilledhydrocarbon liquidshave no avenue of dissipation except to be consumed by any potential fire or explosion.Liquid disposal systemsare also a potential source of hazard because of the possibilitiesof the formation anddistribution of explosive gas-air mixtures. Liquid drainage systems therefore play a key role in theavoidance, reduction and prevention of hydrocarbonmaterials that may result in fire and explosion incidents.Drainagephilosophiesand design features should be examined at the beginning of a facilitydesign.There are several drainage mechanisms are employed at petroleum and related facilities - surface runoff orgrading, spill containment (diking), gravity sewers (oily water and sanitary) and pressurized sewer mains,and lift station collection sumps.Drainage SystemsThe topography, climatic conditionsand arrangementsfor effluenttreatment will influencethe designof drainage systems for the control of oil spills resulting from the failure of equipment, overflows oroperating errors. Additionally the amount, spacing and arrangement of hydrocarbon processequipment will also influencethe features of a drainagesystem.An adequate drainage system should be provided for all locations where a large amount ofhydrocarbon liquids has the possibility of release and may accumulate within the terms of the riskanalysis frequency levels. Normal practice is to ensure adequate drainage capability exists at allpumps, tanks, vessels, columns, etc., supplemented by area surface runoff or general area catchbasins. Sewer systems are normally gravity flow for either sanitary requirements or oily surfacewater disposal. Where insuflicient elevation is availablefor the main header, lift stations are installedwith a forced pressure outlet header to a disposal or treatment system.Process and Area DrainageIn the process unit areas, drainage arrangementsshould ensure that spills will not accumulateor passunder vessels, piping or cable trays. Primary drainage should be provided by an underground oilywater sewer system (OWS) connected to area catch basins. An OWS system normally consist ofsurface runoff to collection troughs and area catch basins or process drain collection receptaclesconnected to underground header. The system mainly consist of an underground pipe network ofbranch lines connected to a main header through sealed connections usually catch basins and104
    • Grading, Containment, and Drainage Systems 105manholes. Fluids from the main header are routed to a central collection point from which they aretransferred to an oil and water separationfacility.A prime safety feature of the OWS is that it does not transmit combustiblevapors or liquids from oneprocess collection area to another area where it may cause a hazard or beunexpected Since fires, and even explosive flame fronts can spreadinside sewer pipingby flaming hydrocarbon vapors on top of firewater orsurface runoff, sewer systems should be designed with sealed (watertraps) to avoid carrying a burning liquid fiom one area to another. Thesealing liquid should always be water, otherwise combustible vapors arelikely to be released both to the atmosphereand in the drain line fiom thehydrocarbon sealing liquid. Once a drainage receptacle has be used forhydrocarbon disposal, either from surface drainage or process activitiesit shouldbe thoroughly flushedwith water to reestablish the water seal.Line segments that are sealed should be provided with a vent to allow any trapped gases to berelieved, otherwise hydrostatic vapor lock will occur which will prevent incoming liquids fromdraining into the system. Such vents should be located on the high end of the line segment so all thevapors will be released. Vent outlets should be located where they do not pose a hazard to thehydrocarbonprocesses or other utilities. Manhole cover plates in process areas should be sealed. Ifthe manhole has any openings it may allow gas to escape out of it instead of the sewer vent fordissipation. Overall the sewer grade should be away fiom shops, or occupied areas, to reduce thepossibilityof flammableliquids or vapors emittingfrom sewer openings located in nonclassified areas.Many incidents have been recorded of process system leaks entering sanitary sewers resulting inhydrocarbon vapor emissions from toilets that have ignited. Sanitary sewers should be providedwhich are entirely separate from oily water sewer (OWS) systems. Similarly process venting orblowdown systems should not connect to the sewer systems.Common practice and a general guide is to prevent combustible vapors from transmitting from oneprocess area to another process area, generally 15.2 meters (50 ft.)or more away. Usually unsealedreceptacles, such as drain funnels, tundishes, drain boxes, are routed to the nearest local sealed catchbasin and then into the oily water sewer main. The unsealed receptacles are only allowed in the sameprocess area equipment where if vapors where released from an adjacent unsealed receptacle it wouldbe "immaterial"due to the proximity to where the liquid is being drained and would normally emitvapors.In some cases a closed drainage system can be used which drains process components directly intothe oily water sewer. This has the advantage of avoiding releases of vapors in any instance, butassurance must be obtained that back pressure from one drainage location will not backfeed liquidsinto another drain point when two valves are open simultaneously or other drainage valves cancontain any backpressure on them from other drainage sources.Surface DrainageProvision should be made to eliminate the chance of liquid spreading to other processes or offsitelocations, even if failure of the underground gravity drainage network occurs. The design philosophyemployed should be to direct flammable liquid spills away from critical or high value equipment.They should be collected for disposal at locations as practically remote from the process equipmentas possible. These provisions usually consist of surface gradingto perimeter runoff collection points,impoundingareas or oily water separation ponds supplementedby directional curbing or diking. Thetypical surfacerunoff gradient employedis approximatelyone percent.Process areas are normally provided with hard wearing surfaces, such as concrete or asphalt, which
    • 106 Handbook of Fire and Explosion Protectionprovidesfor surface runoff if a suitable directional grade is established. The surface runoff should bearranged so that flow from broken lines or equipment is directed away from other facility processesor critical facilities. Surface drainage can be enhanced with low elevation diversion diking anddrainage channels. Although these enhancements are used assist in diverting surface liquids to aremote impounding area, slopped paving is the preferred method for spill collection. Paving ispreferred to untreated ground or crushed stone since flammable liquids may drain into a permeableground cover and accumulate on the surface of the ground water table. During fire incidents theymight float back to the exposed ground surface, forming additional fire hazards. Permeable groundcover will also allow ground water pollution to occur if hydrocarbonliquids can reach it.Drainage areas can be defined by the process fire area, which has been established by the spacing,segregation and arrangement provisions for the facility. Open drainage channels should be usedwhere they will not interfere with the use of the area, i.e., crane access, maintenance activities, etc.They should be designed to minimizeerosion, and if excessivevelocitiesare encounteredthey shouldbe paved. No more than 5 d s (1 5 Ws)velocity should be allowed in paved surface runoff channelsor troughs.Rainfall, firewater flow and process spillage should all be analyzed when design drainage systems.Process spillageshould be the most credible maximumvessel leakage or rupture. A rule of thumb inestimating the spread of spills can be made by using the approximationthat for an unconfined andlevel spill, 3.8 liters(1 gal.), of even a vicious liquid, will cover approximately 1.86 sq. meters (20 sq.fi.). In most cases, firewaterflowrates dominatethe design capacity of drainagearrangements.For small facilities(e.g., production separation),the normal practice in the design of surfacerunoff isto provide a centerline slope from the process area. This would also include provisions to segregatevessels and pumps from the impact of liquid spills. The runoff is collected into catch basins orcollected at the edge of the facility by a drainage channel.,For larger facilities (refineries, gas plants,etc.), the areas are graded to runoff towards a central collection point which also servesas a means toseparate on fire risk fiom another. Catch basins should be located away fiom equipment and criticalstructural supports since they may produce pools of liquids during spillage incidents. Drainagetrenches should not be located under pipe racks or other sources where if ignited they would producea line of fire under critical equipment. The number of catch basins provided to any process areashould also be limited, typically to two to prevent the number of "collection pools". A typicalapproach is to limit drainage areas to a maximum of 232.2 sq. meters (2,500 sq. R.) and size thecatch basins in this area for a maximum flow based on process spillageor fire water flows. All catchbasins should be properly (water) sealed to prevent the spread combustibleliquids or vapors to otherareas that are not involvedin the incident. Underground piping should also be buried where it can beaccessible should future problems require it to be uncovered. Generally such piping is not routedunder monolithicor slabconcrete foundations.Surface drainage should be adequate to drain the total volume of water that can be used during firefighting activities or storm water, whichever is greatest.Open Channels and TrenchesSurface runoff that is not collected in the oily water sewer, should be routed to perimeter orintermediate collection channels or trenches that route the fluids to a remote impounding area.Surfacedrainage routes, troughs, channels, collectionareas should not pass under or be located nearcable trays, pipe racks, vessels, process equipment or close to fire water lines where if ignited wouldcause produce impacts to critical equipment or release other hydrocarbon holdup sources. Opentrenches should not be used in a process area. Instead, an underground oily water sewer with surfacecatch basins should be provided. Historical evidence indicates may process fires have spread whensurfice channels are available Where drainage channels feed int~pipes or culverts, p r ~ v i . 4 ~ ~ ~should be made for preferential overflow direction in case of plugging or flooding of the pipe.
    • Grading, Containment, and Drainage Systems 107Typicalpractice is also to locate open channelsor trenches away from process areas containing heavyvapors, so they cannot collect and spread to other areas.Spill ContainmentWhere surface drainage cannot be employed for safe removal of liquids, diking may be employed toprevent the endangering of property or equipment. Dikes are primarily used to contain tank pump-overs, bottom leakages, piping failures and limit the spread of fluids during a fire incident - bothhydrocarbons and firewater runoff Accumulation of spilled liquids can be limited in quantity orremoved before the retention areas are overflowed through drainagelineswith control valves locatedoutside the diked area. Experience has shown that, under normal conditions, it is unlikely that thecapacity of an entire dike volume will be M y used or needed. Consequentially a dike area drainagemechanism should normally be kept closed until an incidentwarrants their opening.Dikes should be arranged so liquids will flow (with minimum exposure to pipeways) to a low pointwithin the enclosure remote from the equipment producing the spillage. Accumulated liquid canthem be easily drained or pumped into a liquid removal system.Pumping units are usually enclosed with a curbingto contain small leakages, in which a catch basin isprovided in the remote corner of the curbing enclosure. The grade within this enclosure is directedaway from the pumping unit and towards the drainagesewer connection. As an added safety featurean overflow trough from the curbed area is sometimes provided which connects remote drainagechannels, to divert large spillagesaway from the equipment.Drainage slopes within tank areas should ensure that any spills are drained away from tanks,manifolds or piping. Small fires that can occur in gutters or drains around tanks weaken connectionsto the storage tank and release the contents of /the tank. Any gutter encircling the tank should belocated at a safe distance from the tank and drain basins should not be located under tank mixers,major valves or manway entrances to the tank. The diked areas should be provided with animpervious surfacethat is will collect liquids towards a drainagecollection point.Dike walls should not hinder fire fighting efforts or generally impede the dispersion of vapors fromspilled liquids. Most industry standards require containment dikes to be constructed of an averageinterior height of 1.8 meters (6 fi.) or less. Where additional provisions have been made foremergency access and egress from the diked area allowances to this requirement can be made. Itshould be noted that an oil wave may occur in a diked area if the tank fails catastrophically during aboilover or slopoverevent. This wave could surge over the height of a typical dike wall.When several tanks are located within a single diked area, the provision of a mini-dike, Le., 305 mm(12 in.) to 457 mm (18 inches) high, between tanks, minimizes the possibility of minor leakagesendangering all the tanks.
    • 108 Handbook of Fire and Explosion ProtectionTable 10, Comparison of Dike Design Requirements
    • Grading, Containment, and Drainage Systems 109* Tank/vessel rupture or WCCE estimated leakage rate (may require rainfall provisions)* * Provided for incidental spillagesTable IIDrainage Requirements and Capacity Analysis
    • 110 Handbook of Fire and Explosion ProtectionBibliography1.2.3.4.5.6.7.8.9.American Petroleum Institute (API), RP 12R1. Recommend Practice for Setting. Maintenance. Inspection,Operation and Reoair of Tanks in Production Service,Fourth Edition,API, Washington,D.C., 1991.AmericanSocietyof MechanicalEngineers (ASME), A112.1.2.Air Gaps in Plumbing Svstems,ASME, 1991.American Society of Civil Engineers (ASCE), ASCE Standard 7-93. Minimum Design Loads for Buildings andOther Structures,ASCE, New York, NY, 1993.Instituteof Electricaland ElectronicsEngineers,Inc. (IEEE), IEEE 979, Guide for SubstationFire Protection, IEEE,Piscataway,NJ, 1984.Instituteof Electrical and Electronics Engineers, Inc. (IEEE), IEEE 980. Guide for Containment and Control of OilSpillsin Substations,IEEE, Piscataway,NJ, 1987.Industrial Risk Insures (IRI), IM.2. Section 2.5.3. Fire Protection Water & Spill Control for Outdoor Oil &ChemicalPlants, IN,Hartford,CT, 1992.National Fire Protection Association(NFPA), NFPA 15,Water Spray Fixed Svstemsfor Fire Protection, Appendix4-6.2, NFPA, Quincy,MA, 1990.National Fire Protection Association (NFPA), NFPA 30. Flammable and Combustible Liauids Code, NFPA,Quincy, MA, 1993.NationalFire Protection Association(NFPA),NFPA 328. Recommended Practicefor the Control of Flammable andCombustible Liauids and Gases in Manholes. Sewers and Similar Underground Structures, NFPA, Quincy, MA,1992.
    • Chapter 10Process ControlsProcess control plays an important role in how a plant process upset can be controlled and subsequentemergency actions executed. Without adequate and reliable process controls, an unexpected processoccurrence cannot be monitored, controlled and eliminated. Process controls can range from simple manualactions to computer logic controllers, remote fiom the required action point, with supplementalinstrumentation feedback systems. These systems should be designed such as to minimize the need toactivate secondary safety devices. The process principles, margins allowed, reliability and the means ofprocess control are mechanismsof inherent safety that will influencethe risk level at a facility.Human ObservationThe most utilized and reliable process control in the petroleum and related industries is human observationand surveillance. Local pressure and level gages along with control room instrumentation are provided sothat human observationand actions can occur to maintain the proper process conditions. First stage processalanns are provided to alert operators to conditionsthat they may not have already noticed. Typically whensecondary alarm stages are reached, computer control systems employed to automatically implementremedial actionsto the process.Instrumentation and AutomationAutomation and control of processing equipment by highly sophisticated computer control systems isbecoming the standard at most hydrocarbon facilities. Automatic control provides for closer control of theprocess operating conditions and therefore increased efficiencies. Increased efficiencies allow higherproduction outputs. Automation is also thought to reduce operator manpower requirements. Howeverother personnel are still needed to inspect and maintain the automatic controlling system. All processcontrol systems should be monitored by operators and have the capability for backup control or overridecommandsby human operators.Whatever method is used, there should be a clear design philosophy for the basic process control system(BPCS) employed at a facility that is consistent throughout each process and throughout the facility.Consistency in application will avoid human factor errors by operators. The philosophy should covermeasurements, displays, alarms, control loops, protective systems, interlocks, special valves (e.g., PSV,111
    • 112 Handbook of Fire and Explosion Protectioncheck valves, EIVs, etc.), failure modes, and controller mechanisms (i.e., PLCs). The reliability of thesystem should also be specified. If a process feature demonstrates that a major consequence has thepossibility of occurring, (as identified by the risk analysis, i.e., HAZOP, What-If Reviews), additionalindependent layers of protection (ILPs), such as instrumentation and control systems should be provided.These features should be of high integrity, so that the Safety Integrity Level (SIL)is improved. Somecommonly referred to systems are identified as high integrity protective systems (HIPS) or triple modularredundant (TMR).The alarm systems should have a philosophythat relates to the input data - number, types, degree of alarm,and displays and priorities. The information load on the operator has to be constantly taken intoconsideration,e.g., the distinction between alarms and status signalsversus operator action that needs to beinitiated.Control loops should have a fail safe functionas much as practical limitswill allowMost electronictechnology systems use digital electronicsin conjunction with microcomputertechnology toallow the instrumentation user to calibrate and troubleshoot the instrumentation from either a local orremote location. This capabilityis commonlyreferred to as "Smart"electronictechnology.Electronic Process ControlThe state of the art in process control for hydrocarbon process systems is computer microprocessors orcommonlyreferred to as PLCs (ProgrammableLogic Controllers). A distributed digital instrumentationandcontrol system supplementsthe overall process management system(PLC) design. Programmable electronicsystems are commonly used for most control systems, safety functions, supervisory control and dataacquisition systems (SCADA). These systems may consist of a distribute control system (DCS),programmable logic controllers (PLC), personal computers and remoter terminals, or combinationsover acommunicationnetwork.A distributed control system @CS) caters for centralized control but allows sectionalized local controlcenters with a clearly defined hierarchy. Operator interactionis provided with real-time video display panelsinstead of traditional metering instrumentsand status lights. The DCS fimctionally and physically segregatesthe process controls for systems or areas at separate locations or areas within a building. This segregationprevents damages or downtimeto a portion of a the system affecting the entire facility or operation,just asthe physical components are isolated and segregated for risk protection measures. Typically segregatedDCS controls are provided with their own shelters commonly referred to as Process Interface Buildings(PIB) or Satellite Instrumentation Houses (SEI). Protection and location of these installations should bechosen carefully and similar risk analyses chosen since impacts to their operations are just as critical to theprocess as a main control room would be.When the electroniccontrol is specified the followingfeatures should be criticallyexamined:1.2.3.4.5.6.The availabilityof the systemto functionupon demand.The selection of compatiblecomponents.Failure modes of the componentsin the systems and impact on system controlDesign and reliability of utility supplies.Control and integrityof software commands.Capabilitiesfor remote input, monitoring and control.
    • Process Controls 113Changesin display status should signifl changes in functional status rather than simply indicate a control hasbeen activated, for example, a lighted VALVE CLOSED indicator should signifl that the valve is actuallyclosed, not that the VALVE CLOSED control has been activated.There is no standard or specification within the industry which specifiesthe dual redundancy for PLCs usedfor process control functions. The requirement for control system redundancy is primarily a function of thedesired availabilityor demand of the process control system. Most control sytem availabilitypercentagesarein the range of 99 to 99.9%. Depending on the type of PLC system configuration defined, availabilitygenerally improves in relation to the amount of redundancy added to the various system components, butdoes not necessarily improve system reliability.Most published literature cites the MTBF for a PLC central processor between 10,000 and 20,000 hours(Le. 1.2to 2.4 yrs.), the MTBF of Input and Output(V0) interfacesis between 30,000 and 50,000 hours andthe MTBF of Input and Output (VO)hardware is between 70,000 and 150,000 hours. For the worst caseMTBF for the control system is the PLC-CPU or 1.2 years. This represents an availability of 99.76%assuming a mean time to repair the unit of 24 hours. If a dual CPU-PLC configurationwere provided withthe CPU in a running backup mode, using single VOs, the MTBF would almost double, but the overallsystem availability improves only slightly to 99.88%. Completly dual PLCs with dual I/O and CPUs in a1002 or 2002 voting arrangement are seldomused for normal process control systems but are instead usedfor certain safety systems where availability, failsafe and fault tolerant attributes are desired. Complete dualPLCs tend to be more complex and maintenance intensive.Process System Instrumentationand AlarmsSuggested control and instrumentationfor the management of process components are shown in API Rp14C which is still relatively the standard within the industry. All process control systems are usuallyreviewed by a Process Hazard Analysis, which will deem if the provided mechanism area is adequate toprevent a catastrophicincident.For high risk processes, dual level alarms level instrumentation(e.g., highhigh, low/low, etc.) and automaticprocess control (PLC, DCS, etc.) and shutdown, that is backed up by human supervision should always beconsidered. Where alarm indications are used they should provided such that an acknowledgment isrequired by an operator. Alarm indications should be arranged so their is a hierarchy of information andalarm status so that control operator do not become inundatedwith a multitude of alarm indications. If suchan arrangement exists, he may not be able to immediately discriminate critical alarms from non-criticalalarms. Operators sometimes have to make decisions under highly stresshl situations with conflictinginformation. It is therefore imperative to keep major alarms for catastrophic emergencies as simple anddirect as possible.Any critical safety related control function should be protected from impairment from an accidental eventthat would render the device unable to fulfill its function.Transfer and Storage ControlsThe highest process concerns for storage locations and transfer operations is the possibility of a tank orvessel rupture or implosion and overflow, These usually occur when during dynamic operations areongoing.All tanks should be furnished with level gaging instrumentation. Preferably the optimum design is one thatprovides an alarm before high overflow levels are reached and also shut off fill lines when the optimumfill level is reached to prevent overflow or rupture.Although not 100% reliable, check valves are usually installed in most piping systems to prevent backflow in
    • 114 Handbook of Fire and Explosion Protectionthe event of line rupture or segmental depressuring. Storage vessels or tanks recieving products frompipelines or automatic transfer systems are normally required to be fitted with high level alarms which maytrip shutoff devices.Burner Management SystemsFired heaters are extensively used in the oil and gas industry to process the raw materials into usableproducts in a variety of processes. Fuel gas is normally used to fire the units which heat process fluids.Control of the burner system is critical in order to avoid firebox explosions and uncontrolled heater firesdue to malfunctions and deterioration of the heat transfer tubes. Microprocessor computers are used tomanage and control the burner system.
    • Process Controls 115Bibliography1. American Petroleum Institute (API), RP 14F. Recommended Practice for Design and Installation of ElectricalSystems for OffshoreProduction Platforms,ThirdEdition, API,Washington,D.C. 1991.2. AmericanPetroleum Institute, (API) RP 540, Electrical Installationsin Petroleum Processing Plants, Third Edition,API, Washington,D.C., 1991.3. AmericanPetroleumInstitute(API), RP 551. ProcessManagementInstrumentation,First Edition,API, Washington,D.C. 1993.4. Center for Chemical Process Safety (CCPS), Guidelines for Design for Process Safety, American Institute ofChemicalEngineers (AIChE),New York, NY, 1993.5. Fisher, T. G., Alarm and Interlock Systems,Instrument Societyof America, (ISA), Durham,NC, 1984.
    • Chapter 11Emergency ShutdownEmergency shutdown capability is to be provided all petroleum facilities be it manual, remotely operatedor automatic. Inherent safety practices rely on emergency shutdown capability as a prime facet in achievinga low risk facility. Without adequate shutdown capabilities a facility cannot be controlled during a majorincident.Definition and ObjectiveAn Emergency Shutdown(ESD) systemis a method to rapidly cease the operation of the process and isolateit from incoming or going connections or flows to reduce the likelihood of an unwanted event fromoccurring, continuing, or escalating. The aim of an ESD system is to protect personnel, afford protection tothe facility,and prevention of an environmentalimpact from a process event.Design PhilosophyThe ESD system is distinguishedfrom other facility safety systems in that it responds to a hazard situationwhich may affect the overall safety of the entire facility. It is therefore considered one of the prime safetysystems that can be provided for any facility. Without an ESD system, an incident at a hydrocarbon facilitymay be provided with "unlimited"fuel suppliesthat can destroy the entire hciiity. Such situationsare amplydemonstratedby wellhead blowouts that can be fed from underground reservoirs and destruction of pipelineconnectionsat offshoreinstallationsaffecting the availabilityof further isolation means, e.g., "PiperAlpha".Facilities that do not have the capability to immediately provide an emergency shutdown should beconsidered high risks. Similarly, if the reliability of an ESD system is very poor the facility might beconsidered without adequate protection and therefore also a high risk.Activation MechanismsMost ESD systems are designed so that several mechanisms can initiate a facility shutdown.mechanisms are provided by both manual and automaticmeans.These116
    • Emergency Shutdown 117ESD ActionLevelTypicallythey may includethe following:Criticality0000Manual activationfrom a main facilitycontrol point.Manual activationfrom strategicallylocated initiation stationswithin the facility.Automatic activationfrom fire or gas detection systems.Automaticactivationfrom process instrumentationset points.345Levels of ShutdownEquipment Shutdown MajorEquipment Protective System Shutdown SlightNon-ESDProcess and Control Alarms RoutineThe activation logic for and ESD system should be kept as simple at possible. Typically most facilitiesspecifl plateaus or levels of ESD activation. These levels activate emergency measures for increasingamounts or areas of the facility as the emergency involves a larger and larger area or the degree of hazardfrom the initial event. Low hazards or small area involvement would only require a shutdown of individualequipmentwhile major incidentswould require a facilityshutdown. The shutdown of one of a facility shouldnot present a hazard to another portion of the facility otherwise both should be shut down. Typical levelsutilized in the petroleum and related industries are identifiedin Table 12.1 1 Total Facility Shutdown I Catastrophic2 I Unit or Plant Shutdown I SevereTable 12Typical ESD LevelsReliability and Fail Safe LogicThe design of an ESD system has normally been based on independence and fail-safe component utilization.Independence is obtained by physical separation,using separate process locations,impulse lines, instruments,logic devices, and wiring than that of the BPCS. This avoids common failures in the system. Fail safefeatures are obtained by ensuring that selected components in an ESD system are such that during a failureof a componentthe process reverts to a condition considered "safe". Safe implies that the process or facilityis not vulnerableto a catastrophic destructive event due to the release of hydrocarbons. For most facilitiesthis impliesthat pipelinesthat could supplyfuel to the incident (i.e., incomingand outgoing) are shut off andthat high pressure, high volume gas suppliesthat are located in the incident are relieved to a remote disposalsystem.ESD system performance is measured in terms of reliability and availability. Reliability is the probability acomponent or system will perform its logic function under stated operating conditions for a defined timeperiod. Availabilityis the probabilityor mean fraction of total time that a protective component or system isable to hnction on demand. Increased reliabilitydoes not necessarilyincrease availability.Reliability is a function the system failure rate or its reciprocal, mean time between failures (MTBF). Thesystem failurerate in non-redundant systemsis numerically equal to the sum of component failure rates.
    • 118 Handbook of Fire and Explosion ProtectionSLL AVAILABILITYFailures can either be fail-safe or fail dangerously. Fail safe incidents may be initiated by spurious trips thatmay result in accidental shutdown of equipment or processes. Fail dangerously incidents are initiated byundetected process design errors or operations, which disable the safety interlock. The fail dangerouslyactivation may also result in accidental process liquid or gas releases, equipment damage, or fire andexplosions.RISK REDUCTIONFACTOR(RRF)ESD systems should be designed to be sufficientlyreliable and fail safe that a (1) accidental initiation of theESD is reduced to acceptable low levels or as low as reasonably practical, (2) availability is maximized as afunction of the frequency of system testing and maintenance, and (3) the fractional MTBF of the system issufficiently large to reduce the hazard rate to an acceptable level, consistent with the demand rate of thesystem.Fail safe logic is normally referred to as de-energized to trip logic, since any impact to the inputs, outputs,wiring, utility supplies or component function should de-energize the final output allowingthe safety deviceto revert to its fail safe mode. The specification of fail safe for valves can be accomplishedby failing close(FC), failing open (FO) or failing steady (FS), i.e., in the last position depending on the service the valve isintended to perform. Valves that are specifiedto fail close on air or power failure should be provided withspring return actuators. The use of accumulators to meet control valve fail safe conditions should beavoided since these are less reliable fail safe mechanism and are more vulnerable to external impacts of anincident. Control mechanisms including power, air or hydraulic supplies to valves emergency valves(isolation, blowdown, depressuring, etc.) should be fireproofed if the valves are required to be operableduring a fire situation.For ESD isolation valves @e.,EIVs) a fail safe mode is normally defined as fail closed in order to preventthe continued flow of fuel to the incident. Blowdown or depressurizationvalves would be specified as failopen to allow inventoriesto be disposed of during an incident. Specialcircumstancesmay require the use ofa fail steady valve for operationalor performance reasons. These applications are usually at isolation valvesat components, i.e., individualvessels, pumps, etc., where a backup EIV is provided at the battery limitsthatis specifiedas fail closed. The fail safemode can be defined by the action that is taken when the ESD systemis activated. Sincethe functionof the ESD system is to place the facility in its safest mode, by definitiontheESD activation mode is the fail safe mode.The utilization of a fail steady - fail safe mode may allow an undetected failure to occur unless additionalinstrumentation is provided on the ESD system components or unless the system is constantlyhlly functiontested. The prime feature of a full fail close or fail open failure mode is that it will immediately indicate if thecomponentis hnctioning properly.The different safety integrity levels normally applied within the petroleum and related industries are usuallythe following:0 1 BPCS - Inherent I None1 1 90 - 99% I 10 - 1002 1 99 - 99.9% 100- 1,0003 1 99.9 - 99.99% I 1,000- 10,0004 1 99 99 - 99 999% I 10.000 - 100.000ITable 13Typical Safety Integrity Levels (SlL)
    • Emergency Shutdown 119Generally by increasing the independent layers of protection (IPLs), which are applied to a potentialhazardous event, the SJL number can be reduced. It should be noted that a SIL Level of 4 is seldom used inthe petroleum or related industriesbut is common throughout the avionics, aerospace and nuclear industries.Safety Integrity level one equates to a simple non redundant single path design, designed to fail safe with atypical availability of 0.99. Level two involves a partially redundant logic structure, with redundantindependent paths for elementswith lower availability. Overall availability is in the range of 0.999. Levelthree is composed of a totally redundant logic structure. Redundant, independent circuits are used for thetotal interlock system. Diversity is considered an important factor and used where appropriate. Faulttolerance is enhanced since a single fault of an ESD system component is unlikely to result in a loss ofprocess protection.ESD/DCS InterfacesWhere ESD and DCS systems are provided, they should be hnctionally segregated such that failure of theDCS does not prevent the ESD from shutting down and isolating the facilities. Alternatively, failure of theESD system should not prevent an operator from using the DCS to shut down and isolatethe facility. Thereshould be no executablecommands over the ESD-DCS communicationslinks. Communicationlinks shouldonly be used for bypasses, status information and the transmission of reports. Confirmation of ESD resetactionscan be incorporated into the DCS but actual reset capabilityshouldnot.Activation PointsThe activation points for ESD systems should be systematicallyarranged to provide the optimum availabilityand afford adequate protection to the facility. The followingguidelinesprovide some features that should beconsidered.The activationpoints should be located a minimum of 8 meters (25 ft.) away from a high processhazard location but not more than 5 minutes away from any location within the facility. 5minutes is taken as the maximum allowabletime sincehistorical evidenceindicatesprocess vesselrupture may occur after this time period from flame impingement. If risk analysis calculationsdemonstratelonger vessel rupture periods are expected, longer time periods may be acceptable.The chosen locations should be preferably upwind from the protected hazard. Downwind sitesmay be affected by heat, smokeor toxic gases.They should be located in the path of normal and emergency evacuation routes from theimmediate area. In an panic situation personnel may immediately evacuate and not activateemergencycontrols if they are located at inconvenientlocations.Locating sites hrthest from the sources of largest liquid holdups or highly probable leakagesources (i.e., the relativelyhigher hazards) is preferred.They should be located near other emergency devices that may need immediate activation in anemergency@e.,fire water monitors, manual blowdown valves, etc.).The main access into the affected area should not be not impaired. Location of activationpoints
    • 120 Handbook of Fire and Explosion Protectionin normal vehicle or maintenance access routes will affect operations and cause the device to beeventuallyrelocated or damaged.The activation point should be mounted at a height which is convenient to personnel. Theergonomicsof personnel accessto emergencycontrols should be accommodated.Manned control rooms should always be provided with hardwired ESD activation points locatedon the main control console easily accessibleto the operators.Activation Hardware FeaturesThe hardwired ESD activation means is usually a push in knob or button. Confirmed action of the pushbutton should be always be required to manually activate the ESD system in order to prevent accidentalactivations. Most commonly a protective cover is fitted over any of the push button or manual activationdevices. All devices should onlybe manually resettable.Each activation point should be labeled to area of coverage and provided with and identification as to whichvalves it operates or equipment it shutdowns. A specific identifier number should be assigned to eachdevice. The location itself should be highly visible, preferably highlighted in contrasting colors to normalequipment housings.In some instances it may be beneficial to maintain process inventories of certain process vessels until theincident is actually threatening the container. The inventory of the vessel may be crucial to the restart of afacilityor the contents may be highly valuable. Loss of the inventory may be criticized if frequent false tripsof the ESD blowdown system occur. In these cases an automatic fbsible plug blowdown valve could beinstalled which would only activatefrom the heat of a real fire incident. In this way, a false disposal of theinventory can be avoided.Isolation Valve RequirementsThe failure mode of ESDVs for gas processing areas should always fail in the closed position, since this isthe only mechanism to resolve gas fed fires or prevent explosive vapor buildups. The valves should beprovided with an automaticfail close device such as an actuator with spring return specification.ESD valves should lock in the fail safe mode once activated and be manually reset once it has beenconfirmedthe emergencyhas passed or has been resolved.The emergency isolation devices should be arranged so that they can be fully function tested withoutaffecting the process operation. This entails that a full flow bypass should be installed at each emergencyisolation valve. These bypass installations should be locked closed when not in service for fknctional testingthe ESDV.Where MOV or AOVs are selected as ESDVs they should as a minimum have a back up activation powersources and the utility service lines should be highly reliable and protected against an incident. It should benoted that full motor operated and air operated ESDV do not fully equate to a fail safe spring return valve,even if frequent fbnctionai testing is performed. The reliability of an internal spring return actuator isconsidered higher than a self contained MOV or AOV with its own local power source and protection ofcabling. This is because that additional components of a MOV or AOV contribute to additional failurepoints and will also have a higher level of vulnerability from external events that the internal springmechanisminherentlycontains.
    • Emergency Shutdown 121Emergency Isolation Valves (EIV)Emergency isolation valves (EIV) should be located based one two principals (1) the amount of isolatableinventory that is desired and (2) protection of the EIV from the affects of external events. EIV valves arenormally required to have a firesafe rating (i.e. minimal leakage and operability capability, Ref Table 14).Valves and their actuating mechanisms should be afforded adequate protection when they are required to belocated in an area that has potential to experienceexplosionand fire incidents.Subsea Isolation Valves (SSIV)Subsea pipeline emergencyisolationvalves for offshore facilitiesare provided where a risk analysisindicatedtopside isolation may be considered vulnerable. They should be protected from ship-impacts, anchordragging, flammableliquid spills and heavy objectsthat may be dropped from the offshorefacility.Protection RequirementsESD system componentsthat are located in areas that would be considered direct fire exposures, i.e. withinor above fire hazardous risk areas should be provided fire protection measures to ensure integrity duringESD operation and the duration of the major effortsto control the emergency.Valve ActuatingMechanisms: 15-20minutes H rating (H15 or H20,plus blast if applicable)DirectlyExposed Valves: 60-120 minutesH rating (H60 or H120, plus blast if applicable)Actuating mechanisms include control panels, air receivers, valve actuators, instrumentation controls ortubing, etc.
    • 122 Handbook of Fire and Explosion ProtectionTable 14Firesafe Valve Test Standards
    • Emergency Shutdown 123System InteractionsPetroleum facilities exist where the operators are hesitant to activate the ESD system for fear of rupturingthe incoming production pipelines due to their poor construction. This points out the fact that allmechanismsthat introduce a change to the normal operating configurationof the system must be analyzed todetermine what effect the proposed actions will produce. Whenever an ESD isolation valve is closed it willstop incomingor outgoingflows which may produce instantaneouspressure variationsthat can detrimentallyaffect the process system. An analysisof measures to prevent additional consequencesshould be undertakenwhere sucheffects are possible, such as slowervalve closingtimes, increased integrity of piping systems,etc.
    • 124 Handbook of Fire and Explosion ProtectionBibliography1.2.3.4.5.6.7.8.9.10.11.12.American Petroleum Institute (API), Spec 14A. Specification for Subsurface Safetv Valve Eauipment, EighthEdition,API, Washington,D.C., 1994.AmericanPetroleumInstitute(API), RP 14B. RecommendedPractice for Design. Installation. Repair and Operationof SubsurfaceSafetyValve Systems, Third Edition,API, Washington, D.C., 1990.American PetroleumInstitute(API),RP 14C. RecommendedPractice for Analvsis, Desisn. Installationand Testingof Basic SurfaceSafetvSvstemson OffshoreProduction Platforms, Fourth Edition,API, Washington, D.C., 1991.American Petroleum Institute (API), Spec 14D, Specification for Wellhead Surface Safetv Valves and UnderwaterSafetvValves for Offshore Service,Eighth Edition,API, Washington, D.C. 1991.American Petroleum Institute (API), RP 14H. Recommended Practice for Installation and Repair of Surface SafetyValves and UnderwaterSafetvValves Offshore, Third Edition,API, Washington,D.C. 1991.American Petroleum Institute (API), Spec 16D. Specification for Control Systems for Drilling Well ControlEaubment, First Edition,API, Washington,D.C. 1993.AmericanPetroleum Institute (API), Std 607, Fire Test for Soft-SeatedQuarter Turn Valves, Fourth Edition, API,Washington,D.C., 1993.Center for ChemicalProcess Safety (CCPS), Guidelines for Safe Automation of Chemical Processes,AIChE, NewYork, NY, 1994.Kletz, T. A., Immovina ChemicalEngineeringPractices, SecondEdition, HemispherePublishingCorp., 1990.InternationalElectrotechnicalCommission(IEC), IEC-SC65A. Safetv SystemDesign, Draft Standard,IEC, 1994Instrument Societyof America (ISA), draft standard SP-84.01. Applicationof Safety Instrumented Systems for theProcess Industw, Instrument Societyof America,Research Triangle Park, NC, 1994.National Fire Protection Association (NFPA), NFPA 79, Electrical Standard of Industrial Machinery, NFPA,Quincy,MA, 1991.
    • Chapter 12Depressurization, Blowdown and VentingHydrocarbon processing facilities pose severe risks with respect to fire, explosions and vessel ruptures.Among the prime methods to prevent and limit the loss potential from such incidents are the provisions ofhydrocarbon inventory isolation and removal system. These systems are commonly referred to in thepetroleum industry as ESD (emergency shutdown) and depressuring or blowdown. Although moststandards and practices acknowledgethe need for depressuringcapabilities the exact determinationof theirrequirement is not wholly defined. NFPA fire codes and standards rarely mention the subject.ObjectiveTypically hydrocarbon process vessels are provided with a pressure safety valve (PSV), to relieve internalvessel pressurethat developsabove its designed working pressure. The purpose of the PSV is to protect thevessel from rupturing due to overpressure generated from process conditions or exposure to fire heat loadsthat generate additional vaporization pressures inside the vessel. The engineering calculation behind thisapplication assumes that the process vessel steel strength is unaffected by direct fire exposure causing theincrease in pressure. If the vessel is kept at or near its design temperature this can be assumed the case,however when steel is exposed to a high temperature fiom a hydrocarbon fire its capability to containnormal operating pressure deteriorates rapidly sometimes within a few minutes. Since the strength of thematerial is rapidly deterioratingduring this process, regardlessof the vessel internal pressure. A rupture of avessel can easily occur below the operating pressure of the vessel, within minutes of the vessel beingexposed to a major heat source.Pressure safety valves (PSVs) are typically sized to activate at 121% of the working pressure for fireconditions and 110% for the working pressure for non-fire conditions, and only to prevent vessel"overpressure", not to relieve operating pressures. A fire exposure may weaken a process vessel steelstrength below the strength needed to contain its normal operating pressure. In this case the vessel mayrupture before or during activation of the PSV, when its it trying to relieve pressures above operatingpressures.Two major hazards may occur from hydrocarbon pressure vessel failures. The vessel rupture itself and thepossible formation of a vapor cloud as a result of the rupture. If the vessel ruptures it will produce flyingprojectiles and usually release large quantities of flammable vapors. The flying projectiles may containsufficient momentum to affect other areas. The projectiles could harm individuals or damage thehydrocarbon facility, possibly increasing the incident proportions. Secondly, the released gas from apressurized vessel may cause a flammablevapor cloud to occur. If some amount of congestion is present orany amount of turbulence of the cloud occurs, an explosive blast may result if the cloud contains enoughmaterial and finds an ignition source.125
    • 126 Handbook of Fire and Explosion ProtectionIndustry literature typically cites concern with open air explosionswhen 4,536 kgs (10,000 lbs.) or more offlammable gas is released, however, open air explosions at lower amounts of materials are not unheard of.When the release quantity is less than 4,536 kgs (10,000 lbs.), a flash fire is usually the result. The resultingfire or explosion damage can cripple a hydrocarbon processing facility. Extreme care must be taken toprevent the release of hydrocarbonfiom vessels resulting in vapor releases and resultant blast overpressure.Measures such as hydrotesting, weld inspections, pressure control valves, adequate pressure safety valves,etc., should all be prudently applied.To overcome the possibility of a vessel rupture from a hydrocarbon fire exposure several methods areavailable. Depressuring, insulation, water cooling or draining are usually employed in some fashion toprevent of the possibility of a vessel rupture from its own operating pressures. A generalized method toqualitatively determine the effect of a hydrocarbon fire on the strength of vessels constructed of steel isavailable. With this method one can estimate the time for a vessel to rupture and therefore the need toprovide protective measures.API conducted open pool hydrocarbon fire exposure tests (mostly naphtha and gasoline fires), on processvessels during the 1940s and 50s.This data was plotted using the parametersof(1) Fire exposure temperature.(2) Rupture stress of the vessel.(3) Time for rupture.These were plotted and are compiled in API RP 520, Chart D-2 (page 55). The data plotted is for vesselsconstructed of ASTM A-515, Grade 70 steel, a steel typically employed for process vessels. If othermaterials are used an allowance for their stress characteristics under heat application needs to be made.Therefore a general determinationof the need for protectivemeasures, such as depressurization,can be madefor a particular vessel by comparison to the D-2 chart and selected fire exposure temperatures. It should benoted that this is the best availablefire test exposure data in the public domain. Improved methods and testdata may be available in the kture to refine the calculation methods.UnderwritersLaboratories (UL) high rise (hydrocarbon)fire test UL 1709, has an average fire temperatureof 1093 O C (2,000 OF) after 5 minutes. Therefore unless the an actual fire exposure heat radiation inputcalculation has been made, either a worst case fire exposure temperature could be assumed or a standardtemperatureto the limits of UL 1709could be applied.Fireproofing material is considered to fail if any individual thermocouple reaches 649 OC (1200 OF). TheAPI recommended practice does not define the surface temperature from a fire exposure to be applied forthe purposes of calculating rupture periods, but providesdata from 482 OC (900 OF) to 760 OC (1400 OF) in38 OC (100 OF) increments to determinerupture times. It should be rememberedthat fiee burning fires as arule do not achieve theoretical combustion temperatures for the fiels involved. Petroleum fires can reach ashigh as 1300 OC (2400 OF) but average 1000 O C (1850 OF) because of the various factors involved, i.e.,cooling of the fire ball, winds, and geometry. Thus some engineeringjudgment of the arrangement of thevessel involved should be applied in selectingthe appropriate fire exposure steel temperature. Typically 649OC (1200 OF) is chosen as a starting point as this correlates well with fireproofing test requirements. Aparticular point noticed when using the API chart is that a 100 degree C (212 OF) difference in the fireexposure temperature can have a dramatic difference in the time till a vessel rupture. Therefore the chosenexposure temperature has to be chosen carefilly and adequatelyjustified.
    • Depressurization, Blowdown and Venting 127The ASME pressure vessel rupture stress formula is appliedto calculatea vessel stress is:S = P(R+0.6t)EtWhere:S = Rupture StressP = OperatingPressure in PsigR = Shell Inside Radius, Incht = ShellWall Thickness, InchE = Weld Joint Efficiency (generallyassume 100%)The shortest time known for a vessel to rupture from recorded incidents is thought to be 10 minutes.Rupture periods calculated for less than ten minutes should therefore not be assumed, as the historicalevidence and the typical growth of a hydrocarbon fire would indicate that the immediate rupture of a vesseldoes not occur. Further investigationsmay be carried out verity if fire exposure conditions could producesuch results (e.g.,flange leak, gas fire exposures, etc.).If vessel is insulated, some credit can be taken on the reduced heat input rate provided by the insulation, butthis depends upon the quality and thickness of the insulation, plus the time for the insulation to raise theambient exposure temperature. Typically in sizing relief valves, it is normally assumed that lightweightconcrete insulation (fireproofing) reduces the heat input to approximately one third of its original value.Therefore depending on the rating of the fireproofing, the t h e till a vessel rupture from operating pressurescan be increased. The time delay of the fireproofingmaterial can be added to the time it takes to cause thesteel to weaken and rupture. Commercially available hydrocarbon fire rated fireproofing materials areavailable in several hours of fire resistance periods. If connecting pipelines are not isolated with an ESDvalve or insulated from fire sources,they could also be a source of hydrocarbon release that have to be takeninto account when makingthese assumptions.Similarly if a vessel is provided with a reliable and dependable water cooling (i.e., firewater deluge waterspray), according to recognized standards, (e.g., NFPA 15, Water Spray Systems for Fire Protection), thatwould not be affected by an explosion blast pressures or the fire exposure, it may theoretically demonstratethat a vessel does not need a depressuring system for the prevention of rupture from fire exposures.SimilarlyAPI RP 2000 does not allow credit for water cooling sizing pressure relief valves unless they aredemonstratedto have extremelyhigh integrity during accidental events.If the area under the vessel is provided with adequate drainage capability credit may also be taken for areduced heat input due to the runoff of any flammableliquids producing the fire exposure. Usually drainagerequirements to NFPA 30 (Flammable and Combustible Liquids Code), would have to be met, namely 1percent to a 15.2meter (50 ft.) radius. Published literature suggests that an uninsulated vessel rupture timecould be increased 100%for a highly effectivedrainage system.Two examples on the technique to calculate vessel rupture periods have been prepared and are shown inFigures4 and 5.
    • 128 Handbook of Fire and Explosion ProtectionSEPARATOR (Honzontal)ASSUMPTIONS: Size 104" 1.0.x 50-0" S/SShell Wall Thickness 112"Material of ConstructionOperating Presssure 50 PsigDesign Pressure 90 PsigNormal Liquid LevelLiquid Sp. Gr. 1.aA515 Gr. 705-0" from bottomS = P (R + O.Gt)/Et ref.: ASME. DIV. Vlll for circumferential stress)S = 50 (60+ 0.6 x 0.5)/1 .Ox 0.5S = 6,030psiWhere: S = Rupture StressP = Operating Pressure in PsigR = Shell inside radius, Incht = Shell Wall Thickness, InchE = Joint efficiency (assumed 700%)From Figure 0 2 (API 520, page 55)Time before rupture at 6,030psi and 1,300deg. F is approximately 5 HE.CONCLUSION: Depressurization system is not required.HORIZONTAL SEPARATORFigure 4
    • Depressurization, Blowdown and Venting 129CRUDE STABILIZEilASSUMPTIONS: Size 54" 1.0 x 40-0" S/SShell Wall Thickness 7116"Material of ConstructionOperating Presssure 150 PsigDesign Pressure 175 PsigNormal Liquid LevelVessel is insulated but no credit given for insulationLiquid Sp. Gr. 0.a5A5 15 Gr. 705-0" from bottom seamS = P (R + 0.6t)Et (Ref. ASME, DIV. Vill FOR CIRCUMFERENTIAL STRESS)S = 150 (30+ 0.6x 0.4375)~.Ox 0.4375S = 10,374 PsiWhere: S = Rupture StressP = Operating Pressure in PsigR = Shell inside radius, Incht = Shell Wall Thickness, InchE = Joint efficiency (assumed 100%)From Figure D-2 (API 520, page 55)Time b a r e rupture at 10,374 psi and 1.300deg. F is approximately 0.3 hoursCONCLU.SION: Depressurization system.is required.I ICRUDE STABILIZERFigure 5
    • 130 Handbook of Fire and Explosion ProtectionOnce a time period has been established when a vessel might be expected to rupture, this needs to becompared against the WCCE for the facility. A very short duration fire exposure would imply that a vesseldepressurization may not be necessary. Typically most hydrocarbon facilities are provided with an ESDsystem, which at the very minimum should isolate the incoming and outgoing pipelines. In this fashion theremaining major fuel inventory at the facility is what remains in vessels, tanks and the piping infrastructure.It should also be considered that d e r 2 to 4 hours of a hydrocarbon high temperature fire, usuallyequipment or facility salvage value is minimal. So beyond these periods, little value is gained in additionalprotection measures. Typically if the rupture period is of a magnitude of several hours, the need fordepressuring (or blowdown) is not highly demonstrated or recommended.Normally, emergency vessel depressuring is to be automatically activated through a facility ESD level 1(worst case) interface and completed in less than 15 minutes. A vessel should be depressurized to aminimum of 50% of its design operating pressure or preferably completely depressurized, remaininginterconnectingvessels are also depressurized. If vessels are not completely depressurized, there is still arisk of vapor release from the remaining pressure (ie., &el inventory) in the vessel or piping. Anengineering evaluation of depressurization arrangements and calculation of depressuring periods should beperformed.Certain conditions and arrangements (process restarts for example) may preclude the provision of anautomatic and immediate depressuring system for all vessels. Some volumes of gaseous products may benecessary for an adequate process restart. If the facility where to accidentally depressurize, the operationmay suffer an economic business interruption loss if gas supplies have to be obtained from outside thefacility. In these cases alternativeprotection methods may be employed. Where vessels are not located indense processing areas, subject to adjacent impact time delay and local fusible plug activated depressuringoutlet valves, insulation (fireproofing), dedicated firewater deluge, adequate and immediate drainage, etc.,should all be considered. Remote placement of the subject vessel is another yet costly alternative. Anengineeringanalysis should be performed when a fully automatic (ESD) depressuringsystem is not provided.Published literature also suggeststhat explosions and major damage are very unlikely when less than one tonof material is released. API RP 520 additionallysuggest that vessels operated at or below 690 Wa (100 psi)typically are not provided with depressurizationcapability.
    • Depressurization, Blowdown and Venting 131The following is a general guidelinethat may be used to generally classifLwhich process vessels may needdepressurizationcapabilities:Vessels RequiringDepressurizationCapability:A vessel operated above 690 Wa (100 psi).The vessel contains volatile liquids (e.g., butanes, propanes, ethanes, etc.) with vapor pressuresabove atmospheric.Operationalrequirementsexist (e.g., compressorblowdowns).A fire condition may occur that weakens a vessel to below safe strength levels (as defined by APIRP 520, Part 1,figureD-2), within several hours, which may cause significantexposure losses.Vessels Which May Not Require DepressuringCapability:A vessel operated at or less than 690 Wa (100 psi).A vessel containing less than 907 kgs (2,000 Ibs.)of vaporsA vessel whose time to rupture from a fire exposure is more than several hours.A vessel provided with fireproofinginsulation rated to withstand the expected fire exposures untilother protection measures are employed(e.g., effectivemanual firefightingis available).A vessel provided with a firewater deluge system to protect against hydrocarbon fire exposures forthe duration the worst case plausibleincident.A vessel whose time to rupture, insulation, fixed fire water protection or drainage arrangementswould not cause the vessel to rupture during the process incident.A vessel, which if a rupture occurred due to a fire exposure would not endanger personnel, damageimportant or critical facilities,cause significant finankialimpacts, create an environmentalhazard orcreate an undesirablereaction from the general public.The objectives of depressuring are (1) to prevent a vessel from rupturing during a major fire exposure (fromthe weakened condition of the vessel steel), (2) to prevent further fire escalation and (3) to minimize theimpacts to the vessel itself. It is therefore incumbent to depressure a vessel so that its stress is less thanthe stress to cause a rupture from fire conditions. These stresses and rupture periods can be estimated todetermine the need for depressuring systems for hydrocarbon vessels. These estimates can provide a roughestimate for the need of a depressurization system for a particular hydrocarbon process.Vapors from depressuring valves are typically routed to a blowdown header and then to a flare to safelyremove the vapors from the area and dispose of it without impact to the environment. A special concernwhen high levels of pressurized gases are released into a piping system is the possibility of auto-refrigera-tion of the piping material that may cause a brittle fracture. A process engineer should verify which pipematerials and flow rates, specified for the depressurization system, are suitable for the pressures, flows andgases contempla?edOnce calculations are completed on a depressurizationsystem it will become readily apparent high volumesof gases will be flowing through the header to a flare. In some cases the practicality of simultaneouslydepressurizing all of the process equipment and vessels will be difficult to accomplish. In these cases asequential blowdown of the vessels should be considered. Providing for the "worst" vessels first orcontrollingthe systemto blowdownthe area most affected first are desirable options.High noise levels may also be generated when high flows are encountered. In these circumstances, specialnoise reducing fittingsare availableto limit noise impactsfrom the systemto the surroundingarea.
    • 132 Handbook of Fire and Explosion Protectioni YESiIS VESSEL OPERATING NOPRESSURE > I00 PSI > *tNOIS VESSEL VOLUME> 0.5 cu. FT. *YESAiNO* NOiIS WORST CASE flRE> I O MIN.YES*1s KSSEL LOCATED IN AOENSE PROCESSING AREA *MS*ESTIMATE MSSEL RUPTURETIME PER API 520. FIG. 0-2i NOrIS MSSEL INSULATED 1iIAOO nME PERIOO TO RUPTURETIME FOR INSULATIONOOES MSSEL H A M coo0ORAINAGE k JET flREIMPINGEMENT IS MINIMAL aiIA 0 0 TIME OELAY FOR DRAINAGEL LOW JET FIRE IMPACTIS Mssa PROWOEO WTHWATER SPRAY PROTECTIONYESA00 TIME FOR OURAnON OFflRE WATER SPRAYIDEPRESSJRIZATIONNOT NEEOEOPROWOE MEANSro OEPRESNREFigure 6KSIIS FIRE DURATICN LONGERW A N n u € ro RUPTURE *IOEPRESSURINCs n m NEEOEOJ.No PROCESS VESSEL DEPRESSURIZATIONFLOW CHARTDEPRESSURIZATION NOT NEEDEO/Figure 6
    • Depressurization, Blowdown and Venting 133BlowdownBlowdown is the removal of the liquid content of vessels and equipment to prevent their contribution to afire or explosion incident. Blowdown is similar to depressurization but entails liquids instead of gases. Aliquid blowdown should never be sent to the facility flare that is designed to only handle gaseous materials.A liquid release out of the flare may result in a flare out, and if the flare is elevated a shower of liquids ontothe process facilities. Ideally liquid blowdowns should be routed to facilitiesthat are specifically designedtohandle large quantities of liquid materials. The blowdown could be routed to a storage tank, open pit,another process area or the pressurized sewer. A blowdown to a tank is generally avoided since entrainedgases may cause the tank to rupture. Similarly disposal to a pit is not desired as it poses the hazard ofexposed combustibleliquidsthat can ignite.VentingDirect venting of hydrocarbon or toxic gases to the atmosphere should be avoided for thefollowingreasons.(1) It may create a combustiblevapor cloud with fire or explosion possibilities(2) It may be harmfid to personnel.(3) It may be an environmentalpollutant.(4) It is a waste of the fuel gas.. , -(5) It represents a poor communityor public image to releasewastes to the atmosphere.(6) It may be a violation of the national or local environmentalgovernmental regulations.(7)Remotely vented gases may not adequately disperse, then drift considerable distances andignite.Whenever possible waste vapors or gases should be disposed of through the facility flare system orreinjected into the production process for recovery. Non polluting materials such as steam can be freelyvented to atmosphereif they do not pose burn hazards to personnel.FlaresIn most hydrocarbon operations excess gas and vapors have to disposed of safety, quickly withoutenvironmentalimpact. Where the gas or vapor cannot be converted into usefd energy they are routed to aremote point for safe incineration, called flaring. Flares are the most economical and customary means ofdisposing of excess light hydrocarbongases in the petroleum and chemical industries. The primary finctionof a flare is to convert flammable, toxic or corrosive vapors to environmentallyacceptablegases for releaseinto the atmosphere. Both elevated or ground flarescan be used.The type of flare used depends on several factors including:(1)(2)(3)(4)Available space of onshore or offshore arrangements.Characteristicsof the flare gas - composition, quantity, pressure, etc.Economicsboth initial capital costs and periodic maintenance.Public impression(i.e., if flaringis smoky or noisy the general publicwill object to itsoperation).The primary features of a flare are safety and reliability, while the primary objective of the flare is to preventthe release of any unburned gases. In reviewingexistingfacilitiesworldwide, from Russia to South America,onshore and offshore, most installations have admitted either officially or unofficially that on occasion, aliquid release has occurred from the tip of the flare stack. This has occurred even with the installation of aflare header liquid knock out drum. In most cases this has caused no apparent problems although in a few
    • 134 Handbook of Fire and Explosion Protectioncases it has been disastrous. It is suspected liquid releases occur much more frequently than is actuallyreported. Technically the problem may be because most flare systems are designed for unrestricted gas flowthrough the flare header and knock out drum, but which induce liquids to carryover. Therefore thepossibilityof liquid releases from vapor disposal flarescannot be entirely ruled out.During a typical plant design, the flare location is usually examined. Some experts suggest that a flareshould be located downwind and while others propose it should be upwind of the facility. This based on theassumption that a flare may overflow with liquids and therefore should be downwind so these don’t fall onthe plant, while vice versa, a plant gas release will travel downwind and be ignited. The solution of course,is to locate the flare perpendicular to the prevailing wind with adequate spacing from the facility. Thisavoids both the vapor dispersions from the flare and liquid releases onto the plant. Preferably the flareshould also be at a lower elevationthan the rest of the facility. This is in case it releases heavy vapors thathave not been properly combusted in the flare exhaust. Because of the larger spacing distances and riskfactors associated with flaresthey should be one of the first items sited for a new facility.Flare safety precautionsshould include:(1)(2)(3)Use of a automaticflamemonitoring device to warn of flameout conditions.Provision of a liquid knock out (KO) drum, which is equipped with high level alarmstowarn of an excessiveaccumulation of liquid.Prevention of the introductionvapors into the systemwhen it is not operational.The important safety aspects of flaresincludethe following:a. The flare is a readily availableignition source to vapors that can reach it or the radiant heat itproduces.b. Flame-out (flame lift-off or blow-outs), sometimes occurs at a flare, at which time flammablevapors will be discharged. If heavier than air and wind conditionspermit, they will travel alongthe ground to other areas until dissipated. Provision of a windshield around the flare tip willassist in prevent a flame-out from occurring.c. Flare may emit liquids under certain conditions, which even if a flare is lit it can endangerprocesses that are placed to close to it. Provisions to entrap and contain liquids in the flareheader, for worst case conditionsshouldbe provided at the flare tower.Liquid separators or knockout drums are normally used to remove any liquid from gas streamsflowingto flares designed to burn vapors. The drums shouldbe designed not only to collect liquidsrunning along the bottom of the pipe, but to disengage entrained liquid droplets. API RP 521,Section 5.4.2.1 recommends that particles 300 to 600 micrometersin diameter or larger should beremoved before flaring the gas. Additionallythe knockout drum should be sized to accommodatethe maximum amount of liquid that might be required to be withdrawn during depressurizationofthe entire or any portion of the facilityas the design of the system may dictate. If large quantitiesof propanes and butanes low temperatures may be reached in the flare header and drum due to autorefrigeration, which must be taken account of.
    • Depressurization, Blowdown and Venting 135Material Vent Flare Process SewerProcess VaporsFlammable& Non-Xx XSewer Vapors xtoxic&To: 1 1 I 1ProcessVa orsNonflammableandToxicIProcess Va orsNonflammableandNon-toxicLiquids I I I IProcess Blowdown X I xThermal Relief I I I X ] xProcess Drain I xTable 15General Guidelines for Material Disposal Methods
    • 136 Handbook of Fire and Explosion Protection1.2.3.4.5.6.7.8.BibliographyAmerican Petroleum Institute (API), RP-520. Sizing Selection and Installation of Pressure Relieving Svstems inRefineries.Part I Design (1993). and Part I1 Installation(19881, API, Washington,D.C.American Petroleum Institute (API), RP-521. Guide for Pressure-Relieviny and Depressuring Systems, ThirdEdition,API, Washington,D.C., 1990.AmericanPetroleum Institute (API), Standard 2000. VentingAtmosphericand Low Pressure Storage Tanks, ThirdEdition Reaffirmed,API, Washington, D.C.,1987.American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessels Code, ASME, New York, NY,1992.Gas ProcessorsAssociation(GPA), Engineerin9Data Book, GPA, Tulsa, OK, 1987.National Fire Protection Association (NFPA), NFPA 15. Water Spray for Fire Protection, NFPA, Quincy, MA,1993.National Fire Protection Association (NFPA), NFPA 30. Flammable and Combustible Liquids Code, NFPA,Quincy,MA, 1990.Vervalin,Fire Protection Manual for HvdrocarbonProcessing Plants, Gulf Publishing, Houston,TX, 1985.
    • Chapter 13Overpressure and Thermal ReliefThe term pressure relief refers to the automatic release of fluids or gases from a system or component to apredetermined level. Pressure relief systems are designed to prevent pressures in equipment or processesreaching levels where rupture or mechanical failure may occur by automatically releasing the materialcontained within.Almost all portions of a hydrocarbon process or system can conceivablybe exposed to conditionsthat wouldresult in internal pressures (either positive or negative) exceeding the normal operating pressures of thesystem. The most common causes are listed below:Exposure to Fire: If a vessel is exposed to a heat radiation from a fire, internal pressure mayrise primarily due to the generation of vapor from the internal liquid or from thermal expansionof the contained commodity.Excessive Process Heat Input: Most hydrocarbon and chemical processes require or containvarying amounts of heat exchange. Should a process upset occur, which inputs more heat thandesign conditions have allowed an overpressure may result due to expansion of liquid or vaporcontained within the system.Failure of Flow, Pressure or Temperature Control Valves: Control valves that regulateprocess conditions may fail causing a process upset to occur. Once the process upset occurspressure regulation will not be effectivelycontrolledand a pressure increasemay result.Unexpected Process Chemical Reactions: Unexpected chemical reactions which result in heator vapor evolutionsmay produce overpressuresthat have not been planned for.Failure of the Cooling Water Supply: A reduction in cooling water flow to condense vaporsin a vessel may lead to an increased pressure drop through the condensers resulting in anincreased pressure in the vessel.Vessel Isolation: If a vessel becomes isolated either filly or partially, from normal processconditions, internal pressure may build up if it has no outlet for venting.Failure of Heat Exchanger Tubes: If a heat exchanger shell rating is less than the pressurelevel of the circulating medium and an internal heat exchanging tube ruptures or leaks it willoverpressurethe vessel.Introduction of a Volatile Material: The introduction of a liquid into a vessel where the137
    • 138 Handbook of Fire and Explosion Protectiontemperature is above the boiling point of the commodity will result in the rapid vaporization ofthe material causing an increase in vapor output requirements and raising the pressure of thevessel. Materialswith low molecularweight are especiallyprone to this effect.Reflux System Failure: The quantity of reflux used in fractionation systems determines theamount of vapor generation and the consequent pressure differential through the condensersystem. If a reflux systemfails, lower pressuresthrough the condensersand the vessel may resultin higher pressure rise in the system as a whole.Internal Detonations or Explosions: An internal detonation or explosion may occur due toseveral scenarios. Air leakage into the system may cause a combustible mixture to form,undesired chemical reactions may occur, and extremely rapid vapor expansion may occur. Thesealmost instantaneousevents have to be carehlly protected against as many overpressure devicesdo not react quicklyenough to prevent the vessel from rupturing.Thermal Expansion: Contained liquidsmay be subject to heat input that causes them to expandresulting in a pressure increase. Typicalheat sources are direct sunlight and fire exposures.Non-CondensableGas Accumulation: If noncondensiblegases are not removed, overpressurecan result when a heat exchanger surface becomes blanketed or pressure drop through thecondensersis increasedby the presenceof the non-condensablegas.Outflow Rate Exceeds Inflow Rate: If material is being withdrawn from a tank or vessel fasterthan the incomingrate to compensatefor the removal suctiona vacuum will occur. If the vesselor tank is not strong enoughto withstand the negative pressure levelsit will collapse in on itselfThere are numerous types of pressure relieving devices available,.which include relief valves, safety valves,rupture or frangibledisc and blow out hatchesor panels.Pressure Relief Valves (PSV)Pressure relief valves are provided to cater to two main conditions of the process -normal conditions andemergency conditions. Normal conditionsrelate to the designed operation of the process which emergencyconditionscan be caused by either (1) external fire conditions, (2) failure of reflux or cooling, (3)Failure ofthe power supply, (4) failure of steam supply, (5) heat exchanger failure (6) introduction of incompatiblematerials, (7) thermal expansionwith outlets closed.Because these causes of overpressures are considered random and infrequent, the pressure relief capabilityhas to be automaticand constantlyavailable.Where relief valves are provided on liquid storage tanks or vessels, where there is a possibility of liquidrelease, i.e., liquid slug, carehl evaluation of the release disposal system (e.g., flare header) needs to beundertaken. In some cases, a liquid slug may block a header from releasing pressure and defeat the purposeof the pressure release system.
    • Overpressure and Thermal Relief 139Thermal ReliefThermalrelief is necessary in section of liquid piping when it is expected that the liquid will be isolated whenthe piping is also subject to temperature rises from solar radiation, warm ambient air, steam tracing ,fireexposuresor other external sources of heat input.High temperature input to a piping system will cause both the pipes and the fluid contained within it toexpand. Liquids have a high coefficient of expansion compared to metals (e.g., oil will expandapproximately 25 the times of a metal pipe). It therefore can be expected that high pressures can bedeveloped in piping systemsthat can be isolated and exposed to heat input. Thermal expansion of the pipe,expansion of pipe material from internal pressure or compressibilityof the liquid may be adequate for reliefof liquid thermal expansion before strength limits are reached for piping ,valves or blinds. Research testshave shown that pressure from thermal expansion of liquid hydrocarbon may increaseabout 553 kPa to 789kPa (70 to 100psi) for each OF temperature increase. The length of the piping has no effect on the pressurethat will result from thermal expansion of a liquid in an isolated section. However the volume of fluid thatmust be released to prevent excesspressure build up will be directly proportionalto the line length.Temperature increases in hydrocarbon process lines that are not in circulation but receive heat input caneasily achieve temperature increases that will result in pressure build up that needs to be evaluated forthermal expansion relief Normal solar radiation in some cases is enough to raise the pressure in linescontaining liquids by as much as 23,685 kPa to 78,950 kPa (3,000 to 10,000 psi). The main reason whymore ruptures have not occurred in lines without thermal pressure relief devices, is that most isolation valveshave some tolerances of leakage and pipe flange gaskets may also leak or fail. Further reliance on qualityisolation means such as double block valves, double seated gate valves, line blinds, etc., produces a greaterchance of line rupture from thermal expansions. Also reliance on flange leaks to relieve trapped pipingpressure is no longer an acceptableenvironmental alternative. The tighter verification of a leak-free facilityto prevent VOC emissionsto environment will require eliminationof pressure release points that may havebeen unknowing relied upon in the past. Any relief design must assume that the relief effluent is containedwithin system piping and properly contained and disposed.Overpressurefrom thermal expansion can occur in any pipe size or length with only a small rise temperature.It may be argued that all sections of piping which can be isolated theoretically need provisions for thermalrelief. As pressure is built up in a line, sensors may warn of pressure increases, valves can leak, or thepressure build up is not a feasible scenario. There are some services where the provision of a thermal reliefvalve is not justified, such as cold water lines inside buildings, buried or insulated lines, firewater lines,piping operated at elevated temperatures, etc. There are also operational procedures that can be institutedto alleviate thermal pressure concerns such as partially draining liquid lines before isolation, continuouspressure monitoring, etc. These methods are not the preferred method of protection sincethey are prone tohuman error. Reliefvalves are the preferred method of preventing pressure build up.Solar HeatFor geographical locationsbetween 60° N and 60° S latitudes solar heat input to pipelinesand the resultant thermal expansion is essentially the same. Orientation will have someeffect to the total amount of heat input, i.e., North-South provides more exposure thanEast-West, however the maximum rate of heat input is the same that occurs at the highestsun position, Le., at noon. This is a rather trivial aspect, as the cost of pipe length andinstallation costs generally overrule orientation concerns. Wind effects normally willdissipate some heat from pipelines. However for the case of thermal expansion concerns, it is commonpractice to consider no wind for purposes of heat input (or loss) to a piping system. Pipe color will as havean impact to heat absorption. Flat black is the highest heat absorber (l.O), while light colors are quite less(0.2.to 0.3). Reflectivitycharacteristicsalso assist in reflectingradiation.
    • 140 Handbook of Fire and Explosion ProtectionThermal Relief Fluid DisposalThere are three main methods to dispose of releasesfrom thermal relief valves. Discharge around ablock valve (isolation circumvention) is widely used in most situations, however where this is notpractical or economical disposal to a sewer or release to surface runoff can be specified in certaincases.Isolation CircumventionWhere the fluid is the same on each side of the isolation means, and no contamination will resultthis is the optimum choice for thermal relief release. Consideration of the possibility ofbackpressure onto the thermal relief valve, rendering the valve ineffective, should be evaluatedbefore an analysisis finished.Disposal to the Oily Water SewerA process oily water sewer system is a convenient location to direct oily wastes. The oily watersystem normally collects into a sump. If several lines connect into a common header, care shouldbe taken to prevent backflow into another outlet source. In such cases use of an air gap, i.e.,drainage in to a collection hnnel has be advantageous.Surface RunoffOnly when other alternatives are not available should a fluid release to the open environment beconsidered a viable disposal method. Additionallyit should only be consideredwhen the release issmall and does not create an additional hazard - either from fire safety or environmentally. Therelieved liquid should always be directed to a level surface away from other equipment, forcontainment by the facility surface runoff accommodationsto mitigate any environmental or firehazard. In no cases should discharge to the atmosphere be contemplated as it would create animmediate explosion or fire hazard and could also be considered an immediate environmentalpollutant.Pressure Relief Device LocationsPressure relief capabilityis generallyrequired at the following locations:Pressurized VesselsUnexpected process upsets may produce pressures above normal operating conditions.Storage TanksAll storage tanks subject to high flow rates in or out, requiring compensation for the displacedvapor.Equipment Susceptible to Thermal Expansioni. Vessel or tanks subject to ambient or fire hazard heat inputs.ii. The cold side of a heat exchanger if blocked off may be subject to excessive heat input from thehot side.iii. Circulation lines of heater where they can be blocked offDischarge of CompressorsVariable speed driverscan increase compressorsdischargepressures about desired amounts causing a
    • Overpressure and Thermal Relief 141processupset. With the provisions of constant speed drivers, such of electrical motors the possibilityof overspeed is highly remote.Pumps with Variable Speed DriversVariable speed drivers can increase pump discharge pressures about desired amounts causing aprocessupset. With the provisions of constant speed drivers, such of electrical motors the possibilityof overspeed is highly remote.Heat ExchangerHeat exchangersthat can be blocked in or where the shell of the exchanger may be subject to highpressure if an internaltube leak occurs.
    • 142 Handbook of Fire and Explosion ProtectionBibliography1.2.3.4.5.6.7.8.9.AmericanPetroleum Institute(API), RP-14J. Design and Hazards Analysis for OffshoreProduction Facilities, FirstEdition, API,Washngton, D.C., 1993.AmericanPetroleum Institute (AH), RP-520, Design and Installationof Pressure Relieving Systems. Part I Design(1993) and Part I1Installation(1988, API, Washington,D.C.American Petroleum Institute (API), RP-521. Guide for Pressure Relieving and Demessuring Systems, ThirdEdition,API, Washington,D.C., 1990.American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessels Code, ASME, New York, NY,1992.American Societyof MechanicalEngineers (ASME), B31.3ChemicalPlant and PetroleumRefmervPiting, ASME,New York, NY, 1993.American Society of Mechanical Engineers (ASME), B31.4 Liquid Transportation Svstems for Hvdrocarbons,Liquid PetroleumGas. AnhvdrousAmmoniaand Alcohols, ASME, New York, NY, 1993.American Society of Sanitary Engineering, Performance Requirements for Thermal Expansion Relief Valve,AmericanSocietyof SanitaryEngineering,Bay Village, OH, 1990.IndustrialRisk Insurers(IN),IM.7.0.5.0,OverpressureProtection, IN,Hartford,CT.National Fire Protection Association (NFPA), NFPA 30. Flammable and Combustible Liauids Code, NFPA,Quincy,MA, 1993.
    • Chapter 14Control of Ignition SourcesIn petroleum operations any leak or spillage may give risk to an explosive atmosphere. To protect bothpersonnel and the plant, precautions must be taken to ensure that the atmosphere cannot be ignited. It isgenerallyrecognized that there are three main categories of ignition sources in a hydrocarbon facility - openflames, hot surfaces and sparks. The overall objective protection is to remove or provide a barrier in-between these ignition sources from materials that can readily ignite if contact is made. The ability of thesesourcesto ignitea material depend on their availableenergy and configuration.Open Flames, Hot Work and SmokingOpen flames in a hydrocarbon facility usually are availablefrom welding or hot work operations, smokingand the facility flare. NFPA 51B provides guidance in the conduction of cutting and welding operations.Additionally all petroleum facilitieshave limitations on areas allowed for smoking. Both of these sources arenormally controlled through operational measures supplemented by physical separation. Similarlyflares aresitedto offer the least possibilityto ignite a process vapor release.Electrical ArrangementsFacility electrical systems and components provide a convenient source of ignition within a hydrocarbon orordinary occupancieswhenever the design, installation or maintenanceis substandard. Electrical systems orcomponentsmay short, overheat, operate incorrectly, etc. These failureswill present themselves as availableignition sources for hydrocarbonvapor releases. All electricalinstallation should be accordingto recognizedelectricalindustry standards such as API RP 540 and the NEC (NFPA 70).Electrical Area ClassificationThe overall intent of electrical area classificationis to provide for safety of personnel and equipment. This isachieved by the elimination of electrical ignition sources near combustible gases or vapors that couldexplodeor burn. The specificreasons for classifyingfacilitiesinto electricalhazardous areas typically are:1. To ensurethat sources of ignition are safety separated from sources of combustibleliquids andgases.2. To ensure electrical apparatus selected for use near combustibleliquidsand gases is of adequatedesign and constructionto prevent ignitions.3. To assist in the location of air inlets for ventilation systemsand combustion equipment143
    • 144 Handbook of Fire and Explosion Protection4. To definethe extent of flammablevapor travel from vents, drains and other open hydrocarbonsources.5. To assist in the location of combustiblegas detectors and fire detection equipment6. To permit the location of life saving appliances,flammableliquid stores, radioactiveandemergencycontrol points in safe areas where practical.7. To achieve an economicalelectrical installationwhich will provide an acceptablelevel of safety atthe lowest possible cost.It might be argued that if the ignition sources where not all removed, but still present in hydrocarbonprocessing areas, hydrocarbon leakages would be immediately ignited preventing the formation of largevapor clouds. If these leaks are involved in combustion, the he1 is consumed, thus avoiding major firedamage and the value for explosionproofequipmentis unnecessary.It should be remembered that leakages may be large or small in nature and can be orientated in infinitedirections, so considerable fuel releases may occur, even where ignition sources are readily available.Also many incidents where large leakages occurred, have not ignited, since ignition sources were removedfrom the area. Therefore prevention measures should be employed, to avoid the ignition of a hydrocarbonliquid or vapors whenever possible.To enable electrical equipment to be used safely in potential hazardous atmospheres, various, althoughessentially similar, hazardous area definition techniques have been developed over the years by severalorganizations. Various international and national standards or codes of practice govern each of thesetechniques. These methods define how the equipment is to be designed and applied. Certimng bodiesensure a specified design meets the requirements of the standard or code. The basic premise of thesetechniques is to specify a "hazardousarea" that a flammable gas or vapor may be likely to be encounteredbased on gas or fluid concentrationand the configurationof the equipment or facility. The purpose of thesehazardous area classificationsis to limit the probability of electrical ignition of flammable vapors and gases.This is achieved by limiting the types of electrical equipment that may be installed in the areas whereflammable vapors or gases may exist for any length of time. Hazardous area locations for the U.S.petroleum industry are typically prescribed by Article 500 of the National Electrical Code (NFPA 70),American Petroleum Institute Recommended Practice (RE) 500 and NFPA 30 Flammable and CombustibleLiquids Code. Other international codes and specification exist which may alter the requirements of thesecodes,.some of which are more stringent. All countries in western Europe work to CENELEC standards.European Community (EC) member countries issues Certificates of Conformity to these standards andaccept products and systems certifiedby other members. Other countrieswork to their own standardsbasedon IEC-79 (e.g., Australia, Brazil, Japan, Russia), or accept products and systems certified to European orNorth American standards. Figure 7 provides a graphic example of the difference various codes mayproduce.
    • Control of Ignition Sources 1450 10 MScale -NFPA 30 (US1liplBCI (West Germany)[CIIRoSPA: LPG (UK)Health and SafetyExecutive CSS:1CPP: LPG (France)Oet Norske Veritas (Norway)55 C2108 20 (Sweden)Hazardous Area Classification Codes Applied to the Same Pump(Pump handling LPG)Figure 7
    • 146 Handbook of Fire and Explosion ProtectionSome specific internationally recognized electrical hazardous location equipment testing agencies are listedin Table 16below.Table 16Recognized International Electrical Approval TestingAgenciesSimple devices that do not generate or store significant electrical energy can be used without certification.They include thermocouples, resistive sensors, LEDs and some specific switches. In some cases theinterconnectingcablesmay store energy in their capacitance or inductanceand release it suddenly if there isa fault. The certificate for any interface device defines the maximum permitted "cable parameters".Interface devices are usually designedto tolerate long cables and in practice, althoughthe user should check,there is very seldomany problem.Electrical Area ClassificationIn USA the electrical area classificationfor petroleum facilitiesis usually defined by the requirement of NEC("A 70) ,API 500 and NFPA 30 that are similarin content.Class I: Gases and VaporsDivision 1: Gases and vapors can normally existDivision 2: Gases and liquidsnormally confinedClass I, I1 and 111are also used by NFPA to define the range of certain materials in categories based mainlyon flash points. Class TI and 111 materials generally do not provide sufficient vapors to require specificationof an electricallyclassified area, so areas are only defined by Class I flammablematerials.Flammablematerials are also differentiated accordingto the spark energy needed to ignitethem.GroupA: Acetylene
    • Control of Ignition Sources 147Group B:proplyene oxide, and acroleinHydrogen and fuel gases containing >30% hydrogen, butadiene, ethylene oxide,Group C: Ethyl ether, ethylene or gases of equivalent hazardGroup D: Acetone, ammonia, benzene, butane, cyclopropane, ethanol, gasoline, hexane,methanol, methane, natural gas, naphtha, propane, or gases or vapors equivalenthazardSurface Temperature LimitsHazardous area apparatus is classified according to the maximum surface temperature produced under faultconditions at an ambient temperature of 40 OC (104 OF) or as otherwise specified. Some desert locationsmay produce ambient temperatures higher than 40 OC (104 OF) and suitable adjustments must be made inthese circumstances.Rating Degrees C (OF)T1T2T2AT2BT2CT2DT3T3AT3BT3CT4T4AT5T6450 (842OF)300 (572OF)280 (536OF)260 (500OF)230 (446OF)215 (419OF)200 (392OF)180 (356OF)165 (329OF)160 (320OF)135 (275OF)120 (248OF)100 (212OF)85 (185OF)Class I1 and Class I11 areas are for Dust and Fibers respectively, and are typically not extensivelyused in thehydrocarbon industries.Classified Locations and Release SourcesSometypically defined classified locationsare listed below, (when hydrocarbon materials are present):Relief Valve Outlets (if discharge is to atmosphere)Packing glands or seals on pumps and compressorsPipe flanges,fittingsand valve stemsThreaded fittingsthat are not seal-weldedSamplestations with an air breakManways and piping connectionsto vesselsPiping to equipment connectionsVent and drain openingsassociatedwith hydrocarbon fluids or gasesAreas associated with hydrocarbon pumps bordered by three walls (where the walls are 1 meter (3fi) high or >)Drainageditches, gulleys,trenches and associatedremote impoundingbasinsPits, sumps, open trenches and other below grade locationsin a hazardous classified areaLaboratory hoods, ducting and storage rooms where hydrocarbon materials are handled
    • 148 Handbook of Fire and Explosion ProtectionOily water gravity and pressure sewer systemsShip, rail or truck loading facilitiesStorage Tanks for flammableliquidsPipeways at grade bordered by elevated road or dike walls 1 meter (3 ft) high or > on twosides.Pipelinescrapper traps stationsDrilling, wirelineand workover rigs (includingthe mud pits)Undergroundtanks or closed sumps (for collectionof volatile liquids)Containerand portable tank storageContainerand portable tank filling stationsGasolinedispensingand service stationsTank vehicles and tank cars for volatile liquidsEmergency or UninterruptiblePower SupplyFacilities- Battery room exhaust systems (if unsealedbatteries are present)AnalyzerHousesSewageTreatment (Air floatationunits and Biological Oxidationunits)Cooling Towers (handlingprocess water)Protection MeasuresExplosionproof Rated EquipmentElectrical devices that are in areas that may produce an ignition source to hydrocarbon vapors arespecified to prevent such occurrences and can be rated as "explosionproof. Explosionproofratingmeans that a device is rated to withstand an explosion of a specific gas or vapor that may occurwithin it and prevent the ignition of ignition of a specificgas or vapor surroundingit. It also limitsthe operating external temperature that a surrounding atmosphere will not be ignited. Variousenclosures, sealing devices and mechanisms are employed to achieve the desired rating for aparticular piece of equipment.Intrinsically Safe Rated EquipmentIntrinsic safety is based on the principal of restricting the electrical energy available in hazardousarea circuits such that any sparks or hot surfacesthat may occur as a result of electrical faults aretoo weak to cause an ignition. The usehl power is about 1 watt, which is sufficient for mostcurrent instrumentation. It also provides a personnel safety factor since the voltages are low and itcan allow field equipment to be maintained and calibrated "live" without the need for a gas freeenvironment verification. Electrical components or equipment can be manufacturer as intrinsicallysafe and there readily usable in areas where combustiblegases or vapors may be present.Hermetically Sealed Electrical EquipmentSpecificallydesignated electricalequipment can be manufactured so that its internal componentsarecompletely sealed. This eliminates the possibility electrical arcing components or circuits cancontact combustiblevapors or gases.PurgingElectrical housings may be purged with an inert gas or air that flows at a sufficient rate to dilutetheatmosphere immediately around an energized circuit so that atmospheric released gases will be
    • Control of Ignition Sources 149pushed away and will not be ignited.Facilitiesthat are required to be provided in hazardous locations but which provision of electricallyclassified equipment is economicallyprohibitive or technically unavailable a pressurization locationis usually provided. The pressurization air is provided from a safe source and fitted with gasdetection devices for alarm and shutdown. Entranceways are fitted with air locks that aretechnically still classified locations since they will let in hazardous vapors when opened. The airlocks should be fitted with ventilation to disperse any vapors that accumulate.For enclosed areas, they can be considered adequatelyventilated if they meet one of the following(1) The ventilation rate provided is at least four times the ventilation rate required to dilute theanticipated hgitive emissionsto below 25 percent LEL as determined by detailed calculationsfor the enclosed area.(2) The enclosed area is provided with six air changesper hour by artificial(mechanical)means.(3) If natural ventilation is used, 12 air changes per hour are obtained throughout the enclosedarea.(4) The area is not defined as "enclosed per the definitionof API Rp 500, Section4.6.2.2.4.Relocationof DevicesMany times it may easier to relocate electrical equipment outside an electricallyclassified area ratherthan occur addition expense to obtain an explosionproof rating. For example most internalcombustion engines are not rated for hazardous atmospheres.Surface TemperaturesSurface temperature of exposed equipment may pose the most readily available ignition source ina hydrocarbon facility. Hot surfaces should be insulated, cooled or relocated, when they pose athreat of ignition, to hydrocarbon release areas. Required equipment should be rated to operatebelow the autoignitiion temperature of the gas or vapor that may be encountered.StaticStatic electricity can be formed in various locations in the process, storage and transfer operationsof a hydrocarbon facility. Experimental tests have generally demonstrated that saturatedhydrocarbon vapors and gases (under normal conditions),will ignite when approximately 0.25milli-joule of spark discharge energy is released. Some gases have even lower minimum energies asindicated below.Methane 0.29Propane 0.25Cyclopropane 0.18Ethylene 0.08Acetylene 0.017Hydrogen 0.017The essential requirement for protection against the effects of static electricity can be segregated intothree areas:
    • 150 Handbook of Fire and Explosion Protection(1) Identification of potential static electricitybuild up areas.(2) Measures to reducethe rate of static electricitygeneration.(3) Provisionsto dissipate accumulated static electricity charges.The major generators of static electricity at hydrocarbonfacilitiesare:Sprayed liquidsMoving machinery8 PersonnelFlowing liquids or gases containingimpuritiesor paticulatesLiquid mixing or blending operationsIf a gas containsliquid, water vapor or solid particles such as rust particles or dirt, a static charge canbe generated.Generally static electricity can be overcome or controlled by several basic approaches - bonding,grounding, and controlledgeneration.Bonding tries to achieve a common electrical potential on all equipment so that a charge does nothave the opportunityto accumulate.Most if not all hydrocarbon facilitiesare provided with a groundinggrid. The primary purpose of thegroundinggrid is to limit the effects of corrosion induced by charges but it also serves as a means todissipate electrical chargesthat could be a source of ignition. Groundingis the process of electricallyconnecting one or more conductingobjects to a ground potential.LightningLightning is generally considered a form of static electricity that is beingdischarged from particles in the atmosphere. Many instancesof lightninginducedhydrocarbon fires have been recorded, especially at atmospheric storage tanks.NFPA requirements state that if equipment or process vessels, columns of tanksare suitably constructed of substantial steel construction adequately grounded,and do not give off flammable vapors, no other mechanism of lighting protectionis required. This is also true of flares, vent stacks and metal chimneys by natureof their construction and grounding facilities.Since most storage tanks release flammable vapors at seals and vents, they are susceptible tolightning induced fires. Common European practice is to provide lightning rods on the highestvessel at a facility to provide a cone of protection for the facility. NFPA 780 provides additionalguidance for the provisions of lightning protection measures.Direct lightning strikes can ignite flammable contents of cone roof tanks unless the roof is providedwith bonding for the structural members. Floating roof tanks with seal hangers in the vapor spacemay be ignited indirectly when changes on the roof are released by a nearby lightning stroke.Floating roof tanks are commonlyprotected against lightning ignition by bonding the floating roof tothe seal shoes at not less than 3 meter (10 fi.) intervals, use of insulating section in the hanginglinkages, covering sharp points on hangers with insulating material and installation bonds across eachpinned hangerjoint.Buildings that are more than 15.2meters (50 ft.) high, contain combustible liquids in large amountsor store explosive materials should be provided with lightning protection measures according to therequirementsof NFPA 780.
    • Control of Ignition Sources 151Ships with steel hulls or masts have suffered little or no damage from lightning and no specialprotection measures are considered necessary. During the loading or unloading of vessels it iscommon practice to suspend operations and close all openings into tanks during the appearance oflightningstorms.Internal Combustion EnginesInternal combustion engines contain several features that pose ignition sources for hydrocarbonvapors. Most obvious is they exhaust hot combustion gases that can ignite vapors, secondary theyhave hot surfaces - primarily the exhaust manifold and piping, and finally and most overlooked,instrumentationand ignition devicesmay not be rated for use in an area where combustiblegases maybe present.SparkArrestorsSpark arrestors are provided at those locations where sparks may constitute a hazard to the surroundingenvironment. The exhausts of internal combustion engines, incinerator stacks, and chimneys are normalexamples. It usually consists of screening material to prevent the passage of sparks or flying brands to theoutside atmosphere.Hand ToolsAFI has investigatethe necessity of requiring non-sparkinghand tools and the possible ignition risk. Theyconcluded that non-sparking hand tools would not signifidantly decrease the ignition potential from handtools. Hand tool operations in most instances will not produce enough spark energy for ignition plussimultaneousgas release and sufficient spark generation from a hand tool is consideredextremely low.
    • 152 Handbook of Fire and Explosion ProtectionBibliography1.2.3.4.5.6.7.8.9.10.11.12.13.14.15.16.17.18.19.American PetroleumInstitute (API), RP 14F. Design and Installationof Electrical Svstems for Offshore ProductionPlatforms,ThirdEdition, Washington,D.C., 1991.American Petroleum Institute (API), RP 500. Classification of Locations at Petroleum Facilities, First Edition,Washington,D.C., 1991.American Petroleum Institute (API), RP 540. Electrical Installationsin Petroleum Processin? Plants, Third Edition,API, Washington,D.C., 1991.AmericanPetroleum Institute(API), RP 2003. ProtectionAgainst Ignitions Arisingout of Stati- Lightin9 and StrayCurrents,Fifth Edition, API, Washington,D.C., 1991.American Petroleum Institute (API), Publication 2214. Spark Imition of Hand Tools, Third Edition, API,Washington, D.C., 1989.AmericanPetroleum Institute(API), Publication 2216. IgnitionRisk of HydrocarbonVapors by Hot Surfacesin theOpen Air, SecondEdition,API, Washington,D.C., 1991.American Society for Testing of Materials (ASTM), D3284, Standard Test Method for Combustible Gases in theGas Spaceof ElectricalApparatus in the Field, ASTM, Philadelphia, PA, 1990.Bishop, D. N., Electrical Systems for Oil and Gas Production Facilities, Second Edition, Instrument Society ofAmerica, Research TrianglePark, NC, 1992.British Standards Institute (BSI), BS 5345 Parts 1. 2. & 4, Code of Practice for the Selection. Installation andMaintenanceof ElectricalAuuaratus for Use in PotentiallvExulosiveAtmosuheres, BSI, London, UK, 1983.British Standards Institute (BSI), BS 6651-1992 - Code of Practice for Protection of Structures Against Lirrhting,BSI, London, UK, 1992.InternationalElectrotechcal CommissionIEC 79-4. Electrical Apuaratus for ExplosiveGas Atmospheres, SecondEdition, 1975.Institute of Electrical and Electronic Engineers, Inc. (IEEE), IEEE RP 484. Design and Installation of large LeadStorageBatteriesfor GeneratingStationsand Substations,IEEE, New York, NY, 1987.Instituteof Petroleum (IP), Area ClassificationCode for Petroleum Installations,Model Code of Safe Practice, Part15,IP, London, U.K., 1990.Industrial Risk Insurers(IRI), IM.5.2, Lighting and Surge Protection,Hartford,CT.Instrument Societyof America (ISA), RecommendedPractice RP 12.6,ISA, Research, Triangle Park, NC, 1987.Korver, W. 0.E., Classif Explosion-Prone Areas for the Petroleum. Chemical and Related Industries, NoyesPublications, Park Ridge, NJ, 1995.Magison, E.C., Electrical Instruments in Hazardous Locations, Third Edition, ISA, Research, Triangle Park, NC,1978.National Fire Protection Association (NFPA), NFPA 30, Flammable and Combustible Liquids Code, NFPA,Quincy,MA, 1993.National Fire Protection Association(NFPA),NFPA 70, National ElectricalCode,NFPA. Quincy,MA, 1993.20. National Fire ProtectionAssociation(NFPA),NFPA 77. StaticElectricity,NFPA, Quincy,MA, 1988
    • Control of Ignition Sources 15321. NationalFire Protection Association(NFPA),NFPA 780. LightingProtectionCode,NFPA, Quincy, MA, 1992.22. National Fire Protection Association (NFPA), NFPA 496, Standard for Purged and Pressurized Enclosures forEauipment,NFPA Quincy,MA, 1993.23. National Fire Protection Association (NFPA), NFPA 497A. Classification of Class I Hazardous Locations forElectricalInstallationin ChemicalProcess Areas, NFPA, Quincy, MA ,1992.24. National Fire Protection Association (NFPA), NFPA 497B. Classification of Class I1 Hazardous Locations forElectricalInstallationsin ChemicalProcess Areas, NFPA, Quincy, MA, 1991.25. National Fire Protection Association (NFPA), NFPA 497M. Electrical Equipment in Hazardous Locations, Gases,Vapors. Dusts, NFPA, Quincy,MA, 1991.26. Magision, E. C. & Calder, W., Electrical Safety in Hazardous Locations, Instrument Society of America (ISA),Durham,NC, 1993.27. Society of Automotive Engineers, (SAE), RecommendedPractice J 342, S D X ~Arrester Test Procedure for LargeSize Engines, 1991.28. Societyof Automotive Engineers, (SAE), RecommendedPractice J 350. SparkArrester Test Procedure for MediumSizeEngines, 1991.29. Underwriters Laboratories Inc. (UL), UL 674, Safety Electric Motors and Generators for Use in Division 1Hazardous(Classified)Locations, Third Edition, UL, Northbrook,IL, 1994.30. Underwriters LaboratoriesInc. (UL),UL 886. Safety Outlet Boxes and Fittings for Use in Hazardous (Classified)Locations, Tenth Edition, UL, Northbrook,IL, 1994.31. Underwriters Laboratories Inc. (UL), UL 894. Safety Switches for Use in Hazardous (Classified) Locations,SeventhEdition, UL, Northbrook,IL, 1993.32. Underwriters Laboratories Inc. (UL), UL 913, Intrinsicallv Safe Apparatus and Associated Apparatus for Use inClass I. I1 and 111. Division 1. Hazardous(Classified)Locations,Fourth Edition, UL, Northbrook,IL, 1988.
    • Chapter 15Elimination of Process ReleasesAtmospheric vapor releases or liquid spills within a petroleum or related facilities commonly occur everyday. They are a major source of the origin of catastrophic incidents. In order to provide an inherently saferfacility the common release of process vapors to atmosphere or liquids to grade within the facility should beprevented or eliminated wherever practical. Not only does this improve the safety of a facility it alsodecreases the amount of fugitive emissions or liquids that occur therefore decreasing any potential harm tothe environment. Containment of waste gases and liquids, human surveillance, increased testing, inspectionand maintenance, gas detection and adequate vapor dispersion features are all measures to lesson theprobabilityof an incident occurring.The other common source of process releases is leakage. Contained hydrocarbonswill not bum unless anoxidizer is available, but once a leak is present adequate oxygen supplies are immediately availablefrom theair. To prevent explosions and fires the integrity of the plant must always be kept at its highest andintroductionof air suppliesto closed systems must be eliminated.Typically the following mechanisms can release a combustible vapor into the atmosphere during normaloperations1.2.3.4.5.6.7.8.Open tanks and containers.Vents of storage tanks.Safetyvalves, pressure reliefvalves, or vents which releaseto the flare or an atmosphericvent.Glands of pumps and compressors.Process system, vessel or tank drains.Oily water sewer (OWS), vents and drain funnels.Pipelinepig traps and filters.Samplepoints.Process facilities should be designed so that, where practical, these exposed combustible vapors will notexist. Methods of achievingthis objective are defined below.Methods of preventing air intrusionare:Purging,Inerting,Flooding154
    • Elimination of Process Releases 155Inventory ReductionIn the event of a process or storage facility failure, immediate large quantities of hazardousmaterialsmay be released before activationof protective detection and mitigationmeasures. This isespecially a concern where the continued fluid can rapidly vaporize or the material already exists asa gas. In the petroleum industry these commodities generally include liquefied petroleum gasO;PG), natural gas liquids (NGL), condensate, liquids with a high vapor pressure at operatingconditionsand all combustiblegases. Thus limits should be placed on the total isolatable inventoryfor such materials in the process and storage systems. Based on historical data that suggest vaporcloud explosionsgenerally have not occurred for amounts less than 22,000 kgs (10,000 lbs), a limitin the order of this magnitude should be considered for process areas where congestionis higher. Ifhighly volatile and hazardous materials in highly congested areas are involved, lower limits shouldbe considered, (e.g.,4,400 kgs (2,000lbs.)).Vents and Relief ValvesAll waste hydrocarbon gases (vents, relief valves, and blowdowns) should be routed to a flare orreturned to the process through a closed header system. Release of vapors to atmosphere mayproduce a vapor cloud, and even through the release may be remote from the facilityit may drift orthe effects of ignition(i.e., blast overpressure)of the cloud will be felt at the facility.Atmospheric storage tanks are normally fitted with pressure-vacuumrelief valves to reduce vaporemission and evaporationlossesto atmosphere.Sample PointsSampling techniques should use a closed system. ,Open vessel collection means should be avoidedas spillage may occur due to the container mishandling or inappropriate operation of the samplevalve. Open sampling may also lead to inaccurate results since volatile portions of the sample maybe dispersed during the sampling process. Automatic sampling methods are commonly availablewhich eliminatethe need of manual hand samplingprocesses.If open sampling is provided, the sampling point should be located where adequate dispersion ofreleased vapors will occur. The samplingpoint shouldbe located so it is easily accessible so humanerror factors are reduced.Drainage SystemsProcess equipment liquid drains should be provided with a sealed drainage system where it ispractical and backpressurefrom the system or containmenation is not a concern. Open drain portsshould be avoided and separate sewage and oil water drains provided. Surface drainage should beprovided to remove liquid spills immediate and effectively from the process area. Vents ondrainage systems should be elevated so as to freely disperse hydrocarbon gases above congestedareas that could be released from the system.Storage FacilitiesWith proper safety precautions and operating procedures the occurrence of explosions in the vaporspace of fixed roof storage tanks are a very rare event. A frequency estimate of an explosion oncein every 1,000years, per tank, has been stated. Explosivemixtures may exist in the vapor space ofa tank unless precautions are taken. Any vapor will seek an ignition source, so prevention ofignition cannot be guaranteed. This is especially true with liquids that have low conductivity that
    • 156 Handbook of Fire and Explosion Protectionwill allow static charges to build up on the liquid. Precautions to safeguard against internal tankexplosions, include insuring air does not enter the vapor space for tanks containing combustibleliquids above their flash points. This is commonly achieved with production gas or with an inertgas such as nitrogen.. A safer an in the long term more economical approach is to place the liquidin a floatingroof tank.Floating roof storage tanks are inherently safer than fixed roof tanks as they essentially eliminatethe creation of a vapor space in the tank above the hydrocarbonliquid. Floating roof tanks float onthe stored product and rise and fall as the inventory changes. They limit the area of vapor releaseto the circumferencialseal. Low flash point liquids should always be stored in tanks which will notallow the creation of vapors in sizable quantities. Floating roof tanks are twice as expensive toconstruct as fixed roof tanks so there is a trade off of risk against cost. However by reducingemissions the increased cost can be justified on the basis of reduced product loss throughevaporation(a product savings) and impact to the environment.Floating roof tanks, both internal and open top are constructed with a circumferencialseal to allowthe roof to rise and fall. A single seal will allow some vapors to escape. However, recentenvironmentalpractice is to provide a secondary seal over the first seal, which provides additionalmitigationagainst the release of most of the vapors.Most fires on floating roof tanks are small rim fires caused by vapors leaking through the seals.The source of ignition is normally lightning strikes. With proper seal maintenance and inspection,coupled with adequate shunt straps across the seal at every meter or so will reduce the probabilityof a tank fire.Atmospheric fixed roof tanks built according to API requirements will have a weak seam at thejunction of the roof with tank side. If there is internal overpressure, such as an explosion, the seamwill part or the roof blows off, leaving the shell in place to retain its contents. The resulting firewill therefore only initiallyinvolve the exposure surfaceof the liquids still in the tank.Pump SealsRotating pump shafts require a means to seal the circulating fluid from escaping but still allow thepump shaft to rotate. As the pump seal wears or more volatile products are handled the moredifficult it is to prevent leakage through the seal. Historicallythe industryhas much evidence of theproblems with pumps seals and fire hazards areas are required on almost all pumps handlinghydrocarbon products. Double seals with alarm indications are provided to mitigate theconsequences of a pump seal failure instead of single-mechanical (rope) seals.Vibration Stress Failure of PipingIn a review of petroleum industry release incidents, one of the contributing factors is themetallurgicalfailure of smalI diameter vent drain, sample piping at rotating equipment (i.e., pumps,compressors,gearboxes, etc.). Rotating equipment induces stress on the piping connected due tothe rotation force it generates. Although the equipment itself is restrained, it still induces stress inthe connecting pipework that is normally not observed. Since the small diameter piping is not assubstantial as the main pipework, usually less attention is made to its restraint. However becauseof this it is the most vulnerable location for a failure at rotating equipment. The failure point isusually at the connection point of the small diameter line to the main line, where it has the stresslocation from the "loose end" of the small line.
    • Elimination of Process Releases 157For existing equipment a vibration measure survey should be undertaken or examination of pipingsuspected of being under stress. Critical examination of connection points should be made wherethe induced piping vibration stress is the greatest. For new designs a stress analysis can beprepared on the pipework by specializedconsultants.Rotating EquipmentTurbines, compressors,gearboxes,blowers and alternators may suffer damage from bearing failure,inadequate lubrication, blade or diffiser failure, vibration or coupling failures. These failures canlead to the release of lubricants, combustibleliquids or gases that can ignite causing an explosion orfire. Additionalmonitoring and equipment shutdown capabilitiesshould be provided in these cases.Consultation with the manufacturer and the selected application results in the prudentinstrumentation and shutdown logic that should be adopted. In cases where large quantities ofvolatile hydrocarbonsmay be released, the provision of gas detection should be considered.
    • 158 Handbook of Fire and Explosion ProtectionBibliography1.2.3.4.5.6.American Petroleum Institute (API), Manual of Petroleum Measurement Standards, Chapter 8.2, AutomaticSamplingof Petroleumand PetroleumProducts, First Edition,API Washington,D.C., 1987.American Petroleum Institute (API), Standard 620, Desim and Construction of Large. Welded Low PressureStorageTanks, EighthEdition, API Washington,D.C., 1990.American Petroleum Institute (API), Standard 650. Welded Steel Tanks for Oil Storage, Ninth Edition, APIWashington,D.C., 1993.American Petroleum Institute (API), Bulletin 2521, Use of Pressure-Vacuum Vent Valves for AtmosDheric Loss,API Washington,D.C., 1993.National Fire Protection Association(NFPA),NFPA 15,Fixed Water Spray Systems,NFPA, Quincy,MA., 1990.National Fire Protection Association (NFPA), NFPA 30, Flammable and Combustible Liquids Code, NFPA,Quincy,MA., 1993.
    • Chapter 16Fire and Explosion Resistant SystemsThe petroleum and related industries deal with tremendous bulk quantities of flammable and combustiblematerials daily. These materials are handled at extremely high pressures and temperatures where explosive,corrosive and toxic properties may also be present. It is therefore imperative not to become complacentabout their destructive natures and the required protective arrangementsthat must be instituted wheneverthey are handled.Fire and explosion resistant materials and barriers for critical equipment or personnel protection shouldalways be considered whenever petroleum operations are involved. They prolong or preserve the integrityof a facility critical features to ensure a safe and orderly evacuation and protection of the plant isaccomplished.Ideallymost oil or gas incidentswill be controlledby the process shut down systems(ESD, depressurization,drainage, etc.) and hopefit1the fire protection systems (fireproofing, water deluge, etc.), will not be required.However these primary fire defense systems may not be able to control fire incidents if previous explosionshave previously occurred. Before any considerationof fire suppressionefforts, explosion effects must firstbe analyzed to determine the extent of protection necessary. Most major fire incidents associated withhydrocarbon process incidents are preceded by explosion incident.ExplosionsExplosions are the most destructive occurrencethat can transpire at a hydrocarbon facility. Explosionsmayhappen too quickly for conventional fire protection systems to be effective. Once an explosion occursdamage may result from several events:1. Overpressure - the pressure developed between the expanding gas and its surroundingatmosphere.2. Pulse - the differentialpressure across a plant as a pressure wave passes might cause collapse ormovement.3. Missiles- items thrown by the blast of expanding gases might cause damageor escalation.Explosion overpressurelevels are generallyconsidered the most critical measurement at this time. Estimatesare normally prepared on the amount of overpressure that can be generated at various damaging levels.159
    • 160 Handbook of Fire and Explosion ProtectionThese levels are commonly referred to as overpressure circles. Overpressure circles are normally drawnfrom the point of ignitionthat is typically taken for sake of expediencyand highest probability as the point ofleakage or release unless other likely ignition points are identified.Definition of Explosion PotentialsThe first step in protection against explosions is to identifirif they have the possibility of occurring at thefacility and to acknowledge that fact. This may be for both internal and open air explosions. Once it isconfirmed an estimateof their probabilityand severity shouldbe defined by a risk analysis. If the risk level isindicated as unacceptable additional measures for prevention and mitigation should be implemented.Typical locationswhere explosion overpressurepotentials should be considered or evaluated are:Gases stored as liquid due to the application of refrigeration or pressure.Flammable or combustibleliquids existing above atmospheric boiling point and maintained as aliquid because of the application of pressure.Gases contained under a pressure of 3,448 kPa (500 psi) or more.Any combinationof vessels and piping that has the potential to release a total volume containingmore than 907 kgs (2,000 lbs.) of hydrocarbonvapors.Onshoreareas that are considered to have confinement (hlly or partially) and may releasecommoditiesmeeting the above criteria.Locationswhich may have a manned control room less than 46 meters (150 fit.)from a processarea meetingthe above criteria.Gas compressorbuildingsthat may be hlly or partially enclosed.Enclosed buildingshandlingfluidsthat have the potential to accumulateflammablegases (e.g.,produced water treating facilities).Offshore structures that handle or process hydrocarbon materials.The objective in calculating explosion overpressure levels is to determine if a facility has the potential toexperience the hazardous effects of an explosion and, if so, to mitigate the results of these explosions. Thecalculations can also serve to demonstrate where mitigating measures are not needed due to the lack of apotential to produce damaging overpressures either because low explosion effects or distance from theexplosionfor the facility under evaluation.As an aid in determining the severity of vapor cloud explosions, overpressure radius circles are normallyplotted on a plot plan from the source of leakage or ignition. These overpressure circles can be determinedthe levels at which destructive damage may occur to the facility from the worst case credible event (WCCE).Facilitiesthat are deemed critical or highly manned should be relocated out of the overpressure circles fromwhich the facility cannot withstand the explosive blast or provided with other explosion protective measures.Other systems within these overpressure zones should be evaluated for the benefits of providing explosiveprotective design arrangements. Figure 8 shows an example of a typical plot of overpressure circles for ahydrocarbon processingfacility.
    • FireandExplosionResistantSystems161
    • 162 Handbook of Fire and Explosion ProtectionExplosion ProtectiveDesign ArrangementsExplosion suppression systems are being offered on the commercial market for small enclosures, based onpowder and Halon extinguishing agents. These systems have some disadvantagesthat must be consideredbefore being applied at any facility. A leak may continuefor some time and the ignition source is usuallynotlikelyto dissipate. Re-ignition of the gas cloud is a high risk with "one shot" systems. For large enclosures,a tremendous volume of the suppressionagent is necessary and therefore there is point of diminishingreturnfor the protection system (Le.,cost versusbenefit).Research on water explosion inhibiting systems is providing an avenue of future protection possibilitiesagainst vapor cloud explosions. British Gas experimentation on the mitigation of explosions by watersprays, shows that flame speeds of an explosion may be reduced by this method. The British Gas researchindicates that small droplet spray systems can act to reduce the rate of flame speed acceleration andtherefore the consequential damage that could be produced. Normal water deluge systems appear toproduce too large a droplet size to be effective in explosionflame speed retardation and may increasethe airturbulencein the areas.The followingare typical design practicesthat are employedto prevent vapor cloud explosions.a. All hydrocarbon areas should be provided with maximum ventilation capability. Specificexaminationsshouldbe undertaken at all areas where the hazardous area classificationis definedas Class 1 Division 1 or Class 1 Division 2. These are areas where hydrocarbon vapors areexpected to be present, so verification that adequate ventilation is provided to aid in thedispersion of combustiblevapors is a necessity.The followingpractices are preferred:Enclosed spaces are avoided.Enclosed locations will not receive adequate ventilation and could allow the build-upof combustible vapors or gases. Vapors with heavy densities can be particularlycumbersome as they will seek the low areas that are normally not provided with freshair circulation.Installation of walls and roofs are used only where necessary (includingfirewalls)Walls or roofs tend to block vision and access, trap sand, debris, and reduceventilation so that flammable vapors are not as quickly dispersed. They may alsocollapse if there is an explosion or deflagration. They can therefore contribute tosecondary effects by falling onto pipes an equipment that may substantially exceeddamage from the original explosion or deflagration. They can also lead to a falsesenseof security.A minimum of six air changes per hour are provided to enclosed areas.Generally hydrocarbon floors areas are open grated construction when elevated,unless solid floors are provided where there is a need for spill protection or a fire orexplosionbarrier, otherwiseventilation requirementswill prevail.b. Area congestion should be kept to a minimum.Vessels should be orientated to allow maximum ventilation or explosionventing.Bulky equipment should not block air circulationor dispersion capability.
    • Fire and Explosion Resistant Systems 163c. Release or exposure of flammablevapors to the atmosphereshould be avoided.Waste hydrocarbon gases (process vents, relief valves, and blowdowns) should berouted to the flare or returned to the process through a closed header where practical.Samplingtechniquesshould use a closed system.Process equipmentliquid drains should use a sealed drainagesystem.Open drain ports should be avoided and separate sewage and an oily water drainsystem shouldbe provided.Surfacedrainageshould be provided to remove spillsimmediately and effectivelyfromthe process area.d. Gas Detection is provided, particularly to areas handling low flash point materials with anegative or neutral buoyancy (i.e., vapor density is 1.0 or less), since these have the highestprobabilityto collect or resistanceto dispersion.e. Air or oxygen is eliminated from the interior of process systems, i.e., vessels, piping and tanks.Combustible gasses and vapors will exist in the interior of process systems by the nature ofwork. Inclusion of air inside a process will as some time for a flammable atmosphere that willexplodeonce an ignition source is available.f. Protective devices are located outside hazardous areas or behind protective barriers.g. Semi or permanently occupiedbuildingsrequired in or adjacent process areas are constructed towithstand expected explosion overpressures. Nonessential personnel or facilities are relocatedareas which are not vulnerableto explosions.Vapor Dispersion EnhancementsWater SpraysWater spray systemshave been demonstratedto assist in the dispersion of vapor releases. The spraysassist in the dilution of the vapors with the induced air currents created by the velocity of theprojected water particles. They cannot guarantee that a gas will reach an ignition source but doimprove that probabilitiesthat dispersionmechanismswill be enhanced.Air Cooler FansLarge updraft air cooler fans create induced air currents to provide cooling for process requirements.These air coolers create a considerableupdraft that ingeststhe surroundingatmosphere and dispersesit upwards. Judicious placement of fans during the initial plant design can also serve a secondarypurpose of aiding the dilution of combustiblevapors duringan accidental release.Location Optimization Based on Prevailing WindsEquipment that normally handles large amounts of highly volatile products should be placed so thatthe prevailing wind direction will disperse releases to locations that would not endanger otherequipment or provide for an ignition source for the released material.Supplemental Ventilation SystemsEnclosed locations that may be susceptible to build up of combustible gases are typically providedwith ventilation systemsthat will dispersethe gases or provide sufficient air changes to the enclosures
    • 164 Handbook of Fire and Explosion Protectionsuch that gas leakages will not accumulate.enclosures, offshoreenclosed modules, etc.Typical examples are battery rooms, gas turbineDamage Limiting ConstructionVarious methods are availableto limit the damage from the effects of an explosion. The best optionsare to provide some pre-installed or engineered features into the design of the facility or equipmentthat allow for the dissipation or diversion of the effects of a blast to nonconsequential areas.Wherever these mechanisms are used the overpressure levels utilized should be consistent with therisk analysisestimatesof the WCCE incident.Where enclosed spaces may produce overpressures blow out panels or walls are provided to relievethe pressure forces. The connectionsof the panel are specified at a lower strength that normal panelsso it will fail at the lower level and relieve the pressures. Similarly,combustible or flammable liquidstorage tanks are provided with weak roof to shell seams so that in case of an internal explosion, thebuilt-up pressure is relieved by blowing off the roof and the entiretank does not collapse.For exposed buildings at onshore facilities, heavy monlithic concrete construction is used.Entrancewaysare provided with heavy blast resistancedoors. that do not face the exposed area.FireproofingFollowing an explosion incident, local fires develop which it left uncontrolled, result in aconflagration of the entire facility and its destruction. Fire protection measures are provided asrequired to control these occurrences. The ideal fire protection measure is one that does not requireaddition action to implement and is always in place. These methods are considered passiveprotection measures and the most familiaris fireproofing.It has been demonstrated that steel strength decreases rapidly with temperature increases above 260OC (500 OF). At 538 OC (1000 OF), its strength both in tension and compression is approximatelyhalf, at 649 OC (1200 OF) its strength decreases to less than one quarter. Bare steel exposed tohydrocarbon fires may absorb heat at rates from 10,000to 30,000 Btu/hr/sq. A.,depending on theconfiguration of the exposure. Due to the high heat conduction properties of steel, it is readilypossible for normally loaded steel members or vessels to lose their strength to the point of failurewithin ten minutes or less of a hydrocarbon fire exposure.In a strict sense, fireproofingis a misnomer, as nothing is entirely “fireproof”. In the petroleum andrelated industries the term fireproofing is commonly used to refer to material that is resistive to acertain set of fire conditionsfor a specifiedtime. The basic objective of fireproofingis to provide apassive means of protection against the effects of fire to structure components, fixed property or tomaintain the integrity of emergency control systems or mechanisms. Personnel shelters or rehgesshould not be considered adequatelyprotected with fireproofing unless measures to provide fresh airand protection against smoke and toxic vapor inhalationis also provided. In itself fireproofingshouldalso not be considered protection against the effects of explosions, in fact quite the opposite may betrue, fireproofing may be just as susceptible to the effects of an explosion, unless specificarrangementshave be stipulated to protect it from the effectsof explosion overpressures.Fireproofing for the petroleum and related industries follow the same concept as other industriesexcept that the possible fire exposures are more severe in nature. The primary destructive effects offire in the petroleum industry is very high heat, very rapidly, in the form of radiation, conduction andconvection. This causes the immediate collapse of structures made of exposed steel construction.Radiation and convection effects usually heavily outweigh the factor of heat conduction for the
    • Fire and Explosion Resistant Systems 165purposes of fireproofing applications. Fireproofing is not tested to prevent the passage of toxicvapors or smoke, other barriers must be installed to prevent the passage of these. The collapse ofstructural components in itself is not of high concern, as these can usually be easily replaced. Theconcern of structural collapse is the destruction of the items being supported and the impact damageand spread of large quantities of combustible fluids or gases they might release to other portions ofthe facility. Where either of these features might occur that would have high capital impact, either inimmediatephysical damageor a businessinterruption aspect, the applicationof fireproofingshouldbeconsidered. Usually where essentially only piping is involved, which would not release enormousamounts of combustiblematerials, fireproofingfor pipe racks is not economicallyjustified. Commonpiping and structural steel normally can be easily and quickly replaced. It is usually limited tolocations where equipment that requires a long replacement time might be damaged if the rackcollapsed or are supportive of emergency incident control function, such as depressuring andblowdown headersthat are routed to the flare.The primary value of fireproofing is obtained in the very early stages of a fire when efforts areprimarily directed at shutting down processes, isolating fie1 supplies to the fire, actuating fixed orportable fire suppression equipment and conducting personnel evacuation. If equipment is notprotected, then it is likelyto collapseduring this initial period. This will cause firther impact damageand possibly additional hydrocarbon leakages. It may become impossible to actuate ESD devices,vent vessels, or operate fire suppression devices. During firther escalation of the fire larger vessels,still containinghydrocarboninventories, can rupture or collapse causing a conflagrationof the entirefacility.It is theoretically possible, based on the assumption of the type of fire exposure (i.e., pool, jet, etc.)to calculatethe heat effects from the predicted fire on every portion of petroleum facility. As of yetthis extremelycostly and cannotbe performed economicallyfor an entire facility.What is typically applied, is the standard effects of a petroleum fire (i.e., a risk exposure area isdefined) for a basic set of conditions that is used for most locations in a facility. If necessaryexaminations of critical portions of a facility for precise fire conditions are then undertaken bytheoretical calculations. In general the need for fireproofingis typically defined by identifying areaswhere equipmentor processes can release liquid or gaseous he1that can burn with sufficientintensityand duration to result in substantial property damage. In the petroleum industriesthese locations arenormally characterized by locations with a high liquid holdups or pressures historically having aprobabilityof release and high pressure gas release sources.Typical locationswhere fire risk exposures are considerprevalent are:(1) Fired heaters(2) Pumps handling hydrocarbon materials(3) Reactors(4) Compressors(5) Large hydrocarboninventoryvessels, columns, and drumsAdditionally whenever equipment is elevated, which could be source of liquid spillage, long downtime for replacement, or supports flare or blowdown headers in a fire exposure risk area, fireproofingof the supports is normally applied. API Publication 2218 provides firther guidance on the exactnature of items and conditionsthat the industry considersprudent for protection.A standard fire duration (e.g., 2 hours) is applied and a high temperature fire (Le., UL 1709) isnormally assumed from the hydrocarbonrelease sources.
    • 166 Handbook of Fire and Explosion ProtectionThe following material aspects should be considered which application of fireproofing iscontemplated:- Fire performance data (fire exposure and duration)- Costs (material, installationlabor and maintenance)- Weight- Explosion resistance-Mechanicalstrength (resistanceto accidental impacts)- Smokeor toxic vapor generation (when life safetyis associated with protection)- Water absorption- Degradationwith age- Applicationmethod- Surfacepreparation- Curingtime and temperature requirements- Inspectionmethod for coated surface- Thicknesscontrol method-Weather resistance- Corrosivity-Ease of repairFireproofing SpecificationsTypically fireproofing materials are specified for either cellulosic (ordinary) or hydrocarbon(petroleum) fire exposures at various durations. The essential feature of the fireproofing is that itdoes not allow the passage of flame or heat and therefore can protect against structural collapse forcertain conditions. Because fireproofing is nomially not tested to prevent the passage of smoke ortoxic vapors its use to provide protection for human habitation should be carefully examined, inparticular the effects of the passage of smoke and lack of oxygen in the environment. It should bebore in mind that fireproofing is tested to a set of basic standards. These standards cannot beexpected to correlate to every fire condition that can be produced in a petroleum facility. Thespacing, configuration, and arrangement of any hydrocarbon process can render the application offireproofing inadequate for the fire duration if the fire intensity is higher than the rating of thefireproofing. Fire resistance enclosures should not only be rated for protection against the predictedfire exposurebut to ensure the continued operation of the equipment being protected. For exampleifthe maximum operating temperature of a valve actuator is only 100 OC (212 OF), ambienttemperature limits inside the enclosure should be allowed to rise above, even though the fireproofedenclosurehas met the requirementsof a standard fire test. The operatingrequirementsfor emergencysystems must alwaysbe bore in mind.There are a number of fire test laboratories in the world that can conduct fire tests according todefined standards and on occasion specialized tests. Table 17 provides a list of the test agenciesrecognized by the petroleum and related industries.
    • Fire and Explosion Resistant Systems 167Table 17Recognized Fire Testing LaboratoriesStructural steel begins to soften at 316 OC (600 OF) and at 538 OC (1,000 OF) it loses 50% of itsstrength. Therefore the minimum accepted steel temperature for structural tolerance is normally setto 400 OC (752 OF) for a period of 2 hours, exposed to a high temperature hydrocarbon (;.e.,petroleum) fire (Ref. UL Standard 1709).
    • 168 Handbook of Fire and Explosion Protection12001000800600Temperature(Degree C)4002000I+Hydrocarbon FireI+Cellulosic Fire0 Hrs. 0.17 0.34 0.5 0.67 0.84 1.0 1.17 1.34 1.5 1.67 1.84 2.0Hm. HE.TimeFigure 9Time TemperatureCurves for Petroleumversus CellulosicFires(Degrees Celsiusversus Time in Minutes)
    • Fire and Explosion Resistant Systems 169Recent experiential work suggests that heat flux is a more realistic method of determine the heattransmission into fire barriers. Typical heat flux values of 30-50 kwhq. m (9,375 - 15,625Btu/sq./fi.) for pool fires and 200-300 kw/sq./m (62,500 - 93,750 Btu/sq. ft.) for jet fires is normallythe basis of heat flux exposure calculations.FireproofingMaterialsThere are numerous fireproofing materials available on the marketplace and the selection of thematerial involved is based on the application and advantages versus disadvantages of each over aneconomic factor. Usually no single material is ideally suited for a particular application, and anevaluation of the cost, durability,weatherability, and combinationof factors is necessary.Cementitious MaterialsCementitiousmaterials use a hydraulically setting cement such as Portland cement as a binder witha filler material of good insulationproperties, e.g., verminculite,perlite, etc. Concrete us frequentlyused for fireproofing because it is easily installed, readily available, is quite durable and generallyeconomicalcompared to other methods. It is heavy compared to other materials and requires moresteel to support that other methods.Pre-formedMasonry and InorganicPanelsBrick, concrete blocks, or pre-cast cement aggregate panels have been commonly used in the past.These materialstend to be labor intensiveto install and are less economicalthan other methods.MetallicEnclosuresStainless steel hollow panels filled with mineral wool are fabricated in precise dimensions towithstand the specified fire exposure. Typically electrical equipment must operate within aspecified level for a period of time when a fire exposure occurs and is protected by such enclosures.Thermal InsulationThese can be inorganic materials such as calcium silicate, mineral wool, diatomaceous earth orperlite and mineral wool. If provided as an assembly they are fitted with steel panels or jackets.These are woven noncombustible or flame retardant materials the provide insulation properties totire barrier for the blockageof heat transfer.Intumenscent CoatingsIntumenstentcoatings have an organic base that, when subjected to a fire, will expand and producea char and underlyinginsulatinglayer.RefractorvFibersFibrous materialswith a high melting point are used to form fire resistant boards and blankets. Thefibers are derived from glass mineralsor ceramics. They may be woven into cloths and are used asblankets around the object to be protected.
    • 170 Handbook of Fire and Explosion ProtectionTable 18Passive Fire Protective SystemsThe principlefeatures of passive protection are summarizedbelow:Advantapes-No initiationrequired.- Immediateprotection with low conductivitymaterials, reactive materials respond when thresholdtemperature is reached.-No power required.- Meet regulatory requirements.- Low maintenance.- Can be upgraded.- Certain materials can provide anti-corrosionbenefits.- No periodic testing required.Disadvantages- Provide only short duration protection when compared to active systems.-Not renewable during or after a fire.- Inspectionof substrate for permanent materials for corrosion can be difficult.Choice -Determined bv:- Application.- Protection required- Performance.-Physical properties.- Costs.
    • Fire and Explosion Resistant Systems 171CompositeMaterialsLightweight Composite proprietary materials, typically of glass fiber and polyester resins, areavailable as sheet boards which can be arranged into protective walls or enclosures. They offerlight weight, inherent insulation, and can be configured to achieveblast protection. These materialsare corrosion free, and wear resistant.Radiation ShieldsIn some cases radiation shields are provided to protect against heat effects from fire incidents and operationrequirements. The shieldsusually are of two styleseither a dual layer wire mesh screen or a plexy-glass seethrough barrier. The shields provide a barrier from the effects of radiant heat for specificlevels. They aremost often used for protection against flare heat and for bamers at fixed firewater monitor devices, mostnotably at the helidecks of offshorefacilities.Water Cooling SpraysWater sprays are sometimes used instead of fireproofing where the fireproofing application may beconsidered detrimental to the situation or uneconomical to achieve. Typical examples are the surface ofpressure vessels or piping where metal thickness checks are necessary, structural facilities that cannotaccept additional loads of fireproofing materials due to dead weight or wind loads, inaccessibly of thesurfacefor applicationof fireproofing,or impracticabilityof fireproofingapplication.Normally where it is necessary, fireproofing is preferred over water spray for several reasons. Thefireproofing is a passive inherent safety feature, while the water spray is a vulnerable active system thatrequires auxiliary control to be activated. Additionally the water spray relies on supplemental supportsystems that may be vulnerable to failures, Le., pumps, distribution network, etc. The integrity offireproofing systems is generally considered superior to explosion incidents compared to water spray pipingsystems. The typical applicationof water spraysin place of fireproofingis for vessel protection.The water spray protects the exposure by:(1.) Coolingthe surfaceof the exposure.(2.) Coolingthe atmospheresurroundingthe exposure and from the source.(3.) Limitingthe travel of radiant heat from flamesto adjacent exposures.Vapor DispersionWater SpraysFire water sprays are sometimes employed as an aid to vapor dispersions. Some literature on the subjectsuggeststwo mechanismsare involvedthat assist in vapor dispersionswith water sprays. First, a water sprayarrangement will start a current of air in the direction of the water spray. The force of the water sprayengulfsair and dispenses it hrther from its normal circulatingpattern. In this fashion released gases will alsobe engulfed and directed in the directionof nozzles. Normal arrangement is to point the water spray upwardto direct ground and neutral buoyancy vapors upwards for enhanced dispersion by natural means at higherlevels. Second, a water spray will warm a vapor to neutral or higher buoyancy to also aid in its naturalatmospheric dispersion.
    • 172 Handbook of Fire and Explosion ProtectionLocations Requiring Considerationof Fire Resistant MeasuresThe application of fire resistant materials is commonly afforded to locations where large hydrocarbonspillages or high pressure high volume gas releases may occur with a high probability (ie. fire hazardouszones). These locations commonly are associated with rotating equipment and locations where higherosiordcorrosioneffects could occur. Alternativelyfireproofingmaterials are used to provide a fire barrierwhere adequate spacing distances are unavailable (Le., offshore installations, escape measures, etc.). A P IPublication 2218 provideshrther guidancein the application and materialsused in the industry.0 OnshoreVessel, tank and piping supports in fire hazardous zones.Critical services (ESD valves, control and instrumentation).Pumps and high volume or pressure gas compressors.0 OffshoreHydrocarbonprocessing compartments.Floors, walls, roofs for accommodations.Structural support located in fire hazardous zones.Room doors and windows.Pump and high volume or pressure gas compressors0 CommonPetroleumIndustry Fireproofing Material ApplicationsVessel and Pipe Supports:Onshore: 2 inches of Concrete; UL 1709,2 hour ratingOffshore: Ablativeor intumensentmaterials, UL 1709,2 hour ratingCable Trays: Stainless steel cabinets or fire rated mats, UL 1709, 20 minute ratingESD Control Panels: Stainlesssteel cabinets or fire rated mats, UL 1709,20 min. ratingEIVs: (If directly exposed) -Stainless steel cabinets or fire rated mats UL 1709, 60 min.EIV actuators: Stainless steel cabinetsor fire rated mats UL 1709,20 minute ratingFirewalls:Onshore: Concrete or masonry construction,UL 1709, 2 hour ratingOffshore: Ablative,composite or intumensent, UL 1709, 2 hour ratingFlame ResistanceInterior SurfacesMost building fire codes set fire resistive standards for interiorwall and ceiling finishes and overallrequirements for building construction fire resistance features. Based on fire statistics,the lack ofproper control over an interior finish is second only to the vertical spread of fire through openingsin floors as the cause of lossof life in buildings. The dangers of unregulated interior finishmaterialsare mainly: (1) The rapid spread of fire presents a threat to the occupants of the buildingby eitherlimiting or delaying their use of exitways within and out of a building. The produciton of denseblack smoke also obscures the exit path and exit signs. (2) The contributionof additional fuel to afire. Unregulated finish materials have the potiential for adding fuel to the fire, thereby increasingits intensity and shorteningthe time availablefor occupants to escape. The intent of most buildingfire codes is to regulate only the interiorfinish of materials on walls and ceilingsand not to regulatefloor coverings since experience tells that traditionaltype of interior finish materials such as wood,vinyl tile, linoleum,and other resilient floor covering materials do not contributeto the early spreadof fire.
    • Fire and Explosion Resistant Systems 173Electrical CablesElectrical conductors are normally insulated for protection and avoidance of electrical shorting.Typicalinsulatingmaterials are plastics that can readily burn with toxic vapors. The NEC specifiescertain fire resistant rating to electrical cablesto lessen the possibilityof cable insulation ignitabilityand fire spread.Optical fiber cablesThe increasing use of fiber optics for electronic communications poses critical communicationsrisks. The fireresistant requirements of fiber optical cables are currently similar to the requirementsof fire resistant ratings applied to electrical cables within the specifications of the NEC.Fire DampersFire dampers are an assembly of louvers that are arranged to close to prevent the passage of flameand heat. Dampers are installed in ventilation openings or shafts to provide a fire rated barrierequal to the surroundingbarrier. They are activated by spring release by the melting of a fbsiblelink. or by remote control signals.Acceptance testing of fusible link fire dampers should always include a random sample actualfusiblelink (melting) test of the installed assembly that causes the damper to close. Many times animproperly installed damper will not close correctly and the shutter louvers become hung up ortwisted. An alternativesometimes availableis a link assembly that can be temporaryinstalledthat iseasily cut by a pair of clippers. The fbsiblelink meltingtemperature can then be tested separately ata convenient location without subjectingthe installationheat or flames for testing purposes.Smoke DampersSmoke dampers are used to prevent the spread of products of combustion within ventilationsystems. They are usually activated by the fire alarm and detection system. Smoke dampers arespecified on the leakage class, maximum pressure, maximum velocity, installation mode (horizontalor vertical) and degradationtest temperature of the fire.Flame and Spark ArrestorsFlame arrestors stop the flame propagation from entering through the opening. The devicecontains an assembly of perforated plates, slots, screens, etc., enclosed in a case or frame thatabsorb the heat of flame entering and thereby extinguish it before can pass. When burning occurswithin a pipe, some of the heat of combustion is absorbed by the pipe wall. As the pipe diameterdecreases, an increasing percentage of the total heat is absorbed by the pipe wall and the flamespeed in the pipe decreases. By using very small diameter (one or two millimeters), it is possible tocompletely prevent the passage of flame, regardless of flame speed. A typical flame arrestor is abundle of small tubes, which achieves the required venting capacity but prevents the passage offlame. The "Davy" miners lamp was the first use of flame arrestor in which a fine mesh screen ofhigh heat absorption properties was placed in front of the flame of the miner lamp to preventignitionof methane gas in coal mines.
    • 174 Handbook of Fire and Explosion ProtectionResearch has shown that pressure-vacuum vents arejust as effective as flame arrestors for storagetanks against internal ignitions.Spark arrestors are provided on the exhaust of source or fire where a hot particulate might bereleased (Le., internal combustion engines, chimneys, incinerator stacks, etc.). The spark arrestorconsist of a fine metal screen to prevent the particulate matter from being released from the exhaustmechanism.Piping Detonation ArrestorsPipe detonation arrestors are provided where there is a possibilityof highly acceleratingflamefronts withinpiping systemsdue to poor piping designsto prevent such occurrences.
    • Fire and Explosion Resistant Systems 175Bibliography1.2.3.4.5.6.7.8.9.10.1112131415.1617181920A. D. Little, Inc., Evaluationof LNG Vauor Control Methods, American Gas Association (AGA), Arlington, VA,1974American Institute of Chemical Engineers (AIChE), Guidelines for Vapor Release Mitigation, AIChE, New York,NY, 1988.AmericanInstituteof ChemicalEngineers(AIChE), Guidelines for Use of Vapor Cloud DispersionModels, AIChE,New York, NY, 1987.AmericanIron andSteel Institute(AISI),Fire Safe StructuralSteel,AISI, Washington, D.C., 1979.American Petroleum Institute (API), RP-521. Guide for Pressure-Relieving and Depressuring Svstems, ThirdEdition, API, Washington,D.C., 1990.American Petroleum Institute (API), Publication 2218, Fireproofin? Practices in Petroleum and PetrochemicalProcessingPlants, First Edition,API, Washington, D.C., 1988.American Petroleum Institute (API), Standard 2508. Design and Constructionof Ethane and Ethvlene Installationsat Marine and uiueline Terminals.Natural Gas Processing Plants. Refineries, PetrochemicalPlants and Tank Farms,SecondEdition,API, Washington,D.C. 1985.American Petroleum Institute (API), Standard 2510 Design and Construction of Liquefied Petroleum GasInstallations. (LPG), SixthEdition,API, Washington,D. C., 1989.American Petroleum Institute (API), Publication 2510A Fire Protection Considerations for the Design andOperationof LiquefiedPetroleum Gas (LPG) StorayeFacilities,First Edition, API, Washington,D. C., 1989.American Society of Civil Engineers (ASCE), ASCE 78-92. Structural Fire Protection, ASCE, New York, NY,1992.American Society of Testing Materials (ASTM), E-119, Method of Fire Tests of Building Construction andMaterials, ASTM, Philadelphia, PA.British StandardsInstitute,BS 7244. FlameArrestors for GeneralUse, BSI, London,U.K.Bodurtha, F.T., IndustrialExplosionPrevention and Protection, McGraw-Hill,New York, NY, 1980.IndustrialRisk Insurers(IRI), IM.2.5.1.Fireuroofingfor Oil and ChemicalProperties,IRI, Hartford,CT.IndustrialRisk Insurers(IN),IM.2.2.1. Firewalls, IRI, Hartford,CT.National Fire Protection Association (NFPA), Standard 221. Construction of Fire Walls and Barriers, ProposedStandard,NFPA, Quincy, MA, 1993.Sheet Metal and Air Conditioning ContractorsNational Association,Inc., (SMACNA),Fire. Smoke and RadiationDamuer InstallationGuidefor HVAC Systems,Fourth Edition, SMACNA,Chantilly,VA, 1993.Tunkel, S. J., "Methods for Calculationof Fire and Explosion Hazards", AIChE Today Series, AIChE, New York,NY, 1984.Underwriters Laboratories Inc. (UL),UL 263, Safety Fire Tests of Building Constructionand Materials, EleventhEdition, UL, Northbrook,IL, 1992.Underwriters Laboratories Inc. (UL), UL 525, Safetv Flame Arrestor for Use on Vents of Storage Tanks forPetroleumOil and Gasoline,Fifth Edition, UL, Northbrook,IL, 1992.
    • 176 Handbook of Fire and Explosion Protection21. Underwriters LaboratoriesInc. (UL), UL 555. Safety Fire Dampers,Fifth Edition,UL, Northbrook,IL, 1994.22. Underwriters LaboratoriesInc. (UL),UL 5553. Safely Leakage Rated Damuers for Use in Smoke Control Systems,SecondEdition,UL, Northbrook,IL, 1994.23. Underwriters LaboratoriesInc. (UL), UL 1709. Safety Rapid Rise Fire Tests of ProtectiveMaterials for Structuralw,First Edition,UL, Northbrook,IL, 1991.Also seeAppendixB.1
    • Chapter 17Fire & Gas Detection and Alarm SystemsVarious simple and sophisticatedfire and gas detection systems are availableto provide early detection andwarnings of a hydrocarbon release which supplement process instrumentation and alarms. The overallobjective of fire and gas detection systems are to warn of possible impendingevents that may be threateningto life, property of continued business operations.that are externalto the process operation.Process controls and instrumentationonly provide feedback for conditionswithin the process system. Theydo not report or control conditions outside the assumed process integrity limits. Fire and gas detectionsystems supplement process information systems with instrumentationthat is located external to the processto warn of conditions that could be considered harmhl if found outside the normal process environment.Fire and gas detection systems may be used to confirm the readings of major process releases or to reportconditions that process instrumentation may not adequately report or be unable to report (i.e., minorprocessreleases).Fire and Smoke Detection MethodsHydrocarbon vapors immediately burn with flame temperatures that are considerably higher than that ofordinary combustibles. For this reason damage from a hydrocarbon fire is much more severe than anordinary combustiblefire. The objective of a fire detection for the petroleum industry is to rapidly detect afire where personnel, high value, and critical equipment may be involved. Once detected executive action isinitiated to alert personnel for evacuation and while simultaneously controlling and suppressing the fireincident.Human SurveillanceHuman beings provide the first line of observation and defense for any facility. Periodic or constant firsthand operator on site surveillanceof the process provides carehl observation and reporting of all activitieswithin the facility. Humans have keen senses that have yet to be expertly duplicated by instrumentationdevices or sophisticated technical surveillance mechanisms. In this fashion they are more valuable in theobservationof systemperformancethan ordinaryprocess control systems may be.It should be rememberedthat humans are also prone to panic and conhsion at the time of an emergency andso may also be unreliable in some instances. Where proper training and selection of personnel occurssituationsof panic and confbsion may be overcome.177
    • I78 Handbook of Fire and Explosion ProtectionManual Activation Callpoint (MAC)/Manual Pull Station (MPS)Simple switches that can be manually activated can be considered a fire alarm device. Models are usedwhich normally require the use of positive force, i.e., to avoid accident and fraudulent trips. Fire alarmswitches normally can only be reset by special tools in order to trace the source of the alarm, howeversophisticated data reporting systemswith addressabledata collectionmay makethis requirement obsolete.Manual activation devices are normally placed in the main egress routes from the facility or location.Usually placement in the immediatehigh hazard location egress route and at the periphery evacuationroutesor muster location ofthe installationis accomplished.TelephoneReportingAll telephonepoints can be considered a method of notification. Telephonescan be easily placed in a facilitybut may be susceptible to ambient noise impacts and the effects of a fire or explosion. Additionallyinformation from verbal sources can be easily misunderstoodof spoken during an emergency. Simultaneoususe of the phone system during emergency situations may also cause it to be overloaded and connectionsdifficultto achieve.Portable RadiosOperations personnel are normally provided with portable radios in large facilities. They have similardeficiencies to telephones but offer the advantage on onsite portability with continuous communicationaccess.SmokeDetectorsSmoke detectors are employed where the type of fire anticipated and equipment protection needs a fasterresponse time than heat detectors. A smoke detector will detect the generation of the invisible and visibleproducts of combustionbefore temperature changes are sufficient to activateheat detectors. The ability of asmoke detector to sense a fire is dependent on the rise, spread, rate-of-burn, coagulation and air movementof the smoke itself. Where the safety of personnel is a concern, it is crucial to detect a fire incident at itsearly stages because of the toxic gases, lack of oxygen that may develop, and obscuration of escape routes.Smoke detection systems should be consideredwhen these factors are present.IonizationIonization and condensationnuclei detectors alarm at the presence of invisible combustion products.Most industrial ionization smoke detectors are of the dual chamber type. One chamber is a samplechamber the other is a reference chamber. Combustion products enter an outer chamber of anionization detector and disturb the balance between the ionization chambers and trigger a highlysensitive cold cathode tube that causesthe alarm. The ionizationof the air in the chambers is causedby a radioactive source. Smoke particles impede the ionization process and trigger the alarm.Condensation nuclei detectors operate on the cloud chamber principle, which allows invisibleparticles to be detected by optical techniques. They are most effective on Class A fires (ordinarycombustibles)and Class C fires (electrical).PhotoelectricPhotoelectric detectors are of the spot type or light-scattering type. In each, visible products ofcombustion partially obscure or reflect a beam of light between its source and a photoelectricreceiving element. The disruption of the light source is detected by the receiving unit and as a result
    • Fire and Gas Detection and Alarm Systems 179an alarm is actuated. Photoelectric detectors are best used where it is expected that visible smokeproducts will be produced. They are sometimes used where other types of smoke detection is toosensitive to the invisible products of combustion that are produced in the area as part of normaloperations such as garages, fitrnacerooms, welding operations, etc.Dual ChamberCombinations of photoelectric and ionization detectors are available that operate as describe above.They are used to detect either smolderingor rapidly spreadingfires.Very Early Smoke Detection and Alarm (VESDA)High sensitivitysamplingsmoke detector systems provide the best form of rapid smoke detection forhighly critical equipment or in high air flow situations. The VESDA system is basically a suctionpump with collectiontubes or pipes that use an optical smoke detection device to test for evidence ofsmoke particles. Since it gathers air samplesfrom the desired protected area they are much faster indetection than ordinary detection that has to wait for the smoke to arrive to it. Care must be takenthat the sampling tubes are protected fiom mechanical damage and the initial effects of an incident.In the petroleum industry, VESDA systems are typically provided for the interior of electrical orelectroniccabinets or racks that control critical oil or gas processingactivities.Thermal or Heat DetectorsThermal or heat detectors respond to the energy emissionfrom a fire in the form or heat. The normal meansby which the detector is activated is by convention currents of heated air or combustion products or byradiation effects. Because this means of activationtakes some time to achieve thermal detectors are slowerto respond to a fire when compared to some other detection devices.There are two common types of heat detectors - fixed temperature and rate of rise. Both rely on the heat ofa fire incident to activate a signal device. Fixed temperature detectors signal when the detection element isheated to a predetermined temperature point. Rate of rise detectors signal when the temperature rises at arate exceeding a pre-determined amount. Rate of rise devices can be set to operate rapidly, are effectiveacross a wide range of ambient temperatures, usually recycle rapidly and can tolerate a slow increase inambient temperatures without providing an alarm. Combinationfixed temperature detectors and rate of risewill respond directly to a rapid rise in ambient temperatures caused by fire, will tolerate a slow increase inambient temperatures without effecting an alarm, and recycle automatically on a drop in ambienttemperature.Heat detectors normally have a higher reliability factor than other types of fire detectors. This tendsto lead to fewer false alarms. OveraII they are slower to activate than other detecting devices. Theyshouldbe considered for installation only where speed of activation is not considered critical or as abackup fire detection device to other fire detection devices. They have an advantage of suitabilityforoutdoor applicationsbut the disadvantageof not sensing smokeparticles or visibleflamefrom a fire.Some of the systems can be strung as a line device and offers detection over a long path alternativelythey be used as spot detectors. A common deficiency after installationis they tend to become paintedover, susceptible to damage, or the fitsible element may suffer a change in activation temperatureover a long installationperiod.Heat detectors are activated by either melting a hsible material, changes in electrical current inducedby heat loads on bi-metallic metaIs, destruction of the device itselfby the heat, or by sensing a rate ofambient temperature rise.
    • 180 Handbook of Fire and Explosion ProtectionThe following are some of the most common heat detection devices that are commerciallyavailableand used in the hydrocarbonindustries.Flexible plastic tubing (pneumatic)Fusible optical fiberBi-metallicwire or stripFusibleplug (pneumatic pressure release)Quartzoidbulb (pneumatic pressure release)Fusible link (under spring tension)Fixed temperature detectorRate of rise detectorRate compensatedCombinationrate of rise and fixed temperature(On a rare occasion a tensioned stringtied to pressure switch has been provided as detection overthe vapor seal area of a floatingroof crude storage tank. Although this method may be consideredprimitiveand cheap, it is effective and beneficial versus the option of no detection).Optical (Flame) DetectorsFlame detectors alarm at the presence of light from flames usually in the ultraviolet or infared range. Thedetectors are set to detect the typical light flicker of a flame. They may be equipped with a time delayfeaturesto eliminatefalsealarms from transient flickeringlight sources.There are six types of opticaldetector commonlyused in the oil and gas industry.1. Ultraviolet (W).2. Singlefrequency infrared (IR).3. Dual frequency idtared (IR/TR).4. Ultraviolet/infrared- simple voting (W/IR).5. Ultraviolet/infrared - ratio measurement (UVAR).6. Multi-band.Each of the five types of detectors listed has advantages and limitations, making each more or less suitablefor an applicationor a specificrisk. There is not a uniform performance standard for flame detectors such astheir is with smoke detectors. Flame detection for a particularmodel has to be analyzed by evaluation of itstechnical specificationto expected fire development.Ultraviolet (UV) DetectorResponds to the relatively low energy levels produced at wavelengths between 0.185 and0.245 microns. This wavelength is outside the range of normal human visibility andoutside that of sunlight.AdvantagesThe ultraviolet detector is general all purpose detector. It responds to most burningmaterials but at different rates. The detector can be extremely fast, i.e., less than 12 milli-secondsfor special applications (e.g., explosivehandling). It is generallyindifferentto thephysical characteristics of flames and does not require a "flicker" to meet signal inputfunctions. It is not greatly affected by deposits of ice on the lens. Special modules areavailable that can be used in high temperature applications up to 125 OC (257 OF). Hotblack body sources, (stationary or vibrating) are not normally a problem. It is blind to
    • Fire and Gas Detection and Alarm Systems 181solar radiation and most forms of artificial light. An automatic self testing facility can bespecified or it can be tested with a hand held source at distances more than 10 meters (3ft.) from the detector. Most models can be field adjusted for either the flame sensitivityorthe time delay hnction.LimitationsIt responds to electric arcs from welding operations. It can be affected by deposits ofgrease and oil on the lens. This reduces its ability to "see" a fire. Lightning with longduration strikes can cause false alarm problems. Some vapors typically those withunsaturated bonds may cause signal attenuation. Smoke will cause a reduction in signallevel seen during a fire. It may produce a false alarm response when subject to otherforms of radiationsuch as fromNDT operations.Single Frequency Infared (IR) DetectorsThis detector responds to infrared emissions from the narrow C02 band at 4.4. microns.It requiresthe satisfaction of a flicker frequency discriminationat between 2 and 10Hz.AdvantagesIt responds well to a wide range of hydrocarbon fires and is blind to welding arcs exceptwhen very close to the detector. It can see through smoke and other contaminates thatcould blind a W detector. It generally ignores lightning, electrical arcs and other formsof radiation. It is blind to solarradiationand resistant to most forms of artificiallighting.LimitationsThere are few models with automatic test capability. Testing is usually limited to handheld devices only 2 meters (7 fi.) from the detector or directly on the lens test unit. It canbe ineffective if ice forms on the lens. It is sensitive to modulated emissions from hotblack body sources. Most of the detectors have fixed sensitivities. The standard beingunder five secondsto a petroleumfire of 0.1 square meter (1.08 sq. 6.)located 20 meters(66 fi.) from the device. Response times increase as the distance increases. It cannot beused in locationswhere the ambienttemperatures could reach up to 75 OC (167 OF). It isresistant to contaminantsthat could affect a UV detector. Its response is dependent onfires possessing a flicker characteristic so that detection of high pressure gas flames maybe difficult.Dual or Multiple Frequency Infrared (IR/IR) DetectorsThis detector respondsto infrared emissionsin at least two wavelengths. Typically a C02reference at 4.45 microns is established and a second reference channel that is away fromthe C02 and H20 wavelengths is made. It requires that the two signals received areconfirmedas are synchronousand that the ratio between both signalsis correct.AdvantagesIt responds well to a wide range of hydrocarbon fires and is blind to welding arcs. It candetect fires through smoke and other contaminates, although the signal pickup will bereduced. It generally ignores lighting and electrical arcs. It has minimal problems withsolar radiation and artificial radiation. It is also insensitiveto steady or modulated blackbody radiation. There is a high level of false alarm rejection with this model of detector.
    • 182 Handbook of Fire and Explosion ProtectionLimitationsDetectors with complete black body rejection capability are usually less sensitive to firesthan a single frequency infrared optical detector. Because its discrimination of fire andnon-fire sources depend upon an analysis of the ratio between fire and referencefrequencies, there is a variation in the amount of black body rejection achieved. Adetectors degree of black body radiation rejection is in inversely proportion to its abilityto sense a fire. The detectors are limited to applications that involve hydrocarbonmaterials.Ultraviolet/Infrared(UV/IR) DetectorsThere are two types of detectors under UV/IR classifications. Both of the types respondto frequencies in the UV wavelength and IR in the C 0 2 wavelength. In both typessimultaneouspresenceof the W and IR signalsmust be availablefor alarm conditions. Inthe simple voting device an alarm is generated once both conditions are met. In the ratiodevice, satisfaction of the ratio between the level of UV signal received and IR signalreceived must also be achieved before an alarm condition is confirmed.AdvantagesThese detectors respond well to a wide range of hydrocarbon fires and are indifferent toarc welding or electric arcs. There are minimal problems with other forms of radiation.They are blind to solar radiation and artificial lighting. They ignore black body radiation.Its fairly fast response is slightly better than a single fiequency IR detector but not as fastas a W detector. The simple voting type will respond to fire in the presence of an arcwelding operation. It is not desensitized by the presence of a high background IR source.The flame sensitivitiesof the simplevoting detector can be field adjusted.LimitationsThe sensitivityto a flame can be affected by deposits of IR and UV absorbing materials onthe lens if not frequently maintained. The IR channelcan be blinded by ice particles on thelens.While the W channel can be blinded by oil and grease on the lens. Smoke and somechemical vapors will cause reduced sensitivity to flames. UVAR detectors require aflickeringflameto achieve an IRsignalinput. The ratio type will lock out when an intensesignal source such as arc welding or high steady state IR source is very nearby.Flame response for a ratio type is affected by attenuators, while in the voting type there isnegligible effect. The detectors are limited to applications involving hydrocarbonmaterials.Multi-band DetectorsMulti-band fire detector monitors monitor several wavelengths of predominate fireradiation frequencies by photocells. They compare these measurements to normalambient frequenciesthrough micro processing. Where these are found be above certainlevels an alarm is indicated. False alarmsmay even be "recognized"AdvantagesThese detectors have a very high sensitivity and very encouraging stability.microprocessorhas the capabilityto be programmed to recognizecertain firetypes.The
    • Fire and Gas Detection and Alarm Systems 183DisadvantagesMay be inadvertentlymis-programmed. The detector is relatively new on the market andneeds Grther industry experiencefor wide acceptance.Table 19Comparison of Fire Detectors
    • 184 Handbook of Fire and Explosion ProtectionTable 20Applicationof Fixed Fire Detection Devices
    • Fire and Gas Detection and Alarm Systems 185Gas DetectionGas detection is provided in the petroleum industry to warn of and possibly prevent the formation of acombustiblegas or vapor mixture that could cause an explosive overpressure blast of damaging proportions.There are two types of gas detectors used in the oil and gas industry. The most common and widely used isthe catalytic detector. More recently, infared (IR) beam detectors have been employed for special "line ofsight" applications, such as perimeter,boundary or offsite monitoring, pump alleys, etc.A gas detection system monitors the most likely sources of releases and activates alarms or protectivedevicesto prevent the ignition of a gas release and possibly mitigate the effects of a flash fire or explosion.Most hydrocarbon processes contain gases in a mixture. Therefore the gas detection vapor selected fordetectionmust be chosen carellly. The most prudent approach in such cases to chose to detect the gas thatis considered the highest risk for the area under examination.The basis of the highest risk should account for:(1.) The gas with the widest flammablerange of the gasses that are present.(2.) The largest percent volume of a particular gas in the stream.(3.) The gas with the lowest ignition temperature.(4.) The gas with the highest vapor density.(5.) Spark energy to necessary for ignition (Le.,Group A, B, C or D).Since no specific property can define the entire risk for a particular commodity, the consequence for eachmaterial should be examinedwhen decidingupon the optimum gas detectionphilosophyfor a particular area.The following table is a brief comparison of the characteristics of the most common gases that may beencounteredin a hydrocarbonfacility.Material LEL/UEL % AIT (OC) VD GroupHydrogen 4.0 to 75.6 500 0.07 BEthane 3.0to 15.5 472 1.04 DMethane 5.0 to 15.0 537 0.55 DPropane 2.0 to 9.5 450 1.56 DButane 1.5to 8.5 287 2.01 DPentane 1.4to 8.0 260 2.48 DHexane 1.7to 7.4 225 2.97 DHeptane 1.1to 6.7 204 3.45 DTable 21Comparison of Common Hydrocarbon Vapor HazardsBy an analysis of the composition of gas or liquid stream and the arrangement or conditionsat the particularfacility one can prudently arrive at the optimum detection philosophy.
    • 186 Handbook of Fire and Explosion ProtectionApplicationAssuming the main objective of combustible gas detection is to warn of the formation of vaporcloudsthat if ignited would produce h a d l explosionaftereffects, then the threshold of 5.5 meters(18 ft.), as proposed by the Christian Michelsen Institute, Norway, should be the limiting case forthe spacing of combustible gas detectors. A three dimensionaltriangular spatial arrangement of 5meters (16.4 e.), 10Y0for adjustment and contingency factor, would provide a satisfactoryarrangement for area gas detection in confined areas. The first step is to define all possible leakagesources and then narrow the possibilitiesby selectingequipment that has the highest probability ofleakage. This can be accomplished by first refemng to the electrical hazardous area classificationdrawings for each facility. Equipment that handles low flash point materials should be given thehighest priority, with materials of a high vapor density of most concern, since these vapors areeasiest to collect and less likelyto disperse.Pump and compressor seal areas are by far the most common areas where vapor releases mayoccur. This is followed by instrumentationsources, valve seals, gaskets and sample points and themost rare but usually catastrophicerosion and corrosion failures of process piping.The nature of the release needs to be analyzedto determinethe path of the vapors, i.e., high or low.This will determine whether the detectors need to be sited above or below the risk. Detectorsshould also be sited with due regard to the normal natural air flow patterns. High and low pointswhere gas may settle should also be considered.Enclosed spaces that may subject to a gas leak that have intrinsic production valve or are highcapital items should be provided with gas detection. Typically these locations are compressor andmetering houses.As a preventive measure, gas detectors are normally placed at the air intakes of manned facilities,critical switchgear shelters and internal combustion engines subject to vapor exposures, i.e., nearprocess areas handling gases and vapor. The facility air intakes themselves should be positioned toprevent the intake of combustiblegases fiom these areas, even during accident scenarios.Normally point source detectors are positioned with their detector head downwards for bettercapture of the ambient gases.No gas detector should be located where it would be constantly affected by ambient conditionssuch as surface drainage runoff, sand, ice, or snow accumulation. Special consideration should begiven near open sewer grates and oily water drain hnnels were frequent alarmsmay appear due tovapor emissions.Where overall large area coverage is necessary or desired , such as the monitoring of facilityborders, pump alleys, entire onshore units or offshore modules, "line of sight" IR beam detectorsare used, otherwise "point source", catalytic detectors are provided. The point source locationsshould be at least on either side of the leak point, which at least one of the detectors downstreamventilation pattern.
    • Fire and Gas Detection and Alarm Systems 187Typical Hydrocarbon Facility ApplicationsThe following locations are typical applications where combustible gas detection devices are provided orshouldbe consideredin the hydrocarbonindustry:All hydrocarbon process areas containing materials with gaseous materials that are notadequatelyventilated (i.e., would not achieve a minimum of six air changes per hour orwould allow the build up of flammable gas due to noncirculating air space). Typicallyapplications include compressor enclosures, process modules in offshore platforms andenclosed arctic facilities.For enclosed areas, they can be considered adequately ventilated if they.meet one of thefollowing. Where artificial mechanisms are employed for ventilation assistance highreliability must be assured.(1) The ventilation rate provided is at least four times the ventilation rate required todilute the anticipated hgitive emissions to below 25 percent LEL as determined bydetailed calculationsfor the enclosed area.(2) The enclosed area is provided with six air changes per hour by artificial (mechanical)means.(3) If natura1 ventilation is used, 12 air changes per hour are obtained throughout theenclosed area.(4) The area is not defined as "enclosed" per the definition of API RP 500, Section4.6.2.2.4.All gas compressors should be provided with point gas detection at sealage points andespeciallyif enclosed in a packaged module - interior area detection and at the air intakeand exhaust of the driver and compressor.Pumps handling high vapor pressure hydrocarbon liquids (detector sited close to thepump seals).At all intakes for fresh air or W A C systems to buildings in an electrically classified areaaccording to the National Electrical Code (NEC) or subject to ingestion of combustiblevapors. Especially if they are considered inhabited, critical or of a high value. Typicallycontrol rooms, critical electrical switchgear, or main process area power sources areprovidedwith gas detection.At all critical internal combustion prime movers subject to the possible ingestion ofcombustiblevapors.In all battery or U P S rooms in which hydrogen vapors may be vented or released frombattery charging operations.Entrances and air intakes to the accommodation module or continuously mannedenclosed locationslocated offshore.Drilling areas such as the mud room, drilling platform, and areas around enclosedwellheads.Possible hydrocarbonleaks points at process cooling towers.Sensitive (critical or high value) processing areas where immediate activation of incidentand vapor mitigation mechanisms are vital to prevent the occurrence of a vapor cloud
    • 188 Handbook of Fire and Explosion Protectionexplosion.0 Enclosed water treating facilities that can release entrained combustible gases or vapors,especially a concern at produced water treating operations.0 Monitoringthe purge gas from cold boxes and double walled insulated cryogenic storagetanks.0 Process locations containing large volumes or high pressure hydrocarbon gases whichmight be susceptibleto extremeeffectsof erosion or corrosion from the process activity.CatalyticDetectorsDescriptionThe catalytic gas detector was originally developed in 1958for the mining industry. It has becomethe standard means of detection worldwide in virtually all oil and gas operations. It is also usedextensivelyin coal extraction and the chemical process industry.Catalytic gas detection is based on the principal that oxidation of a combustible gas in air ispromoted at the surface of a heated catalyst such as a precious metal. The oxidation reactionresults in the generation of heat that provides a direct measure of the concentration of the gas thathas been reacted. The sensing element embodying the catalyst is a small bead that is supportedwith the sensor.They are sensitive to all flammable gases, and they give approximately the same response to thepresence of the lower explosive limit (LEL) concentrations of all the common hydrocarbon gasesand vapors. However it should be remembered that gas detectors do not respond equally todifferent combustible gases. The milli-volt signal output of a typical catalytic detector for hexaneor xylene is roughly one half the signal output for methane.They have two disadvantages. First they are only capable of sensing a flammable gas at a singlepoint. If the position of the sensor is unfavorable in relation to the origin of the flammable gasrelease and the pattern of air flow and ventilation in the hazardous area, then the gas detector willnot detect a dangerousrelease of gas until it is too late to take effective action. Generallypoint gasdetectors can only provide adequate protection at a facilityif deployed in large numbers.Secondly small quantities of airborne pollutants may poison the catalyst in the detector. Thisseverely reduces its sensitivity. The detector becomes less reliable and often makes duplication,voting logic and frequent maintenancenecessary.The following substanceshave been known to poison catalytic gas sensors:...Tetraethyllead (at present being phased out as ;I gasoline additive in most count1ics).Sulfir compounds(particularly hydrogen sulfidein oil production refiningoperations).Phosphate esters ( used in corrosion inhibitorsin lubricatingoils and hydraulicfluids).Carbon tetrachloride and trichlorelhylenc (found in degreasing agentsand diy cleaningfluids).Flame inhibitorsin plastic materials.Thermal decomposition products of neoprene and PVC plastics.Glycols.Dirt or fiberparticles
    • Fire and Gas Detection and Alarm Systems 189Siliconvapors.Infra-Red (IR) Beam Gas DetectionConventional gas detectors are only capable of detecting gas at point locations. If the position ofthe detector is unfavorable in relation to the origin of a gas release, it may not detect the gas releasebefore a dangerous accumulation of gas has occurred. To provide improved detection capability,an infra-red beam gas detector has been developed which is capable of detecting gas anywherealong an open path of several hundred meters in length. These devices have been availableto theindustry for approximately ten years and their quality has improved as field experiencewas gained.The sensor is based on the differentialabsorptiontechniqueand has a reasonably even response to arange of light hydrocarbons. A microprocessor controller is commonly used for signal processingthat produces the alarm and trouble indications.Many frequency lines of infared radiation are absorbed by hydrocarbon gases. By selection of aparticular frequency, a detector can be made which is either specific to a particular gas or if thefrequencyis commonto severalgases, a particulargroup of gases may be detected.Application (IR Beam)IR beams are typically provided as a special gas detection applications. They offer a direct viewand surveillanceover a large area rather than a point source origination of gas. The most frequentuse of these is verifymg whether a gas release would be carried offsite from the facility. Otherpossible applicationswould be overall monitoringin area of several possible leak sources but withina line of sight arrangement such as a pump alley or an offshoremodule.Pump Alleys - Where a number of pumps are used, they are usually arranged in parallel toeach other facilitatingthe use of an IR beam over the line of pumps.Perimeter Monitoring - The perimeter of a hazardous area or process unit can beeffectively monitored for vapor release by IR beam arrangements on the edges.Theoretically they could be used to warn of open air combustible vapors approachingignition sources in a reverse role, e.g., to the flarefrom the process area.Boundary and Offsite - Especially critical for locations near to public exposures, an IRbeam detector can be used to signal if vapors or gases may be released to offsite locations.Alarm SettingTo achieve early and reliable warnings of leakages, the sensitivity of detectors should be at thehighest level commensuratewith the level of false alarm rates.Alarm panels are normally set to give two levels of warning: a first alarm at low level and a secondalarm at high level. Typical practice is to set these at 25% and 50% of the LEL, for the low and"high" levels respectively. A recent trend is to provide lower levels such as 10 and 25% LEL.Although there is no statutory requirement for the exact levels of alarms settings, NFPA 15,Appendix A, section A-8-2, suggest levels of 10-20% of the LEL as the first alarm point and 25-50% LEL as the second alarm point at which executiveaction should occur. AlternativelyAPI RP14C, SectionC 1.4(b), suggest settingsno greater than 25 and 60% of the LEL.From a safety viewpoint the lower the alarm levels are set the better. However the lower the levelof alarm the greater the possibility of false alarms and disruption to operations. On the other hand
    • 190 Handbook of Fire and Explosion Protectionsome practical experiencehas shown that with the lower levels of sensitivity,more minor leakagesare at first detected. As these leakage sources are corrected, less and less real alarms are receivedthan if the gas detectors were set at the higher LEL levels (Le., 25 and 60% LEL). It should alsobe realized that for immediate leaks the concentration of the vapor in an area will immediatelyrisedirectly into the LEL range (or past it) so the relative settings below the LEL may not besignificant. The most important feature is to have detection capability for the gases that may beencounteredat the installation.In general practice, the gas detection alarm set points are the settings recommended by themanufacturer of the equipment or by requirementsof an operating company to effect an acceptablecompromise on any given field of operation. The lower the set points the higher the sensitivitytopossible leakage emissions.CalibrationOperation of detectors with their associated alarm panels should be checked and calibrated afterinstallation. Detector performance can be impaired in a hostile environment by blockages to thedetector (i.e., ice, salt crystals, wind blown particles, water or even fire fighting foam, or byinhibition of the catalysts by airborne contaminants such as compounds of silicon, phosphorus,chlorine or lead. It is essential that detectors and alarm panels be checked and re-calibrated on aroutine basis.It is also possible for detectors to be calibratedusing one gas (e.g., methane) for use thereafter indetecting a second gas (e.g., propane or butane) provided the relative sensitivityof the detector toeach of the gases is known. A procedure for calibration of the detector for a different gas than thatwhich is being used is normally availablefrom the manufacturerof the detector.Detectors should be calibrated after installation as recommended by the manufacture, typically thisis every 90 days. However if experience indicatesthat the detectors are either in calibration or outof calibrationthe period of re-examination shouldbe lengthen or shorten accordingly.Hazardous Area Classification RatingSince detectors are by definition exposed to combustible gases they should be rated for electricallyclassified areas, such as Class I, Division I or 2, the specificgas groups (normally groups C and D),and temperature ratings. It shouldbe noted the UL presently does not specificallytest combustiblegas detector sensor heads for use in classified areas, although they do tests enclosures for controland data acquisition circuits. Several other international standards do evaluate combustible gasdetectors for use in classified areas (e.g., BS 6020).Fire and Gas Detection Control PanelsStand alone fire or gas detection and alarm panels are normally provided in the main control facilityfor the installation. Recent trends also incorporate the transmittal of fire and gas alarms throughthe DCS into the main process alarm real time control panel. When alarm panels are located withina protected building, they should be located for easy access for emergency response personnel andproximityto manual electrical power shut off facilities.
    • Fire and Gas Detection and Alarm Systems 191GraphicAnnunciationAlarms should be displayed on a conventional dedicated window annuciator panel or if controlroom based on a dedicated CRT display for fire and gas detection systems. Each detector locationshould be highlighted with indications for trouble, alarm low, and alarm high. Where annuciatorpanel window alarms the alarm indication lights should be provided with specific labels indicatingthe exact alarm locations.Power SuppliesCommercially available combustible gas detection systems generally use 24 VDC as the powersupply for field devices. 24 VDC is inherently safer and corresponds the voltages increasing usedby most instrument systems in process areas. A main supply voltage converter can be used to stepdown or convert from AC to DC power supplies.Emergency Backup PowerThe power for combustible gas detection system should be supplied from the facilitys UPS or ifthis is unavailable normal power with a reliable battery backup source of a minimum of 30 minuteduration.Time DelayWhere instantaneous reaction is not imperative, susceptibility to false alarms can be reduced byrequiring the fire signal to be present for a predetermined period of time. However, the time delayreduces the advantages of high speed early detection. In most applications, the tradeoffs betweenfalse alarmsand the damage incurred in the first few secondsof a fire have been inconsequential.Voting LogicActivation of a single fire or gas detectors should not be trusted to provide executive action forhydrocarbon facilities. The present technology suggests they are too vulnerable to false alarms.They should also be arranged for a voting logic for alarms and executive actions. Voting is therequirement for more than one sensor to detect a fire or gas presence before the confirmation of thealarm. This method would prevent a false alarm cause by a single spurious source or by electronicfailure of a single component. Usually a one out or two or a two out of three (2003) votingnetwork of detectors is used to offer a confirmed alarm reception.Cross ZoningThe use of two separate electrical or mechanical zones of detectors, both of which must beactuated before the confirmation of a fire or gas detection. For example, the detectors in one zonecould all be placed on the north side of a protected area, and positioned to view the protected arealooking south, while the detectors in the second zone would be located on the south side andpositioned to view the northern area. Requiringboth zones to be actuated reduces the probabilityof a false alarm activated by a false alarm source such as welding operations, from either the northor the south outside the protected area. However this method is not effective if the zone facingaway from the source, sees the radiation. Another method of cross zoning is to have one set ofdetectors cover the area to be protected and another set located to face away from the protectedarea to intercept external sources of nuisance UV. If welding or lighting should occur outside theprotected area, activation of the alarm for the protected area would be inhibited by second
    • 192 Handbook of Fire and Explosion Protectiondetectionactivation. Althoughthis method is quite effectivea fire outsidethe protected area wouldinhibitthe activation for the protected area.ExecutiveActionOnce an alarm has been confirmed, actions should be taken to prevent or reduce the impact fromthe event. Depending on the priority of the alarms the following actions should be taken at thepoint of activation:12.3.4.5.6.7.8.The facility evacuation and warning alarms should be activated, and personnel evacuationor muster should commence.Activate fixed fire extinguishing systems or vapor dispersion mechanisms (i.e., watersprays).Start fire water and foam solution (if applicable) pumps.Close HVAC fire and smoke dampers. Close fire doors.Shutdown HVAC fans (unless arranged for automatic smoke control and management).Activate the process ESD systems (i.e., Isolation, Power Shutdowns, Blowdown andDepressurization).On confiied gas detection sources of ignition such as welding or small power circuitsshould be immediately shut down in the affected area (immediately shut down is appliedto equipment not rated for use where hazardous gases are present).Messages should be sent alerting outside agencies of the event and current situation.Circuit SupervisionThe detection and alarm circuits of fire and gas detection systems should be continuouslysupervisedto determineifthe systemis operable. Normal mechanismsprovide for a limited currentflow through the circuits for normal operation. During alarm conditions current flow is increasedwhile during failure modes the current level is nonexistence. By measuring levels at a control pointthe health of the circuit or monitoring devices can be continuously determined. End-of-line-resistors (EOLR) are commonlyprovided in each circuit to provide supervisorysignal levels to thecontrol location.
    • Fire and Gas Detection and Alarm Systems 193Table 22Comparison of Gas Detection Systems
    • 194 Handbook of Fire and Explosion ProtectionBibliographyFire Detection1.2.3.4.5.6.7.BHR Group Ltd, Managementand Engineeringof Fire Safetvand Loss Prevention. Onshore and Offshore,ElsevierApplied Science,London, U.K., 1991.Bishop, D. N., Electrical Svstems for Oil and Gas Production Facilities, Second Edition, Instrument Society ofAmerica (ISA), Durham,NC, 1992.Coon, W., Fire Protection Design. Criteria. ODtions. Selection,R. S. Means, Kingston, MA. 1991.Institute of Electrical and Electronic Engineers. Inc. (IEEE), IEEE 979-84. Guide to Substation Fire Protection,IEEE,New York,NY, 1988.National Fire Protection Association(NFPA),NFPA 72. National Fire Alarm Code (NFAC), NFPA, Quincy, MA,1994.NationalFire ProtectionAssociation(NFPA),NFPA 90A. Heating andVentilationSystems,NFPA, Quincy,MA,National Fire Protection Association (NFPA), NFPA 850, Fire Protection for Electric Generating Plants, NFPA,Quincy,MA, 1992.Gas Detection1.2.3.4.5.6.7.8.9.1011American Petroleum Institute (API), API RP 14C. Recommended Practice for Analysis. Design. Installation andTesting of Basic SurfaceSafetv Svstems for OffshoreProduction Platforms, Fourth Edition, API Washington D.C.1986.American Petroleum Institute (API), API Publication2031. CombustibleGas Detector Svstems and Environmentaland ODerational FactorsInfluencingTheir Performance,First Edition, API Washington D.C., 1991.BHR Group Ltd., Fire Safetv Engineering, "Modem Methods of Designing Fire and Gas Detection Systems",BHRA, Cranfield, U.K., 1989.British StandardsInstitution(BSI), BS 6020. Part 1.4. and 5,Instrumentsfor the Detection of CombustibleGases,Parts I,4, & 5.,BSI, London,U.K., 1981.British Standards Institution, (BSI), British Standard 6959, Selection Installation, Maintenance and Use ofApparatusfor the Detection and Measurementof CombustibleGases, BSI, London,U.K., 1988.Canadian StandardsAssociation(CSA), StandardC22.2 No. 152 M1984. CombustibleGas Detection Instruments,CSA, Rexdale,Ontario,Canada, 1984.Department of Energy (U.K.), Guidance on Fire Fightin? Equipment. Section 4. Flammable Gas Detection andMeasuring Eaubment (Regulation6) Her Majesty Stationary Office(HMSO) London,U.K., 1977.FactoryMutual (FM), FM ClassNo. 6310-6330,CombustibleGas DetectionInstruments,Instrument Society of America (ISA), ISA-S12.13, Part I-Performance Reauirements. CombustibleGas Detectors,ISA, Research TrianglePark,NC, 1986.Instrument Society of America (ISA), RP 12.13, Part 11-1987 Installation. Operation. and Maintenance ofCombustibleGas Detection Instruments,ISA, Research,TrianglePark, NC, 1987.Health and Safety Executive (HSE), Guidance Note CSl, Industrial Use of Flammable Gas Detectors, HMSO,London,U.K., 1987.
    • Fire and Gas Detection and Alarm Systems 19512. Lloyds Register of Shipping, Offshore Gas Detector Siting Citerion, Investigation of Detector Spacing, HSE,Sheffield, U.K., 1994.13. National Fire Protection Association (NFPA), NFPA 15. Standard for Water Sprays Fixed Systems for FireProtection, AppendixA, NFPA, Quincy, MA, 1990.14. National Fire Protection Association(NFPA),NFPA 30, Flammable and CombustibleLiquids Code, Section A-8-4NFPA, Quincy, MA, 1990.15. Schaeffer, M. J., "The Use of Combustible Detectors in Protecting Facilities from Flammable Hazards", ISATransactions,Vol. 20, No. 2, InstrumentSociety of America, Research Triangle Park, NJ, 198116. United States Coast Guard (USCG), 46 CFR 154.1345and 1350. USCG Regulations for Gas Detection Systems onSelf-propelledVessels C&g Bulk Liquefied Gases, USGPO,Washington, D.C.
    • Chapter 18EvacuationThe primary safety feature for any installation should be its evacuation mechanisms for its personnel. Ifpersonnel cannot escape from an incident they may be affected from it. Personnelmust first be aware that anincident has occurred, and then have an availablemeans to escape or evacuate from it. An adequate meansof escape should be provided from all buildings, process areas, elevated structures, and offshoreinstallations.Provision of an adequate means of escape is listed in most national safety regulations for the industry as awhole as well as local building code ordinances.The population density for any process area is usually quite low. Initial glances at an operating unit wouldindicate that the facility is unmanned. The highest concentrationsof personnel are typically found in controlrooms, transportation mechanisms, drilling or maintenance activities and accommodations. These locationsoffer the highest probability of large life loss within the petroleum and chemical industries. Historicalevidence of hydrocarbon and chemical facilities demonstrate that for the majority of incidents, a relativelylow level of fatalities occur. When a large life loss does occur, it is usually due to the congregation ofpersonnel in a single area without the abilityto escape, or to avoid or protect themselves from the impendinghazard.When and emergency egress route is provided it should be protected from the effects of fire and smoke orthe personnel equipped with a means to protect themselves when transversing it. It has been shown thatpeople are reluctant to enter into smokethat reduces visibilityto less than 10 meters (33 ft.), even when it isnot hazardous to do so. Where the effects of fire, smoke and explosions are likely to preclude the use of anemergencyegress route, it is the same as not providing an egress route.Alarms and NotificationsAlarms should be able to be noticed at all areas of the facility, whether manned or considered technicallyunmanned. The basic theory for deterrkning the number andlocation of audible alarm devices is that strategically placed and distributed deviceswill provide an efficient distributed level of sound, than one large centrally locateddevice.As a rule of thumb, the unobstructed sound radius of a typical siren, horn or bell is about 61 meters (200 ft.)If an area is segregated by walls, equipment or structures it should be provided with own audible source ofalarm. If unobstructed areas from 61 to 305 meters (200 to 1,000 ft,) are encountered, a large plant widesiren or horn may be suitablein some cases, depending on background noise and orientationof the device(s).196
    • Evacuation 197Where several different alarm signals are necessary they should be easily distinguishable from one anotherfor the purposes they are intending to provide, i.e., fire alarm, evacuation, etc. Different signals can rangefrom horns, sirens, klaxons, buzzers, etc., in addition the intensity, pitch, warbling, etc., can also be varied.Electronic programmable controllers are available that can easily be programmed to produce the differentemergencysounds.Fire and evacuation alarms should normally sound between 85 and 100 dB, with a maximum of 120 dB.They should be in the range of 200 to 5000 Hz,preferably between 500 to 1500 Hz. Where ambient noiselevels are higher, flashingbeacons should be used. Beacon colors should be consistent with the alarm colorcodingphilosophyadopted for the entire facility.Panel alarms and indications should not be mounted lower than approximately 0.76 meters (2 6" ft,) orhigher than 1.83 meters (6 0" ft.). Outside these limits the alarms alarm indicators are less noticeable andawkward for maintenancepersonnel activities.Alarm InitiationAlarms should be initialed by the local or main control facility for the location. Manual activation meansshould be provided for all emergency, fire, and toxic vapor alarm signals. Activation of fire suppressionsystems by automatic means should also indicate a facility alarm. Most fire and gas detection systems arealso set to automatically activate alarms after contimation and set points have been reached. Manualactivation of field or plant alarm stations should activatethe process or facility alarms.Alarm activation points should be clearly highlight and marked. Their operation should be simple, direct andconsistent throughout the facility or company, especiallyif personnel may be transferred or rotated fromone locationto another.Evacuation RoutesEvacuation routes are of prime importance for the safety of plant workers during an emergency. Theyshould contain the followingfeatures:Two evacuation routes, situated as far apart as practical, should be provided from all hydrocarbonprocesses or normally occupied work areas. Areas that are considered low hazard (nohydrocarbons,chemicalsor other flammablesare in the immediatearea) may be allowed one escaperoute. The exception to tlus is rooms located on an offshore installation in proximity tohydrocarbon processes.Should not be affected by the effects of fire or explosions (i.e., blast overpressure, heat, toxicvapors and smoke).Evacuation routes should be generally straight and direct to points of safety or embarkationA minimum width of 1.O meter (39 inches) should be maintained on all main evacuationroutes.Passage from one level to another level should be by stairways, where impractical, vertical laddersare normally provided. Preferably stairwaysand ladders should be located on the exterior faces ofstructures that face away from the plant. Stairways designs that require evacuation to be throughother process equipment or areas should be avoided. On fired units where the towers may be verycloseto the furnace, providing an additionalwalkway bridge link to an adjacent tower or structuremay be more cost effective if the towers need to be climbed frequently.The evacuation route should be simple to locate and negotiable even in emergency lighting con-ditions. If the route is not obvious, adequate demarcation (i.e., signs and arrows) should be
    • 198 Handbook of Fire and Explosion Protectionprovided of the route and exit pointsAn emergencymuster location is provided. This affordsa meansto account for personnel andissue hrther evacuation instructions.0 Egress arrangementsshould not be exposed to drainageprovisions provided at a facility.Emergency Doors, Exits, and Escape HatchesExit routes and doors from all facilities should be provided according to the requirements of NFPA 101.The minimum width of all exit routes should not be less than a standardized width, 1.0 meter (39 inches)being commonly adopted.Where low occupancy rooms areprovided in offshore facilities near process areas,a secondary emergency escape hatch is provided as an alternative means of escape in addition to the normalmeans of egress.The design of stairways of two or more risers is critical for safe evacuation. Stair widths, rise and run arearranged and balanced for an effective and orderly evacuation. Studies of people travelling on stairwayshave shown that the probabilty of the greatest hazard is the user. Inattention has been shown to be thesingle most factor producing the greatest misteps, accidentsor injuries. Life safety codes for the installationof stairs place limitations on the use of winding, circular and spiral stairways to ensure adequate egressroutes are provided €or emergencyperiods.Incidental combustible liquid storage (e.g., lube oil reservoirs, fuel day tanks, etc.) should normally not beinstalled within 1.8meters (6 e.)of an emergencyexit route, especially if it is the only means of egress fioman enclosure.Marking and IdentificationWhere practical routes between exit points should be defined by lines painted on thefloor or facility pavement in reflective oil resistant paint. All exit doors should beplainly marked. Direction arrows and wordings should be positioned along escaperoutes where necessaryto guide personnel to exit points or the perimeter of the facility.The arrows should be preferably selfilluminating(Le., luminescent).EmergencyIlluminationA minimum of 1.0 foot candles of illumination should be provided to the centerline of evacuation routes.This illumination should be available for the evacuation routes for the duration of the expected emergencyevacuationperiod, but not less than 90 minutes.Offshore EvacuationThe methods of evacuation offshore are dependent on the ambient environmental conditions that maydevelop in the area and relative distance to the mainland. Regions that experience colder ambientconditions inhibit immersion opportunities and remote offshore locations retard onshore assistancecapabilities. The preferred and most expedient evacuation means from an offshore installation is byhelicopter. Because of the nature of fire and explosions to affect the vertical atmosphere surrounding anoffshoreinstallation,helicopterevacuationmeans cannot always be accommodatedand should be consideredof low probability where the accommodation quarters are located on the same structure as a hydrocarbonprocess.
    • Evacuation 199North/South Atlantic and North/South Pacific EnvironmentsAreas of the North and South Atlantic, and North and South Pacific present continual extreme andhostile ambient conditions that make survival exposed to such conditions a very limited probabilitywith adequate protection measures. In these locationsthe probabilityof survival is increased with theprovision of a fixed safe refuge rather than the provision of an immediate means of escape. Foroffshore facilities historical evidence indicates that both helicopter and lifeboat mechanism may beunavailable in some catastrophic incidents. Remote onshore facilities may also experience severewinter conditionsthat also render this philosophyapplicable.Temperate and Tropic EnvironmentsLess severe locations, where supplemental exposure protection for the normal ambient conditions isnot necessary. These location however may contain other threats that need to be accounted for, suchas, sharks, hurricanes, volcanic and tsunami activity.Means of EgressIn general at least two means of accesses should be provided from all "facility evacuation musterareas" to the sea . These means are usually selected fromthe following:i. Stairwayor ladder.ii. Lifeboat and davit launched life rafts.iii. Abseiling devices.iv. Scramblenets or knotted ropes.v. Slidetube.Where other semi-occupied areas exist, they are usually provided sufficient and properly arrangedevacuation meansto the sea by way of two remote locations. These includethe following:i. Abseilingdevicesii. Scramblenets or knotted ropesiii. Ladder or stairway.6 . 2Flotation Assistnnce,, >?4flrTwo methods of flotation assistance in the open sea are usually provided forthe number of personnel on board @OB) the installation. They may consist ofthe following:1i! /.i.....~. ____-2i. Lifejacket or inflatablesurvivalsuit. ..,ii. Lifeboatsand life rafts.iii. Flotation device(life buoy or ring)A prime considerationin the provision of lifeboats for offshoreinstallationsis that they can be readilymaneuvered away from the structure of the installation. Recent trends have been for the orientationof lifeboats to point outwards so that egress away from the structure is improved and the fear ofbeing swept into the platform by the waves and current is lessened. Positioning in an outwardorientationalso improvesthe evacuationtime for the boat to "get away" fromthe incident.
    • 200 Handbook of Fire and Explosion ProtectionYES-APPROX. CUM.TIME TIMEIS MUSTER AREA OR ACCESSAFFECTED BY INCIDENT?ACTIVITYIALARM & NOTIFICATIONISEEKREFUGEOREVACUATEIIII0.05 , 0.10 I1 IvDON LIFEJACKETI 0.05 0.15 I1 ICHECK ROSTERP I tSTANDYBY ORHELICOPTEREVACUATIONII I I!YESCONDITIONSURVIVABLE?SEEK OTHER PROTECTED SHELTERI OR HELICOPTER EVAC.* WCCEOFFSHORE EVACUATIONFLOWCHARTFIGURE 10
    • Evacuation 201Bibliography1.2.3.4.5.6.7.8.9.10.11.American Society of Testing Materials (ASTM), F 1166. Standard Practice for Human Enheering Design forMarineSystems.Eauipment and Facilities,ASTM, Philadelphia,PA, 1988.Acoustical Societyof America (ASA), S3.41, Audible EmergencyEvacuation Signal, (ASA 96), ASA, New York,NY, 1990.British StandardsInstitute (BSI), BS 5395: Part 3: 1985. Stairs ladders and walkways, Part 3 Code of Practice forthe design of industrialtypestairs, permanent ladders and walkways,BSI, London,UK. 1985Department of Energy (U.K.),OffshoreInstallations: Guidance on Life Saving Aodiances, HMSO, London, U.K.,1978.Department of Energy (U.K.), SI 1977 No. 486. Offshore Installations. The Offshore Installations Life SavingAppliancesRegulations, 1978, HMSO, London,U.K., 1978.International Maritime Organization(IMO), International Convention for the Safety of Life at Sea, IMO, London,U.K., 1986.International Organizationfor Standardization(ISO), IS0 7731:1986 Danger Signals for Work Places - AuditoryDanger Signals,ISO, Geneva, Switzerland, 1986.International Organization for Standardization(ISO), IS0 8201:1987 Acoustics - Audible Emergencv Evacuation&gal, ISO, Geneva, Switzerland, 1987.National Fire Protection Association(NFPA),NFPA 101. Life SafetvCode,NFPA, Quincy,MA, 1994.Occupational Safety and Health Administration (OSHA), 29 CFR 1910.037, U.S. Department of Labor,Washington,D.C.Occupational Safety and Health Administration (OSHA), 29 CFR 1910.165, U.S. Department of Labor,Washington,D.C.
    • Chapter 19Methods of Fire SuppressionThe objectives of fire suppression systems are to provide cooling, control the fire (i.e., prevent it fromspreading) and provide extinguishment of the fire incident. A variety of fire suppression methods areavailableto protect a facility. Both portable and fixed systems can be used. The effectiveness of all fireextinguishingmeasures can be determined by the rate of flow of the extinguishing agent and the method orarrangementsof delivery.Before the need of fire protection measures is defined, the type of hydrocarbon fire exposure should beidentified. By determining the type of fire expected, the adequacy of the fire protection measures based onthe philosophyof protection for the facility, can be assessed. The easiest method to arrive at the protectionrequirements is to identi@the materials and pressures involved in the process. Once this is accomplished,the most appropriate fire control or suppressionmechanism can be identified from NFPA 325M. Tables 3and 4 provides examples of a tabular format that can be used to document the fire control mechanisms thathave been chosen.Portable Fire ExtinguishersHistorical evidence indicatesthat portable (i.e., manually manipulated an operated) fire extinguishers are themost common method of extinguishinghydrocarbon fires for the petroleum industry in the incipient stage.Human surveillancecombinedwith the abilityto quicklyand effectivelyreact to the beginning of an incipientfire have prevented countless petroleum incidents from developing into large scale disasters. The objectivefor providing portable fire extinguishersis to have an available supply of plentihl extinguishers that can beeasily used in the early stages of a fire growth. When these extinguishing means are exhausted or theincipient fire has grown to the point of uncontrollabilityby manual methods, fixed fire suppression systemsand process incident control systems should be activated (e.g., ESD activation). Only personnel trained intheir use should be expected to use a portable fire extinguisher.202
    • Methods of Fire Suppression 203A portable Fire Extinguisher is a device used to put out fires of limited size. Portable extinguishers areclassified by expected application on a specific type of fire (i.e., A, B, C, or D) and the expected area ofsuppression.The four types of fires are grouped according to the type of material that is burning. Class Afires include those in which ordinary combustibles such as wood, cloth, and paper are burning. CIass B firesare those in which flammable liquids, oils, and grease are burning. Class C fires are those involving liveelectrical equipment. Class D fires involve combustible metals such as magnesium, potassium, and sodium.The numerical rating on the fire extinguisher is a relative rating number. It is assigned by recognized testinglaboratoriesfor the amount of averagefire area that can be extinguishedaccordingto methods establishedby"A. The rating does not equate to the amount in square feet that can be expected to be extinguishedbyan individual.The classes of portable fire extinguishers manufactured and used in the USA are defined below. Othercountrieshave similarclassifications(although these may not be exactly the same).Extinguishersfor Class A FiresClass A fire extinguishers are usually water based. Water provides a heat-absorbing (cooling) effecton the burning material to extinguishthe fire. Pressurizedwater extinguishersuse air under pressureto expel the water.Extinguishersfor ClassB FiresClass B fires are put out by excluding air, by slowing down the release of flammable vapors, or byinterrupting the chain reaction of the combustion. Three types of extinguishing agents carbondioxide, dry chemical, and foamwaterare used for fires involvingflammableliquids, greases, and oils.Carbon dioxide is a compressed gas agent that prevents combustion by displacing the oxygen in theair surrounding the fire. The two types of dry chemical extinguishers include one that containsordinary sodium or potassium bicarbonate, urea potassium bicarbonate, and potassium chloride baseagents. The second, multipurposetype contains an ammonium phosphate base. The multipurposeextinguisher can be used on class A, B, and C fires. Most dry chemical extinguishers use storedpressure to discharge the agent, and the fire is extinguished mainly by the interruption of thecombustion chain reaction, Foam extinguishersuse an aqueous film forming foam (AFFF) agent thatexpels a layer of foam when it is discharged through a nozzle. It acts as a barrier to exclude oxygenfiom the fire.Extinguishersfor Class C FiresThe extinguishing agent in a class C fire extinguisher must be electrically non-conductive. Bothcarbon dioxide and dry chemicals can be used in electrical fires. An advantage of carbon dioxide isthat it leaves no residue after the fire is extinguished. When electrical equipment is not energized,extinguishersfor class A or B fires may be used.
    • 204 Handbook of Fire and Explosion ProtectionExtinguishersfor Class D FiresA heat-absorbing extinguishing medium is needed for fires in combustible metals. Also, theextinguishingmedium must not react with the burning metal. The extinguishingagents, known as drypowders, cover the burning metal and provide a smotheringblanket.The extinguisher label gives operating instructions and identifies the class, or classes, of fire on which theextinguisher may be used safely. Approved extinguishers also carry the labels of the laboratories at whichthey were tested.Portable fire extinguishers should be positioned in all hydrocarbon processing areas so that the traveldistance to any extinguisher is 15 meters (50 ft.) or less. They are generally sited on the main walkways orexits from an area, near the high hazard itself and near other emergency devices. They are mounted atapproximatelyone meter fiom the walking surfacewith red background highlighting.Water Suppression SystemsWater is the most useful and vital fire suppressionmedium, whether used for fixed systems or manual firefighting efforts for petroleum facilities. It is relatively inexpensiveand normally plentiful. It has enormousheat absorption properties. Approximately 3.8 liters (1.0 gal.) of water absorbs about 1,512 k cal (6,000Btu), when vaporized to steam. Steam created by water evaporation expands to about 17,000 times itsvolume in open atmospheres, thereby limiting combustion processes by displacing oxygen in the area.When water is combined with other additives, it can control and extinguish most petroleum fires. A watersuppression system consists of a supply source, distribution system, and the end using equipment such asfixed spray systems, monitors, hose reels and hydrants. The objective of water suppression systems is toprovide exposure cooling, fire control, suppression of fire incidents and may assist in the dispersion offlammableor toxic vapors.When water suppressionsystems are provided, due concern should be made for the disposal of the releasedwater. Of primary importance are the capacity and location of surface drainage systems. Fire water usageusually places greater demands on a facility gravity sewer system than rainfall or incidental petroleumspillageeffects.Water SuppliesFirewater supply sources can be the city public water main, a dedicated storage tank and pumps, or the mostconvenient lake, river or if an offshoreinstallationthe open sea. Brackish or salt water supplies can be usedif suitable corrosion protection measures are applied to the entire firewater system if it is planned to be usedfor an extended life (i.e., grater than five years). If a short life span of the facility is expected, shortcorrosion resistant materials may be used (i.e., carbon steel, galvanized steel, etc.), provided periodic testingindicates their integrity is still adequate and scaleor corrosion particles do not affect operational efficiency.
    • Methods of Fire Suppression 205Most hydrocarbon facility process areas and high volume storage areas have standardized on a minimumsupply or availabilityof four hours of firewaterfor the WCCE. The performance of risk analysismay revealthe level of fire water protection may be more or less than this requirement. Once a detailed design iscompleted on a facility or if a verification of existing water demands is needed, a simple tabular calculationof firewater requirements can be made. This table can be used to document spray density requirements,duration levels, code requirements and other features. Table 23 provides and example of arrangement todocument such information.Fire PumpsFire protection pumping systems are almost universally required to be according to NFPA 20. Pump sizesdepend on the water delivery requirements to protect the hazard. When fire pumps are designated toprovide fixed fire protection water suppliestwo sources are provided - a main and a backup. The preferreddriver for fire punips at most hydrocarbon facilities,when there is a reliable and non-vulnerablepower grid isavailable, is by an electric motor that receives energy from two different power sources (i.e.,generatorstations). Alternatively, at least one electric and one prime mover standby (diesel, gas or steam engine isprovided) unit is provided. Where the electric power grid is unreliable or fiom a single source, fire pumpspowered by prime movers should be provided.Nowadays the power grids of industrialized countries and commercially availablehigh horsepower electricalmotors are highly reliable, so the need of independent prime mover, as may have been the case severaldecades ago, is not highly demonstrated. The maintenance, failure points, fuel inventories, instrumentationand controls needed for an internal combustion engine versus an electrical motor all demonstrate it is not asa cost effective option as compared to an electrical motor. Of course adequate integrity and reliability ofelectrical motor power sources and infrastructuremust be assured. Where several tire pumps are necessaryit is still good common sense practice to provide a prime mover source to accompany electrical motordrives. Offshore installations are particularly attractive for this option where a prime mover adjacent togenerator provides power for an electrically submersible pump or hydraulic drive unit, thereby eliminatingthe need for long line shaft turbine pumps needing specialized alignments for correct operation. Petroleumoperations in third world locations are generally dependent on their own power generation, so shelfcontained prime mover option for fire pumps are selected to decrease sizing and costs of the productionpower generators.
    • 206HandbookofFireandExplosionProtectionmh)4
    • Methods of Fire Suppression 207To avoid common failure incidents prime and backup fire pumps preferably should not be locatedimmediately next to each other and ideally should be housed at separate locations at the facility. Theyshould feed into the firewater distribution system at points that are as remote as practical from each other.In practical application, except for offshore installations, most small to medium sized facilities contain asingle firewater storage tank, requiring the siting of all firewater pumps close to it. Even in thesecircumstances it may be wise to segregate the main and backup fire pumps from each other with separate tiein points to the firewater distributionloops. This mostly depends on the hazard level of the facility and thedistance of the firewater pump location from the process. Fire water pumps should be located as remotefrom the process area as feasible,preferablyat a higher elevation and in the upwind direction. In a review ofone hundred major petroleum industry fires, the failure of the firewater pumps was a major contributor ofthe ensuinglarge scale destructionof the facilityfor twelve of the incidents.The metallurgy selected for construction of a firewater pump is dependent on the properties of the watersource to be used. For fresh water sources (i.e., public water mains), cast iron is normally adequatealthough bronze internals may be optional. Brackish or sea water utilization will require the use of highlycorrosion resistance materials and possibly coatings. Typically specified metals include alloy bronze,monnel, ni-resistant, or duplex stainless steels sometime combined with a corrosion resistant paint orspecializedcoating.For onshore facilities,water may be supplied from local public water mains, storage tanks, lakes and rivers.In these cases a conventional horizontal pump is used. The preferred design for onshore fire water pumps isa horizontal centrifugal type with a relatively flat performance curve (Le., pressure versus quantity). Thedischargepressure is determined by the minimum residual pressure required at the most remote location ofthe facility flowingits highest practical demand with allowancesadded for pipingfrictionlosses.Where a significant lift is required such as offshore, several options are available such as a shaft driven,hydraulic drive or electrical submersible pump. Shaft driven vertical turbine pumps historically have beenused extensivelyoffshore,but recent reliability improvementwith electrical submersiblepumps and hydraulicdrive units have been eagerly accepted as they eliminate alignment problems, topsides weight and in someinstances are less complex than the right angle engine driven vertical turbine units. Hydraulic calculationsfor offshorepump installationsmust rememberto account for tide and wave fluctuations.Especially critical in fire pump installations from open bodies of water is the activity of underwater diveroperations in proximity of the underwater fire pump suction bell or opening. Underwater diving operationsroutinely occur at the structural support (i.e., the jacket) for offshoreinstallations for corrosion monitoring,modifications, inspections, etc. The high water current at the intake to the submerged pump poses a safetyhazard to the divers. During the operation of the ill fated Piper Alpha offshore platform it was commonpractice to switch the fire pump to manual startup mode (requiring an individual visit to the fire pumplocation) to start it up, during diving operations. This was the case on the night when the installation wasdestroyed. A simple solution is to provide a large protective grid far enough away and around the pumpintake so that it will limit water velocities below that which would cause concern to the divers. TheInternational Association of Underwater Engineering Contractors has issued a notice (AODC 055)describingthese requirements.When more than one pump is installed, they should be coordinated to start in sequence, since immediatestart up of all pumps may not be necessary and could cause damage to the system. Depending on thenumber of pumps available, they can be set to startup on sequentiallydecreasingfire main set points. All firewater pumps should be able to be started from remote activationswitcheslocated in manned control rooms.Small capacity pumps commonly referred to as "jockey" pumps are provided on a firewater system tocompensatefor small leakages and incidentalusage without the main pump(s) startup. They are set to start0.70 to 1.05kg/sq. cm. (10 to 15 psi) above the start up pressure of main firewaterpumps. In some cases across-over fioni the utility water system can be used in place of a jockey pump, however a check valve isinstalledto prevent drain down of the firewaterby the utility water system. Jockey pumps do not requirethe
    • 208 Handbook of Fire and Explosion Protectionsame reliability of firewater water pumps and should not be credited for fire water supply when calculatingfire water suppliesavailable.Fire pumps should be solely-dedicatedto fire protection. They may be used to feed into a backup systemforemergency process cooling but not as the primary supply. If such backup is allowed is should be tightlycontrolled and easily accessiblefor prompt shutdownin case of a real emergency.A method of testing fire pumps should be provided to verify adequate performance will be availableduringan emergency. Additionally most fire protection audits, insurance surveys and local maintenancerequirements would require fire pumps to be routinely tested for performance verification. In fact,predictive maintenance can be performed before fire pumps reach reduced flow performancelevels requiringremoval. Pressure gages on the suction and discharge should be provided and a method to verify theflowing water quantity at each test point. The sizing of flow test piping should account for the maximumflowrate of the unit, not just its rated capacity.The latest trend is to install a solid state electromagnet flowmeter with precise digital readout, howeverorifice plate flowmeters are still commonly employed. Alternatively a test header with 63.5 mm (2.5 in.)outlets for pitot flow measuring can be used with reference to hydraulic flow tables. In dire circumstanceswhere flow measuring devices are not directly availableat the fire pump, plant hydrants or hose reel outletsmay be used (refer to Appendix A.l), even portable clamp-on electromagneticand uitrasonicflowmeters areavailable. The ideal situation is design so flow test water is re-circulated back into the storage reservoirfrom which it has be extracted, avoiding extensive setup requirements and unnecessary water spillage.Offshore a drainage test line is routed back to the sea surface, since disposal directly underneath topsidestructure may affect personnel who periodicallywork at the lower or sea surfacelevels.Fire Pump Standards and TestsPurchase or specification of a fire pump to support hydrocarbon operations should be in compliance withrecognized international standards for such equipment. The most commonly referenced standards are listedbelow. All of these standardsrequire a factory acceptancetest of the unit.000API 610 CentrifbgalPumps for General Refinery Service.BS 5316 Part 1:1976,(IS0 2548) AcceptanceTests for Centrifugal,Mixed Flow and AxialPumps.NFPA 20 Standard on the Installationof CentrifbgalFire Pumps.UL 448 Standard for Safety, Pumps for Fire Protection Service.Table 24Fire Pump StandardsFirewater Distribution SystemsThe distribution system is arrangement of piping configured to ensure a deliveryof water to the desired area,even if a portion of the systemis isolated for repairs. This is accomplishedby a looped network of pipes andisolation valves at strategic locations. A loop network should be provided around each process area. Fororisliore facilities, firewater piping is normally buried. Offshore it should be routed against and behindstructural members for protection against damage from fires and particularly explosions. If the piping needsto be exposed, it should be secured in both horizontal and vertical directions against potential blastoverpressureloads. Flanged connectionsshould be avoided since they may prove to be the weakest point or
    • Methods of Fire Suppression 209leakage, however they are much favored for offshore construction efforts as they eliminate specializedwelder costs.The sizing of piping is based upon a hydraulic analysis for the water distribution network for the WCCE.The main delivery pipe should be sized to provide 150% of the design flow rate. A residual pressure andflow requirement at the most remote hydrocarbon process or storage location from the supply sourcedictates the sizing for the remaining system. Nornial reliability requirementsusually suggest that minimumof two sources of supply be availablethat are in themselvesremote from each other. Therefore two remoteflow calculations must be performed to determine the minimum pipe distribution size. NFPA 24 requiresthat the minimum residual pressure available in a fire main not be less than 6.9 bars (100 psi.). Velocitycalculations should be performed which verify flows are not more than the limits of the material that isemployed.Normally firewater mains are of metal (e.g., Carbon Steel, Kunifer, etc.) construction. Some recentinstallations have used reinforced plastic piping for the underground portion of the distribution network.This is acceptable as long as the firewater system stays pressurized. If the pressure is removed, the weightof earth covering will deform the plastic piping to an oval shape. Eventually leaks will develop at fittingconnections, which are usually a higher pressure rating that the piping and can withstand the weight of theoverburden. Distribution piping should not be routed under monolithic foundations, buildings, tanks,equipment, structural foundations, etc. Both for needs of future accessibility and additional loads thefoundationsmay impose.The firewater system should be dedicated to firewater usage. Utilization for process or domestic services,erodes the fimction and capability of the firewater system, particularly its pressure, possibly during anemergency.A hydraulically designed system is preferred over standardized approach for optimization of the firewaterflows, water storage requirementsand piping materials. In any case, the main header should not be less than203 mm (8 in.) in diameter. Piping routed to hydrants, monitors, hose reels and other protective systemsshould be at least 152 mm (6 in.) in diameter.Firewater Control and Isolation ValvesAll fixed fire suppression system control valves should be located out of the fire hazard area but still withinreach of manual activation. For high hazard areas (such as offshorefacilities), dual feeds to fire suppressionsystems should be considered from opposite areas. For onshore facilities, firewater isolation valve handlesshould not be contained within a valve pit or a below grade enclosure within the vicinity of hydrocarbonprocess facilities,sinceheavy process vapors travel f?om the process and may settle inside.If a firewater line needs to be temporarily isolated and an isolation means is not availableon the immediateportion of the system needing work, a unique solution is to use a liquid nitrogen low temperature coil linefreezing apparatus. This mechanism causes an ice plug to form in the line, effectively sealing the line fromleakage, during the period the temporary isolation is needed.Firewater control valves are usually required to be tested to a recognized standard. The most commonlisting is by UL which is shown in Table 25.
    • 210 Handbook of Fire and Explosion ProtectionValve Type Test StandardGate ValveCheck ValveSprinklerValveDeluge ValveFoaMater ValvePreaction ValveButtertly ValveUL 262UL.312UL 193UL 260UL 260UL 260UL 1091Table25Test Standardsfor Fire Protection ValvesSprinklerSystemsWet and dry pipe sprinkler systems are commonly provided to indoor occupancies, such as warehouses,offices, etc. They are considered essentially 100% effective for fire suppressionif properly maintained andthe hazard has not changed sincethe original design. Sprinkler systems are normally activated by the heat ofthe fire melting a tension loaded cap at the sprinkler head. The cap melts or falls away releasing water fromthe pipe distribution network. Thus they do not activate until a fire conditionis absolutely real. Due to theremoval of Halon gaseous fire suppressionsystems because of environmentalconcerns, sprinklers have beensuggested as an alternative for electrical and electronic enclosures. An often overlooked fact whenconsideringmaintaininggaseous systems over a sprinkler systemis that considerablefire damage will alreadyhave occurred once a sprinkler system activates.Water Deluge SystemsDeluge systems should generally be activated by automatic means. Activation by manual means defeats theobjective of instailinga deluge system, and fire water monitors should be provided instead as they are morecost effective where manual means is relied upon. Most systems provided at petroleum facilities aretypically activated by a heat detection. Usually a hsible plug pneumatic loop detection system or WARdetectors are placed around the equipment. This insures activationwhen operators are not present and onlywhen a real fire situationis present.For vessels protected by deluge systems the most important points are the vessel ends, the portion of thevessel that contains a vapor space (ie., the unwetted portion), flange connections that can leak and if thevessel is located closeto the ground without good surfacedrainage, the immediateunderneath surface of thevessel that would exposed to the flames.Water Spray SystemsWater spray systems for hydrocarbonfacilitiesare routinely specifiedbecause of the rapid application meansthe system can provide and the excellent heat absorption a water based system represents. Water sprays arealso used when passive fire protection measures (i.e., fireproofing, spacing, etc.) cannot practically beutilized. The key to providing an effective system is to ensure the surfacesto be protected receive adequatewater densities and that the arrangementsto activate the system are equally fast acting. By far the highest
    • Methods of Fire Suppression 211application is the utilization for cooling process vessels. The important surfaces for process vessels toprotected are the vapor spaces and hemispherical ends. Electrical transformers are provided with waterspray coveragewhere their value or criticalityis considered high.Water FloodingWater flooding is the principle to inject water into the interior of a storage tank for the purposes ofpreventing flammableor combustibleliquids from being released from a leakage point or to extinguisha fire.The principle involves fill a vessel or tank so that the lighter density hydrocarbon fluids float on the waterand only water is released from the container. In practice the logistics of pedorming such and operationwhile also conducting prevention or fire fighting efforts for the immediate hydrocarbon spillage makes thisavenueof protection generallyunviablealthoughfor large volume containersit might be useful.Steam SmotheringThe use of steam smothering in the hydrocarbon industries is typically limited to fires that might occur as aresult of a tube leak in a fbrnace or heater. The steam is most effective in smothering fires when they arelocated in relatively small confined areas. Steam extinguishes fire by the exclusion of free air and thereduction of available oxygen content to the immediate area, similar to other gaseous suppression agents.Use of snuffing steam requires some knowledge in the principle of fire smothering and readily availablesupplies of steam generation. Snuffing steam also presents a personal burn hazard from superheated watervapor exposure if directed onto or near unprotected skin. Use of other fire extinguishingagents is generallypreferred over the use of snuffingsteam. A standard on the use of snuffing steam has never been publishedbut Appendix F of NFPA 86 provides some limited information on the general requirements in designing asystem.Water CurtainsFire water sprays are sometimes employed as an aid to vapor dispersions and can also mitigate availableignition sources. Literature on the subject suggests two mechanisms are involved that enhance protectionwhen using water spraysfor vapor dispersion. First, a water spray arrangement will start a current of air inthe direction of the water spray. The force of the water spray engulfs air and dispenses it further from itsnormal circulating pattern. In this fashion released gases will also be engulfed and directed in the directionof nozzles. Normal arrangement is to point the water spray upward to direct ground and neutral buoyancyvapors upwards for enhanced dispersionby natural means at higher levels. Second, a water spray will warma vapor to neutral or higher buoyancy to aid in its natural atmospheric dispersion characteristics. One sprayhead operating at 276 kPa (40 psi) will move 7,835 liters per second (16,600 CFM) of air at a 3 meters (10ft.) elevation. This air movement can reduce flammable vapor concentrations within a relatively shortperiod.Water curtains can also cool or eliminateavailableignition source to a released vapor cloud. In this fashionthey can also be a mitigating feature to prevent vapor cloud explosions. Hot surfaces, sparking devices andopen flames in the immediate area of a vapor release can all be eliminated as a result of a directed watercurtain where these sources exist.For water curtains to be highly effective they should be automatically activated upon confirmed gasdetection for the area of concern.
    • 212 Handbook of Fire and Explosion ProtectionBlow Out Water Injection SystemA patented water injection system has been devised for extinguishing oil and gas well fires in case of ablowout. The "Blowout Suppression System" (BOSS) consist of finely atomized water injected to the fluidstreamof a gas and oil mixture before it exits a release point. The added water lowers the flametemperatureand flamevelocitiesthereby reducing the flame stability. In the case where the flame cannot be completelydissipated, the fire intensity is noticeably deceased, preserving structural integrity and allowing manualinterventionactivities. A precaution in the use of such a device is that, if a gas release fire is suppressedbutthe flow is not immediately isolated, a gas cloud may develop and exploded that would be more destructivethat the pre-existing fire condition.Hydrants, Monitors and Hose ReelsMonitors are considered the primary manual water delivery device for hydrocarbonfacilities, while hydrantsand hose reels are considered secondary. Monitors are an initial manual fire suppressiondevice that can beactivated by operators with limited fire fighting training or experience. Use of hydrants and hoses usuallyrequire additional manpower and previous training. The use of a fire hose however, provides for moreflexibility in the application of water sprays and where it may be needed when it is impractical to install amonitor. Monitors are usually placed at the process areas, while hydrants are placed at the perimeter roads,accessible to mobile apparatus. Most monitor pipe connections may also be fitted with fire hoseconnections.Hydrants should be considered as a backup water supply source to monitors and fixed fire suppressionsystems. Hydrants should be located on the ring main at intervals to suitably direct water on the fire hazardwith a fire hose. Hydrants monitors and hose reels should be placed a minimum of 15 meters (50 ft.) fromthe hazard they protect for onshore facilities. Hydrants in process areas should be located so that anyportion of a process unit can be reached from at least two opposite directionswith the use of 76 meters (250f?), hose lines if the approach is made from the upwind side of the fire. Offshorehydrants are located at themain accesswaysat the edge of the platform for each module. Normal access into a location should not beimpeded by the placement of monitors or hydrants. This is especially important for heavy crane accessduring maintenanceand turnaround activities.For offshore installations, the placement of fire protection devices are more rigidly regulated. Monitors arenormally required by regulationsfor the helideck and on open decks, such as the drilling or pipe deck wherethe reach and area of coverage can be effective without blockagesthat would be encountered in an enclosedmodule. They can be effectively used on open decks when positioned at the edge of the deck. Heiideckmonitors should be arranged so they are normally below the helideck level, and should be provided with heatradiation screens due to the proximity to the aircraft hazard. The helideck monitors are normally at thehighest point in the system, requiringthe highest pressure to the fire pumps and the source where trapped airwill accumulate. NFPA and HSE provideguidance in the placement of helideck firewaterrequirements.Monitors should be provide at all rotating equipment and large liquid holdup vessels. They should also belocated to provide cooling water spray to the process equipment preferably from an upwind location. Aminimum of two remotely located firewater monitors are usually provided at sources of potential largehydrocarbon release, i.e., rotating equipment such as pumps, compressors, storage vessels and tanks. Thesemonitors are typically placed to provide a water spray in-between the selected equipment besides providinggeneral area protection, i.e., a water spray between two pumps to protect one from another from a seal leak.Where additional monitor coverage is desired, but placement is unavailable such as at ship loading docks,monitors can be elevated on towers to improve their area of coverage. Where monitors need to be sited inclose proximityto a hazard, such as offshorehelidecks, a heat shield is provided for the operator.Before the final placement is made on a monitor location during a design preparation,based solely on the dis-tance a water stream can reach, verification should be made that an obstruction doesnot exist which can blockthe water stream. Typical practice is to draw "coveragecircles"from the monitor on a plot plan. Where
    • Methods of Fire Suppression 213these circles intersect pipe racks, large vessels or process columns, the water coverage will be blocked andthe coverage circle should be modified accordingly. Generally where extreme congestion exist, such as inoffshore facilities monitor coverage would be ineffective due to major obstructions and congestion.Exposure to personnel activating the device due to its proximity to the hazard would also be detrimental.Similar coverage circles for fire hydrants may also be drawn for straight length distances of hose segments.These may not have to accommodate most obstructions such as pipe racks as the hose can easily be routedunder or through the rack.Monitors can be set and locked in place, while the operator evacuates or attends to other duties. A residualpressure of 690 kPa (100 psi) is required for most monitors to effectively provide suppression and coolingwater (ref.NFPA 14, Section 5.7) and shouldbe verified when several are flowing simultaneously.Oncomingor cross wind effectsmay reduce the performance of water monitors. When winds of 8 k d h r (5mph) are present they may reduce the range of water spray by as much as 50%. Consideration should begiven to the placement of monitors when the normd wind speed is such to cause performanceeffects.Hard rubber hose is preferred over collapsible fabric hose for process area hose reels and for preference ofimmediate availability. The rubber hose should not be allowed to be stored or exposed to direct sunlight forany considerabletime period.The surface slope at the placement of all hydrants, monitors and hose reels should be slightly away from thedevice itself so water will drain away and prevent corrosion effects. Where automobile traffic may beprevalent, protective post or railing should be provided to prevent impacts to the devices. The protectivebarriers should not affect the hose connection, use of hoses or obscure the spray from monitors. The postsshouldbe provided with highly visible markings or reflective paint.NozzlesThere are a variety of nozzles that can be provided to hoses and monitors. They are capable of projecting asolid, spray or fog stream of water depending on the requirements and at varying flow rates. Straightstream nozzles have a greater reach and penetration, while fog and water sprays will absorb more heatbecause the water droplets absorb more heat due to greater surface area availability. Fog and water spraynozzlesare sometimesused to assist in the dispersionof vapor releases.A 32 liters per second (500 gpm) nozzle with an adjustable combination straight stream and fog tip arenormally provided for fixed installations. Nozzles up to 63 Vs (1,000 gpm) may be used at high hazardlocations. Higher capacity nozzles generallydo not increasethe reach of the water spray only the amount ofwater delivered. Where higher capacity nozzles are retrofitted to existing systems both the firewatercapacity and the drainage system capacity should be reviewed for adequacy. Where foam agents areavailablethe nozzles should have the capabilityto aspiratethe foam solutionif it is desired.Foamwater Suppression SystemsFoamwater systems are provided wherever there are large quantitiesof liquid hydrocarbons that pose a highfire risk. Foam is an aggregate of water, chemical compoundsand air filled bubbles that float on the surfaceof combustibleliquids. They are used primarily to provide a cohesive floating blanket on the liquid surfaceof the liquid material it is protecting. It extinguishes a fire by smothering and cooling the fuel, Le., liquidsurface, and prevents re-ignition by preventing the formation of combustible mixtures of vapor and air overthe liquid surface. Foam will also cool the fuel and surrounding equipment involved in the fire. Foams aresupplied in concentrates that are appropriately proportioned into water supply systems. They are thenaspirated with air to produce the foam bubbles.
    • 214 Handbook of Fire and Explosion ProtectionFoam is a homogenousblanket of a mixture of liquid chemical and air or a nonflammablegas.Foam fire suppressionsystems are classified as high or low expansion. High expansion foamis an aggregation of bubbles resulting from the mechanical expansion of foam solution by airor other nonflammablegases. Expansion ratios range from 100:1 to 1,000:1. Foams with anexpansion ratio significantly less than 100:1, are produced from air foam, protein foam,fluoro-proteinfoam, or synthetic foam concentrates. They are inserted as a definite portion ina liquid stream that is later aspiratedjust before or at a distribution nozzle. High expansiontype foams are generated in a high expansion generator by blowing air through a wet screenwith a continuous spray of water producing additive. High expansion foam is very light. Itcan be appliedto completelyand quickly fill an enclosure or room. The various types of foamprovide similar protection. They are principally selected on the basis of compatibilityof foamequipment provided, materials involved and use with other agents. All foams are electricallyconductiveand should not be used on fires involvingenergized electricalequipment.Low expansion foams are typically applied to the surface of exposed flammable liquids,especially in outdoor areas. High expansion foams are commonly applied to large enclosedareas where high winds would not affect the foam usefulness and where interior locations arehard to reach.Special alcohol resistant (or compatible) type foam is needed for application to alcohols,esters or ketones type liquids and organic solvents, all of which seriously break down thecommonly used foams. Commercially available foam products are now available that can beused on both alcohols and hydrocarbons, only alcohols or only hydrocarbons. It is thereforeimperativeto designfoam systemsin a cost effectivefashion if several products are in use thatmay require special foam applicationrequirements.Chemical foams were widely used in the industry before the availabilityof liquid concentrates,and now they considered to be obsolete.ConcentrationsFoam concentrations currently on the market range from 1 to 6 mixing or proportioningpercent with water. The advantage in the lower percentage mixing means less foamconcentrate is needed for a particular hazard. This is economical both in amount of agentneeded and in storage facilities necessary, and is particular usefir1 offshore where a weightsaving can also be realized. Foam systems of very low percentages necessarily require a“cleaner”system to perform adequately.SystemsIn the oil. and gas industry there are generally five foam fire protection systems commonlyencountered. :(1.) General area coverage with foam water monitors, hoses or portable towers.(2.) Fixed foam water deluge spray systems for general area or specific equipment.(3.) Atmospheric or low pressure storage tank protection by overhead Foam Chambers.(4.) Atmospheric or low pressure storage tank protection by subsurface injection systems.(5.) High expansion foam applied to special hazards such as warehouses or confinedspaces.
    • Methods of Fire Suppression 215General Area CoverageGeneral area coverage is generally provided where there is hlly or partially enclosedareas, e.g. offshore modules, truck loading racks, liquid storage warehouses, etc. whereliquid spills can easily spray, spread or drain over a large area. Where the protected areasare critical or high value immediate detection and release mechanisms are chosen (i.e.,deluge systems). Aspirating or non-aspirating nozzles may be used. Aspirating nozzlesgenerally produce foams with a longer life span after discharge. Aspirating nozzles alsoproduce a foam with a higher expansionratio than non-aspirating nozzles.Foam Water Deluge SystemsDeluge systems are generally used in areas requiring an immediate application of foamover a large area, such as process areas, truck loading racks, etc. The system employsnozzles connected to a pipe distribution network which are in turn connected to anautomatic control valve referred to as deluge valve. Automatic detection in the hazardarea or manual activation opens the deluge valve. Guidance for designing foam waterdeluge systems is provided in NFPA 16.Overhead Foam InjectionThese systems are typically provided for the protection of atmospheric or low pressurestorage tanks. They consist of one or more foam chambers installed on the shell of a tankjust below the roof joint. A foam solution pipe is extended from the proportioningsource, which is located in a safe location, to a foam aspirating mechanismjust upstreamof the foam chamber or pourer. A deflector is usually positioned on the inside tank wallat the foam chamber. It is used to deflect the foam against the tank wall and onto thesurfaceof the tank or the tank and shell seal area.Two types of designsare commonly applied. For cone top tanks or internal floating rooftanks with other than pontoon decks multiple foam makers are mounted on the upperedge of the tank shell. These systems are designed to deliver and protect the entiresurface area of the liquid of the tank. For open and covered floating roof tanks withpontoon decks the foam system is designed to protect the seal area. Foam makers aremounted on the outside of the tank shell near the rim and foam is run down inside to theseal area that is encapsulated with a foam dam. This method tends to cause themovement of cooler product to the surface to aid in extinguishment of the fire and theamount of water delivered to the heat layer in heavier products can be controlled toprevent excessive frothing and slopover.Subsurface Foam InjectionSubsurface foam injection is another method to protect atmospheric or low pressurestorage tanks. This method produces foam through a "high back pressure foam maker"and forces it into the bottom of the storage tank. The injection line may be an existingproduct line or a dedicated subsurface foam injection line. Due to its buoyancy andentrainment of air, the foam travels up through the tank contents to form a vapor tightblanket on the surface of the liquid. It can be applied to any of the various types ofatmospheric pressure storage tanks but is generally not recommended for application tostorage tanks with a floating roof since distributionof the foam to the seal area fiom theinternal dispersion is difficult.
    • 216 Handbook of Fire and Explosion ProtectionHigh Expansion FoamHigh expansion foam is generallyapplied to ordinary combustible (Le., Class A) fires thatoccur in relatively confined areas that would be inaccessible or a hazard for fire fightingpersonnelto enter. The system controls fires by cooling, smothering an reducing oxygencontent by steam dilution. The system uses high forced air aspirating devices, typicallylarge fans, to produce foams with an expansion ratio of 100 - 1,000to 1. Proportioningof 1 112% percent is normally used providing large quantities of foam from relativelysmall amounts of concentrates. Use in the oil and gas is normally reserved to manual firefighting efforts.Gaseous SystemsCarbon Dioxide SystemsCarbon dioxide (C02) is a non-combustible gas that can penetrate and spread to all parts of a fire,diluting the available oxygen to a concentration that will not support combustion. C02 systemswill extinguishfires in practicallyall combustiblesexcept those which have their own oxygen supplyand certain metals that cause decomposition of the carbon dioxide. C02 does not conductelectricity and can be used on energized electrical equipment. It will not freeze or deteriorate withage. Carbon dioxide is a dangerous gas to human life since it displaces oxygen. Concentrationsabove 9 percent are considered hazardous, while 30 percent or more are needed for fireextinguishing systems. Carbon dioxide systems are generally ineffective in outdoor applicationssince wind effects and dissipate the vapors rapidly. It has a vapor density of 1.529 and thereforewill settleto low points of an enclosure.For fire extinguishmentor inerting purposes C02 is stored in liquid form that provides for its ownpressurized discharge.ApplicationCarbon dioxide may be applied for fire extinguishmentthrough three different mechanisms:(1) Hand hoses from portable storage cylinders.(2) Total floodingfixed systems.(3) Local applicationfixed systems.Carbon dioxide is an effective extinguishing agent for fires of ordinary combustibles,flammable liquids and electrical fires. It is a clean agent in that it will not damage equipmentor leave a residue. Some cooling effect is realized upon agent discharge, but a thermal shockto equipment should not occur if the systemis property designed and installed.Fixed systems are classified in the manner they are stored. Low pressure 2,068 kPa (300 psi)or high pressure 5,860 kPa (850 psi) systems can be specified. Low pressure systems arenormally provided when the quantity of agent required exceeds 907 kgs (2,000 lbs.).Protection of electronic or electrical hazards usually requires a design concentration of 50%by volume. NFPA 12 provides a table specifying the exact concentration requirements forspecific hazards. As a guide, 0.45 kgs (1 lb.) of C02 liquid may be considered to produce0.23 cubic meters (8 cu. ft.) of free gas at atmosphericpressure.Fixed C02 systems are almost used extensivelyfor protecting highly valuable or critical wherean electricallynon-conductive, non-residue forming agent is desired and where the location isunmanned. In the hydrocarbon industries C02 systems are usually provided to protect
    • Methods of Fire Suppression 217unmanned critical areas or equipment such as electricaVelectronic switchgear rooms, cabletunnels or vaults, turbine/compressorenclosures, etc. Where rotating equipment is involvedboth primary and supplemental discharges occur to account for leakages during the rotatingequipment "run-downs." Concentrations are to be achieved in 1 minute and normallymaintainedfor 20 minutes.Safety PrecautionsCO, is a nonflammablegas, therefore it does not present a fire or explosion hazard. The gas isgenerally consideredtoxic but will displace oxygen in the air, since it is 1.5times heavier thatair it will settle and air supplieswill be pushed out of the area. The C02 gas is considered anasphyxiation hazard to personnel for this reason. Since the gas is odorless and colorless itcannotbe easiiy detected by human observationin normal environments. Fire protection C02gas is normally stored under high pressure as a liquid and expands 350 times its liquid volumeupon release.The normal concentration of oxygen in air is from 21 to 17 percent. When the concentrationof oxygen in air drops below 18 percent, personnel should consider vacating or not enteringan area due to an asphyxiationhazard. Alternativelythey can be provided with protective selfcontained breathing apparatus to work in low oxygen environments.There are two factors of personnel hazard from a C02 release:(1) When increasing amount of C02 are introduced into an environment the rate anddepth of a persons breathing increases. For example at 2 percent C02 concentration,breathing increases 50 percent and at 10 percent concentration a person will graduallyexperience dizziness,fainting, etc.(2) When atmosphericoxygen content is lowered below 17 percent a persons motorcoordinationwill be impaired. Below 10 percent, they will becomeunconscious.System DischargesWhere fixed automatic C02 systems are installed, a time delay of 30 seconds ,warning signsand alarms or beacons are provided to warn the occupants of the room. This allows theoccupants to immediately evacuate, or initiate an "abort" switch where the activationhas beenby accidental means.System LeakagesLeakages from C02 fire suppression systems are considered extremely rare. With adequateinspection and maintenanceprocedures a leak on the system should generally not be expectedto occur. Installed pressure gages on the C02 cylinders should be frequently checked againstthe initial pressure readings. If they are found to be different, immediate action should betaken to investigatepossible leakages.In small rooms where high pressure C02 storage bottles are kept, it is apparent that with a350 expansionratio, the room could easilybe a hazard to personnel from system leakages.In small rooms where high pressure C02 storage bottles are kept, it can be readily realizedthat with a 350 expansion ratio, the room would easily be a hazard to personnel from systemleakages. A calculation could be performed which would identi@ the amount of potentialC02 build up (ie., percent C02 concentration) from the immediate and complete (ie., leak)
    • 218 Handbook of Fire and Explosion Protectionfrom a single storage container (based on liquid capacity of the container storage, room size,ventilation rates, etc.). Where C02 fire protection storage bottles are contained in enclosedareas they should be well labeled to the possibility of an oxygen deficient atmosphere. Theroom should normally be a controlled location (i.e., doors locked) and all personnel enteringthe enclosure must be equipped with a portable oxygen monitoring device (unless a fixedoxygen monitoring system is installed) as dictated by a companys safety procedures for entryinto an area where there is a possibility of an oxygen deficient atmosphere. Should a leakoccur in the enclosure a portable exhaust fan can be positioned to evacuate any accumulatedC02 vapors at the time and an oxygen monitoring device can be arranged to confirm removalof vapors to allow for safe entry. The provision of permanent operating exhaust fan for theseareas would not necessarily guarantee that when a minor C02 leak occurs they would beadequately removed from the area, thereby precluding the necessity of oxygen monitoring anda controlledlocation. SinceC02 vapors are heavier than air they will normally seek the lowerportions of any enclosure. The C02 vapors may not reach the exhaust fan especially if theexhaust fan cannot remove the heavier vapors from the remote lower regions in the enclosure.Depending on the size of the leak, vapors may propagate from the leaking storage containerfor a considerable amount of time. Even when an exhaust fan is installed to dissipate thevapors, it cannot be guaranteed that the C02 vapors would be entirely removed when anindividualrandomlyenters the room.In room that are provided with air conditioning an exhaust fan would always be evacuationthe cooled air. This would defeat the purpose of the air conditioner. (the exhaust fan wouldhave to be continuously operated since no idea when a leak would occur could be accuratelypredicted, unless sensing instruments were provided, if so the exhaust fan as a preventivedevicewould then be consideredsomewhat superfluous).In instances where C02 storage bottles are installed in enclosed spaces, an exhaust fan isusually provided the protected hazard area. It is activated to removethe vapors once a systemhas been klly discharged, rather than a prevention measure for partial vapor release anddisposal of unexpectedleakages.Supplemental measures that may be considered are a fixed oxygen monitoring system, a lowpressure storage bottle alarm(s) or odorizationof the stored C02 gas.DisadvantagesC02 systemshave the followingdisadvantages:1. The expelled C02 gas presents a suffocation hazard to Humans in the exposed area.All such areaswould require strict access control.2. C02 gas is considered a "greenhouse"gas and may in the future be considered anenvironmentalconcern.3. Fixed C02 systemsrequire a large storage area and have considerableweight whichlimitstheir benefit offshore.4. Deep seated fires may not be hlly extinguishedby a gaseous fire suppressantagent.HalonHalon is a halogenated compound that contains elements from the halogen series - fluorine,chlorine, bromine and iodine. Halogen atoms from noncombustiblegases when they replace
    • Methods of Fire Suppression 219the hydrogen atoms in hydrocarbon compounds such a methane or ethane. Except for Halon1310, bromotrifluormethane, most halogenated hydrocarbon compounds are corrosive whenmoistureis present. Halon will also break into corrosive and toxic byproducts in the presenceof a sustained electrical arc.Halon systems were the ideal fire suppressionagent before their implicationsof environmentalimpact due to ozone depletion. The industry is gradually phasing out usage of halon systemsfor this reason. A flowchartto analyzemechanismsto supplement or eliminateHalon systemsfor electrical or computer processing areas is shown in Figure 1 1. Some of the prime reasonsto eliminate the use of Halon systems is that the facility may be constantly manned with arelatively low fire risk. Other facilities may have a very low combustible load and can besupplemented by highly sensitive fire detection means, such as a VESDA fire detectionsystem.Halon ReplacementsSeveralHalon replacements are now availablethat have been tested and accepted by certifyingagencies. These agents generally require higher concentrations than that Halon suppressionsystems. They may be asphyiants to humans. Most also have greater storage requirements(i.e., space and weight) than the previousHalon systemsdid.Oxygen Deficient Gas Inerting SystemsTo reduce the risk of explosion and fires from enclosed spaces of volatile hydrocarbon storagetanks, a gas with that would be considered deficient in oxygen is provided to exclude oxygenfrom enteringthe enclosure. Large ocean going tanker vessels are equipped with a continuosinert gas systemthat blankets storage holds or tanks with an oxygen deficient gas (combustionexhaust gases from the prime mover). Similarly some crude oil storage tanks are providedwith a processed gas as a method of excluding oxygen from enteringthe vapor space of coneroof storage tanks.
    • 220 Handbook of Fire and Explosion ProtectionFire Initiation(Failure/Malfunction/Electrical Fire1 - Detection ActivatedextinguishedNO NOOf Fire SuppressedELECTRICAL FIRE INCIDENT CONTROLFigure 11
    • Methods of Fire Suppression 221Chemical SystemsWet ChemicalWet chemical systems have a slightly advantage over dry chemicals in that they can coat theliquid surfaceof the fire and can absorb the heat of a heat, thereby preventing re-ignition. Wetchemical systems are primarily provided for kitchen cooking appliances - grills, fryers, etc.They provide a fixed fire suppression application of liquid fire suppressant through fixednozzles. The typical applicationfor petroleum facilitiesis at the kitchens of onsite cafeterias.Spray coverage is provided to exhaust plenums, and cooking surfaces activated by fusiblelinks or manual pull stations. The bible links should be rated for the maximum normaltemperature expected in the exhaust fumes, usually 232 OC (450 OF). Common practice toconduct a one time agent discharge and operational test during the initial installationacceptance,together with a hydrostatictest of the systempiping.Dry ChemicalDry chemical agents currently used are a mixture of powders, primarily sodium bicarbonate(ordinary), potassium bicarbonate (Purple K), monoammmonium phosphate (multipurpose).When appliedto a firethey cause extinguishmentby smothering the fire process. They will notprovide securement of a flammableliquid spill or pool fire and it can re-flash after it is initiallysuppressed if an ignition source is present (i.e., a hot surface). Dry chemical is still veryeffective for extinguishment of three dimensional flammable liquid or gas fires. It isnonconductiveand therefore can be used on live electricalequipment.Dry chemical agents reduce visibility, pose a breathing hazard, clog ventilation filters and theresidue may enhance corrosion of exposed metal surfaces. Dry chemicals should not be usedwhere delicate electrical equipment is located, for the insulation properties of the drychemicals may render the contacts inoperative. Dry chemicals may also present a clean upproblem after use, especiallyfor indoor applications. The system should activate fast enoughto prevent equipment becoming too hot to cause a re-ignition once the system has beendischarged. -411dry chemicalagents are corrosiveto exposed metal surfaces.Fixed systems may be fixed nozzles or hand hose line systems. They usually range in capacityfiom 68 to 1,360kgs (150 to 3,000 Ibs.). Most use a high pressure nitrogen cylinder bank tofluidize and expel the dry chemical from a master storage tank. Where immediate watersuppliesare unavailable,fixed dry chemical systemsmay be a suitablealternative.Dual Agent SystemsChemical and FoamDual agent suppression systems are a combination of simultaneous application of foam waterand dry chemical to provide for greater fire fighting capabilities. Usually aqueous film-forming foam (AFFF) and potassium bicarbonates are used. They are provided in separatevessels on a self contained skid. When needed they are charge by a bank of high pressurenitrogen cylinders and the agents are discharged through two manually operated and directednozzles. The nozzles are provided on approximately 30 meters (100 ft.) lengths of hardrubber hose to provide for fire attack tactics.Self contained dual agent systems, (foadwater and dry chemical), are provided for manualfire fightingefforts against three dimensional pressureleaks and large diameter pool fires. Thedesign affords fast fire knockdown, extinguishment and sealant against re-flash. A skid
    • 222 Handbook of Fire and Explosion Protectionmounted unit is provided at locations where flammable liquids are present and personnel maybe in a direct vicinity of the hazard. Typical hydrocarbon applications are associated withaircraft operations both fixed wing and rotary (Le., helicopters). For land based operationsthe skid is provided on a flatbed of a truck or small trailer for greater mobility at aircraftlanding strips. Offshorethe equipmentis normally fixed at the helideck periphery.
    • Methods of Fire Suppression 223OffshoreProcess ModuleProcessVesselsIGas ReleaseIProcessArea4. Vapor Dispersion Deluge Spray 4. NFPA 15Liquid Spill NFPA 30 1. Hydrants 1. NFPA 24Gas Release 2. Monitors 2. NFPA 243. Hose Reel 3.NFPA 244. OverheadFoamwater Deluge 4. NFPA 16Liquid Spill NFPA 30 1.Hydrants 1.NFPA 24Gas Release 2. Monitors 2. NFPA 243. HoseReel 3.NFPA 242. MonitorsI3. Hose ReelHeatersTank FarmTruckLoadingRail LoadingMarine Loadingb PStationGasCompression2. NFPA 243.NFPA 24Gas Release 2. Monitors 2. NFPA 243. NFPA 86Liquid Spill NFPA 30 1.Hydrants 1.NFPA 24Gas Release 2. Monitors 2. NFPA 243.NFPA 154.NFPA 115.NFPA 11Liquid Spill NFPA 30 1.Hydrants 1.NFPA 24Gas Release 2. Monitors 2. NFPA 243.NFPA 16Liquid Spill NFPA 30 1. Hydrants 1.NFPA24Gas Release 2. Monitors 2. NFPA 24Liquid Spill NFPA 30 1.Hydrants 1.NFPA 24Gas Release 2. Monitors 2. NFPA 24Liquid Spill NFPA 30 1. Hydrants 1. NFPA 242. Monitors 2.NFPA 24G a s Release NFPA 30 1. Hydrants 1.NFPA 242. NFPA 242. Monitors3. Snuffig Steam3. Water Deluge Cooling Spray4. SubsurfaceFoam Injection5.Foam TopsideDelivery3. OverheadFoamwaterDelugeKitchensAdministrationI I I 4. WaterDelugeCooling Spray I 4. NFPA 15Fired I Liquid Spill I NFPA30 I 1.Hydrants I l.NFPA243. Sprinkler System 3 NFPA 13LiquidSpill NFPA I01 1. DryChemical 1. NFPA 17CombustibleFire 2. Wet Chemical 2. NFPA 17ACombustibleFire NFPA 101 1.Hvdrants 1.NFPA 24OficeI I 1 4. Preaction Sprinkler I 4. NFPA 13Flare I Liquid Spill I NFPA30 I 1. Hydrants I 1.NFPA242 Standpipe System 2 WPA142 Sprinkler System 3 NFPA13Table 26Fixed Fire SuppressionDesign Options Basis
    • 224 Handbook of Fire and Explosion ProtectionApplication TableTable 27Fire SuppressionSystem Applications
    • Methods of Fire Suppression 225Table 28Advantages and Disadvantages of Firewater Systems
    • 226 Handbook of Fire and Explosion ProtectionBibliography1.2.3.4.5.6.7.8.9.10.11.12.13.14.15.16.17.18.19.20.American Petroleum Institute, (API), RP 14G. Recommended Practice for Fire Prevention and Control on OpenTwe OffshoreProductionPlatforms,Third Edition,WashingtonD.C., 1993.American Petroleum Institute (API), Standard 610. Centrifugal Pumps for General Refinerv Service, SeventhEdition, API, WashingtonD.C., 1989.American Petroleum Institute (API), Publication 2021. Fighting Fires in and Around Flammable and CombustibleLiauid Atmosuheric StorageTanks, Third Edition, API, Washington, D.C., 1991.AmericanPetroleum Institute (API), Publication 2030 Guidelines for Auulicationof Water Surav Svstems for FireProtectionin the PetroleumIndustry, First Edition,API, Washington, D.C., 1987.AmericanWater WorksAssociation(AWWA)C502. Standardfor Drv-Barrel Fire Hydrants,AWWA, Denver, CO,1985.American Water Works Association (AWWA), C503, Standard for Wet-Barrel Fire Hvdrants, AWWA, Denver,CO, 1988.AmericanWater Works Association(AWWA), M17. Installation. Field Testing and Maintenance of Fire Hydrants,Third Edition,AWWA, Denver, CO, 1989.American Water Works Association (AWWA), M31. Distribution Svstem Reauirements for Fire Protection, FirstEdition,AWWA, Denver,CO, 1989.Bryan, J. L., Automatic Sprinklerand StandpipeSvstems,NFPA, Quincy,MA., 1976.Coon, W., Fire Protection Design. Criteria. Options. Selection,R. S. Means, Kingston,MA. 1991Department of Energy(U.K.), OffshoreInstallations:Guidanceon Fire Fighting Equipment, HMSO, London, U.K.,1978.Department of Energy (U.K.), 1978 NO. 611, Offshore Installations The Offshore Installations (Fire FightingEauiument)Rermlations. 1978,HMSO, London,U.K., 1978.International Association of Underwater Engineering Contractors, Protection of Water Intake Points for DiverSafe&. AODC Notice#055, Associationof Diving Contractors,London,U.K. 1991.Industrial Risk Insures (IN),IM.2. Section 2.5.3. Fire Protection Water & Still Control for Outdoor Oil &ChemicalPlants, IRI, Hartford,CT, 1992.National Fire ProtectionAssociation(NFPA),Fire ProtectionHandbook, 17thEdition,NFPA, Quincy,MA, 1991National Fire Protection Association(NFPA),NFPA 10. PortableFire Extinguishers,NFPA, Quincy, MA, 1990National Fire Protection Association (NFPA), NFPA 11. Low Expansion Foam and Combined Agent Systems,NFPA, Quincy,MA, 1988.National Fire Protection Association (NFPA), NFPA 11A. Medium and Hiph Exuansion Foam Svstems, NFPA,Quincy, MA, 1990.National Fire Protection Association (NFPA), NFPA 12. Carbon Dioxide Extinguishing Systems, NFPA, Quincy,MA, 1993.National Fire Protection Association (NFPA), NFPA 13. Installation of Sprinkler Systems, NFPA, Quincy, MA,1991.
    • Methods of Fire Suppression 22721. National Fire Protection Association (NFPA), NFPA 14. Installation of Standuipe and Hose Svstems, NFPA,Quincy,MA, 1993.22. National Fire Protection Association (NFPA), NFPA 15. Water Sprav Fixed Svstems for Fire Protection, NFPA,Quincy,MA, 1990.23. National Fire Protection Association (NFPA) NFPA 16. Deluge Foam-Water Surinkler and Foam-Water SpravSystems,NFPA, Quincy,MA, 1991.24. National Fire Protection Association (NFPA), NFPA 17. Dry Chemical Extinmishim Svstems, NFPA, Quincy,MA, 1990.25. National Fire Protection Association (NFPA), NFPA 17A. Wet Chemical Extinguishing Svstems, NFPA, Quincy,MA, 1990.26. National Fire Protection Association (NFPA), NFPA 20. Installation of Centrifugal Fire Pumps, NFPA, Quincy,MA, 1990.27. National Fire Protection Association(NFPA), NFPA 22. Water Tanks for Private Fire Protection,NFPA, Quincy,MA, 1993.28. National Fire Protection Association (NFPA), NFPA 86. Ovens. and Furnaces, Desim. Location, Equipment,NFPA, Quincy,MA, 1990.29. NationalFire Protection Association(NFPA),NFPA 418. HelideckProtection,NFPA, Quincy,MA, 1993.30. Underwriters Laboratories Inc. (UL), UL 193, Alarm Valves for Fire Protection Service, Ninth Edition, UL,Northbrook,IL, 1993.31. Underwriters LaboratoriesInc. (UL),UL 260. Drv Pipe. Deluge, and Pre-Action Valves for Fire ProtectionService,Sixth Edition,UL, Northbrook,IL, 1994.32. Underwriters Laboratories Inc. (UL), UL 262. Standard for Safetv for Gate Valves for Fire Protection Service,Seventh Edition, UL, Northbrook, IL, 1994.33. Underwriters Laboratories Inc. on),UL 312. Standard for Safetv for Check Valves for Fire Protection Service,Eighth Edition,UL, Northbrook, IL, 1994.34. Underwriters Laboratories Inc. (UL), UL 448. Standardfor Safetv for Pumps for Fire Protection Service, SeventhEdition, UL, Northbrook,IL, 1990.35. UnderwritersLaboratoriesInc. (UL), UL 1091. Standardfor Safetvfor ButterflvValves for Fire Protection Service,Fourth Edition, UL, Northbrook,IL, 1993.
    • Petroleum operations are found on all the major continents and diversified environmental conditions. Theseenvironments are so different and remote that unique situations develop which require specializedrequirements.Arctic EnvironmentsArctic environments pose different ambient conditions than normally encountered at most oil andgas facilities. The most obvious is that the ambient temperature level can reach extremely lowlevels, asmuch as -45.5 Oc (-SOOF)and that snow or ice storms canbe expectedto occur.The primary concern at these locations is the protection of critical equipment so they can continueto function. This involves both the metallurgical properties of vessels,piping, control systemsandinstrumentation. Personnel operations are also hampered in such location. Generally heavyinsulated protective clothing must be worn and accessto equipment becomes blocked or difficultdue to ice and snow accumulation. Locations considerably north or south will also exhibit longerperiods of darknessand light during the seasons,causing disorientation to the unfamiliar personnel.For meansof protection, the use of water based suppressionsystemsmay be a hazard due to thedisposal of firewater water, which will freeze quite readily in exposed locations. This may also bethe case with exposed hydrocarbon fluid lines that, if isolated, say for an ESD activation, mayfreeze up due to lack of circulation. This will hamper restart operations for the facility. Typicalusein the past hasbeen the reliance on gasesfire suppressionagentsfor enclosed area, particularlyHalon. Other methods include fire water storagetanks that are kept warm, together with fire mainsdeeply buried and continually circulated.Desert EnvironmentsDesert environments also pose different ambientconditions than that normally encountered at most oiland gas facilities. The most obvious is that the ambienttemperature level can reach extremely high levels, asmuch as 54.4 Oc (130 OF) and that sand storms can beexpected to occur. Typical problems of free rangeroving livestock (camels, sheep, goats, etc.) with theirnomadic herdersmay also exist.228
    • Special Locations, Facilities and Equipment 229Special considerationof thermal relief for piping exposure to sunlight (solar radiation) needs to beunder taken. This is usually accomplishedby paintingwith reflective paint or burial. Hydrocarboncontainingpiping is usually painted in a reflective color (i.e., aluminum)for advantagesof reflectionof solar radiation (heat input) to avoid thermal expansionof fluidsin blocked systems.Where facilities are exposed to the constant radiation of the sun, sun shades are provided overexterior exposed equipment that may not function properly at elevated temperatures or woulddeteriorate rapidly if left continual exposed to the direct sunlight. Most electrical or electronicequipment is rated for a maximum operating temperature of 40 OC (104 OF) unless otherwisespecified, e.g., hazardous area lighting temperatures are normally specified for 40 O C (104 OF)limit. Of particular concern for fire protection systems are those containing storage for foamconcentratesrubber hoses or other rubber componentswhich may dry and crack.Sand barriers and filters are provided on facilities and equipment where fresh air intakes areneeded. Sand storms can also cause abrasive actions to occur on exposed hardware that mightcause it to malfunction.Signs, label and instructions exposed to direct sunlight may begin to fade after relatively shortperiods after installation.Offshore FacilitiesOffshore facilities are dramaticallydifferent from onshore facilitiesbecause instead of being spreadout the equipment is segregated essentialiy into compartments or separated into a complex ofplatforms. Offshore facilitiespose critical questions of personnel evacuation and the possibility oftotal asset destruction if prudent risk assessmentsare not performed. A through analysis of bothlife safety and asset protection measures must be undertaken. These analyses should becommensuratewith the level of risk a particular facilityrepresents, either in personnel exposed orfinancial loss. An unmanned wellhead platform might only require the review of wellhead shut-in,flowline protection and platform ship collisions to be effective, while manned drilling andproduction platforms may require the most extensiveanalysis.Generally the highest risks in offshore facilities are blowouts, transportation impacts and processupsets. Where inadequate isolation means are provided for either wellheads or pipelineconnectionsto the installationconsiderablefuel inventorieswill be availableto an incident.The helidecks of offshore facilities are usually povided at the highest portion of the offshoreinstallation for avoidance of obstructions during aircraft maneuvering and available space. As aresult the roof of the accommodation is typically selected. The location also facilitates evacuationof personnel from installation by helicopter due to its proximity to the highest concentration ofpersonnel. This enhances one of the avenues of escape from the installation but also exposes theaccommodation to several hazards. The accommodation becomes subject to the hazards ofhelicopter crashes,&el spillages,and incidentalhelicopter fuel storage and transfer facilities.Because of the inherent hazards associated with helideck operations they should be provided with
    • 230 Handbook of Fire and Explosion Protectionfoam water monitor coverage, that have a minimum duration of 20 minutes. The monitors shouldbe placed as a minimum on opposite sides of the deck, but preferably from three sides. Themonitors should be located below deck levels and provided with a heat radiation screen that can beseen through. The helideck should be elevated above the accommodationby an air gap to ensurevapor dispersals fiom fuel spillages. Fuel loading and storage for the helicopters should be locatedso they can bejettison or disposed of in an emergency if they arelocated near the accommodation.Offshore Floating Exploration and Production FacilitiesFloating exploration and production facilities are sometimes provided on jackup rigs, semi-submersible vessels or ex-crude oil shipping tankers converted to production treatment vessels.These facilities are essentiallythe same as fixed offshore platform or installations except they aremoored in place or provided with a temporary support structure instead of provided with fixedsupports to the seabed. The major process fire and explosion risks are identical to the risksproduced on offshoreplatforms. They have one addition major facility risk, that is the maintenanceof buoyancy of the installation. Should fire or explosion effects cause a loss of buoyancy (or evefistability) the entire facility is at risk of submergence. Adequate compartimization and integrityassurancesmust be implementedin these instances.u1IPipelinesFor the purposes of risk analysis a pipeline should be thought of as an elongated pressure vesselwith unlimited flow. They normally contain large inventories of combustible substancesat elevatedpressures. Damage to an entire pipeline is highly unlikely and a damaged portion of a pipeline cangenerally be easily replaced. The primary risks of pipelines are the exposures they pose to nearbyfacilities and business interruption concerns. To maintain adequate protection against theirhazards, adequate siting, isolation and integrityassurancesmust be provided.Siting - The preferred arrangement of bulk transport pipeline systems is for burial underground.This provides for enhanced protection from overhead events. This is even the case for offshorepipelines where there have been numerous incidents of dragged anchors from fishing vessels topipelines exposed on the seabed. A radius of exposure from a pipeline can also be easily calculatedfor fires and vapor explosionsbased on the commodity, pressure, release opening, etc. From thesecalculations a restricted zone or similar can be designated.Isolation - It has been shownthat the additionof isolation valves at periodic intervals is not as costeffective as prevention measures such as thickness inspections or tests. However all pipelinesshould be provided with a means for emergency isolation at it entry or exit from a facility.Offshore facilities may be particularly vulnerable to pipeline incidents as the Piper Alpha disasterhas shown. In that accident a contributing factor to the destruction was the backfeed of thecontents of the gas pipelineto platform once the topside isolation valve or piping lost its integrity.Further isolation means @e.,a subseaisolation valve SSIV) were not available.Integrity Assurances - When first installed piping systems will be checked for leakages at weldjoints and flange connections. Weld joints are usually verified by NDT radioactive means (Le., x-ray) or die penetrants.Depending on the services, the pipeline will usually be hydrostatically or pneumatically tested.Normally a section is specifiedfor testing from flange point to flange point. Once tested the blankflanges at the ends of the section are removed and the tested portions are permanently connected
    • Special Locations, Facilities and Equipment 231for operational start-up.hydrostaticallytested and will be the most likely point of systemleakageupon system startup.This usually leaves a flange joint or connection that has not beCorrosion is by far the most serious hazard of pipeline incidents. It is imperative that adequatecorrosion monitoring programs be provided for all hydrocarbon pipelines. Order crude oilpipelines operating at elevated temperatures appear more susceptible to corrosion failures thanother pipelines.Other failures of pipelines generally occur as a result of third party activity and natural hazards.Offshore, pipelines are generally more susceptible to fishing boats dragging their anchors on theseabed. Onshore pipelines are vulnerableto impactsfrom earth moving operations for constructionor road grading. On occasionimpacts from mobile equipment may also directly strike and damagethe pipeline.Wellheads -Exploration(Onshore and Offshore)The primary concern with exploration wellheads is the possibility of ablowout during drilling operations. A blowout is a loss of control of awellhead pressure. Normallythe wellhead pressure in a well being drilledis controlled with a counter balance of drilling "mud" that equalizes itsweight with that of the upward pressures of the oil or gas in the well. Ifthe flow of mud is interrupted, such as through a loss of circulation (i.e.,through the formation,drill pipe, etc.), the only thing between the drillingrig and its crew on the surface and the oil and gas forcing itself up thewell at 34.5 to 68,948 kPa (5 to 10,000 psi), is a stack of valves calledblowout preventers. In theory, they can stop the upward oil and gasflow, as long as the well pressure is less than their seals are rated at, andthey are operated in time(/An underground blowout can also occur during a drilling operation. An underground blowoutoccurs when a loss of mud control occurs and the reservoir fluids begin to flow from oneunderground zone into a zone of lower pressure. Because the loss flow is below the surface it isconsidered an underground blowout and are more difficultand complex to evaluate and correct.Drilling mud is a mixture of barite, clay, water and chemical additives. Initially in the early days ofexploration is was clay that was provided from the river beds in Texas, Arkansas and Louisiana.The mud is provided to pits at the drilling site. From the mud pits it is pumped into the drill pipe tolubricate the drill, remove cuttings and maintain pressure control. M e r exiting the drillhead itcirculatesin the annulus of the wellpipe back to the surfacewhere it is reused after the particulatesare removed By varyingthe weight of the drillingmud into the drillstack, wellhead pressure controlcan be effectivelymaintained. Naturally occurring barite has specific weight of 4.2. Eight or ninepound drilling mud is considered light and eighteen or twenty pound is considered heavy. Heaviermud, containing larger quantities of barite is considerably more expensive than light mud, so adrilling company may try to use the lightest weight mud possible when drilling a well. It has also betheorized that heavier drilling mud might precipitate reservoir formation damage by blocking thepores in the reservoir that the oil flows out of or through. On occasion such frugality and reservoirconcerns may have been a contributingfactor leadingto a wellhead blowout.Blowout preventers (BOPS)hnction is to cut off the flow of potential blowout. In all wells beingdrilled there are normally three holes or pipes within pipes that are at the surface of the wellhead -conductor pipe, casing pipe, and drill pipe. The drill pipe is the actual hole while the outer two areannulus formed around the inner pipe. Any one of these under varying conditions can be a sourceof through which oil or gas can escape during drilling. The annular preventer is a valve that appears
    • Handbook of Fire and Explosion Protectionas a rounded barrel and is positioned on top of one or more other blowout preventers in a preventerstack. The annular preventer seals off the annulus area of the well, the space between the drill pipeand the side of the hole. It could also be used to seal off a well with no drill pipe in it. If a well"kicks",but does not blowout, the annularpreventer allows fluid such as drillingmud to be pumpeddown the hole to control the pressure while it prevents material from coming out. Blowoutpreventers below the annular preventer are called ram preventers because they use large rams -rubber faced steel blocks that are shoved together to seal off a well. They can withstand morepressure than an annular preventer and are the considered the second line of defense. There areblind rams that seal off an open hole and pipe rams which are used to close a hole when drill pipe isin use. There are also shearrams that simplycut the pipe OK Using the shear ram is the last resort,since is will cut the drill pipe and bit and send it down to the bottom off the hole. Blowoutpreventersare operated hydraulically from an accumulatorthat should be located as remotely fromthe wellhead as practical. The control panel for activationshould be readily available at the drillingoperations and in some cases (such as offshore) a duplicate activation panel is provided at othercritical emergencycontrol points.The most common cause of a well to become uncontrolled and develop into a blowout is impropermud control operations and the inability of the blowout prevention system to contain it because ofsystemfailures, i.e., lack of testing and maintenance.Once a wellhead fire exists it is best to allow the well itself to keep burning to alleviate explosionhazards and pollution concerns until the well itself can be capped or plugged. Adjacent exposures,especially other wellheads, if in close proximity, should be cooled. Testing by research laboratoriesand operating companies indicates that the fire and heat radiation of a wellhead incident can beconsiderably lessened when the water spray provided immediately at the wellhead is directedupwards instead of downwards. Figure 12 shows the general results of tests conducted in the late1980s that indicated the most efficient water spray geometry consisted of nozzles spraying parallelto the flame axis based on the mass flow rate of water (Mw) to the mass flow rate of the releasedgas (Mg).
    • Special Locations, Facilities and Equipment 233RELATIVE EFFECTIVENESSOF VARIOUS SPRAY ARRANGEMENTSAT WELLHEAD FLAMESFigure 12
    • 234 Handbook of Fire and Explosion ProtectionIt is also interesting that in 1970 Chevron pleaded "no contest" to charges of "knowingly andwillfilly" failing to install safety devices on 90 oil wells in the Gulf of Mexico. Three other oilcompanies were similarlycharged with the same offense (Shell, Conoco and Humble). At the timeChevron was fined $ 1 million U.S. dollars for 500 violations under the Outer Continental ShelfLands Act. The violations involvedfailureto install safety chokes at the wells - i.e., a method to cutoff the flow of oil automaticallyin the event of incident.Loading FacilitiesLoading is one of the most hazardous operations in themanufacturing and handling of hydrocarbon commodities. These ,facilities represent a strategic point in the process that, if lost, mayadversely affect the entire operation of the facility. Pipeline transport is the preferred method ofmaterial transport but cannot be accommodatedin instances where smaller quantities are involved ortrans-ocean shipment is required. The most obvious hazards with loading facilities is the possibilityof overfilling, displacement and release of combustible vapors, concerns with static buildup, andcollisionswith the transferringfacilitiesand the carrying vehicle (primarilyships, barges or trucks).Loading facilities should be sited where the shipping vehicles will not be exposed or expose otherprocesses during or traveling to and from the loading devices. All manual loading facilities should beprovided with self closing valves. A method for emergency isolation of product flow and transferpump shut down should also be consideredfor all facilities.The primary area of protection should be centered around the fixed equipment at the product transferarea, the highest probable leak or spillage location. These include the loading arms, hoses, pipeconnections and transfer pumps. Protection of the fixed equipment ensures rapid restart after theincident with limited business interruption. Of secondaryimportanceis the protection of the transfervehicle (ship, rail or truck). The most critical of these are large shippingvessels where considerablemonetary loss would be incurred. The immense size of some shipping vessels and loadingarrangementsmake protection of the completevessel impractical. Risk analyses of shippingincidentsgenerally indicate the probability of immediate complete vessel fire involvement a low probabilityversus the possible destruction from internal vessel explosions from vapor accumulations duringdeballasting.The most practical protection method for protection of ship and rail loading facilitiesis through fixedmonitors. Due to the relatively smaller size of truck loading racks and liquid spillage accumulationthey are normally protected with an overhead foam water general area deluge system supplementedwith nozzles directed at high leakage points. Some truck loading facilitieshave been protected withlarge fixed dry chemical systemswhere the water supplieshave not been adequate.Electrical Equipment and Communication RoomsFacilities that are located in hazardous areas are usually kept pressurized to prevent the egress ofhazardousvapors and keep the interior ofthe facilityas non-classified electrically.Switchgearand relay rooms are required to have smoke detection per NFPA 850, section 5.8.4andIEEE 979, section 2.7. The activation of the fire alarm should shut down the air handling system.If the facility is especiallycritical to the continued hydrocarbonprocess considerationof a fixed fireprotection system should be evaluated.
    • Special Locations, Facilities and Equipment 235Combustible gas detection for air intakes should be considered when the enclosures are inproximity to hydrocarbon processes. This is especially important when the processes can bedemonstratedto be within areas where a WCCE release will not have dissipated at the distancethefacilityis placed from it. An alternativeis to have the air handling system self circulating so it doesnot direct fresh air supplies in from the outside. Such systems are normally provided at unmannedshelters.Battery RoomsBattery rooms are provide for back up and uninterruptedpower supplies(UPS), for process controlfunctions. They are usually provided at or near the facility control room or electrical switchgearfacilities. Lead acid batteries when charged produce free hydrogen as a by product. The hydrogenis vented from the batteries and released into enclosure. IEEE 484-1987, Section 5.1.4and NFPA850, Section 5-8.5,classifybattery rooms as nonhazardous (per NFPA 70, Article 500) if adequateventilation is provided to the enclosure. Adequate ventilation defined by NFPA 850 is that lessthan one percent hydrogen will accumulate in the room at any one time. IEEE defines adequate asless than 2% hydrogen of the total volume of the battery area. The maximumhydrogen gas releaserate during charring is 0.000269 CFM per charging amphere per cell at 25 OC (77 OF), at oneatmosphereof pressure.Typical industry practice is to provide an explosionproofrated exhaust fan in the exhaust systemfor the battery room and classify the exhaust duct and a radius of 1.5 meters (5 ft.) from theexhaust vent outlet at Div. I, Class 2 Group B. The light switch for the facility should be locatedoutside the battery room.Where drainage provisions are provided to the battery room, the fluid should first collect into aneutralizingtank before enteringthe oily water sewer system(OWS).Where sealed and unserviceable batteries are used, these requirements do not apply since no freehydrogen is released.Fire detection capability is considered optional as the batteries themselves have little combustiblematerials and only a limited amount of cabling or charging equipment is normally provided.Therefore a fire incident is considered as having a very low probability of occurring.Enclosed Turbines or Gas Compressor PackagesTurbines and gas compressors are normally provided as a complete assembly in an acousticalenclosure. Because the equipment is enclosed and handles gas supplies, it is a prime candidateforthe possibility of a gas explosion and fire.The most obvious source a gas accumulationis a fuel leak. Other rare losses have occurred due tolubrication failures, causing the equipment to over heat, with subsequent metal fatigue anddisintegration. Once disintegration occurs heat release from the combustion chamber will occuralong with shrapnel and small projectiles which will be thrown free from the unit from inertiamomentum of the rotating device.Most enclosures are provided with a high interior air cooling flow that is also helpful to disperseany gas release. Combustiblegas detection is provided in the interior of the enclosure and at the airexhaust vent. Fixed temperature devices are also installed.The prime method of protection from a gas explosion in the enclosureis through gas detection and
    • 236 Handbook of Fire and Explosion Protectionoxygen displacement or inerting. C02 or in the past Halon fire suppression systems have beenused as the inerting and fire suppression agents. The agents are stored outside, at a convenientlocation, and applied to the appropriate hazard. ESD signals shut off the fuel supplies to theturbine once an incident occurs. Of critical importance is integrity protection to the ESD fie1isolation valve and its control fromthe incident itself.A one hour fire wall or "substantial space" should be provided between the turbine and gascompressor. The utilization of explosionblow-out panels in the acoustical enclosure will also limitdamage from an explosion. Although strengthen panels could be provided to protect againstshrapnel ejection, the cost installation coupled with the low probability of such an occurrence andthe low personnel exposure periods, generallyrender this a non-cost effective safety improvement.Heat Transfer SystemsHeat transfer systems are normally provided to utilize availableprocess heat, to economizeheat fordistillation purposes or to preheat fuel supplies before usage. They are generally considered asecondaryprocess support system to the main production process, however they may be so criticalto the process that they might be considered a singlepoint failure if not adequatelydesigned.Most heat transfer systems are of a closed loop design that circulates a heat transfer mediumbetween heaters and heat exchangers. Circulation pumps provide flow and regulating valves areused for process control. The heat transfer medium is usually steam, a high flash point oil, or inprocess plants flaniniable liquids and gases. Inherently steam is a safer medium to use and ispreferred over other mediums. When steam supplies are unavailable high flash point oils (organicor synthetics) are sometimesused.For oil systems, commonly referred to as Hot Oil systems a reservoir is sometimes provided in anelevated storage tank. The fire risks associated with the Hot Oil systems comprisethe temperatureof the circulating oil, location of transfer pumps and protection of the storage reservoir. Thecirculating oil may be heated to above its flash point, therefore producing a "flammable"liquid inthe system rather than a combustible liquid. This may be hrther compounded by the fact thecirculating system (i.e., pumps, valves, and piping) may also eventually reach temperatures abovethe flash point of the combustible circulating oil (through conduction with the circulating oil), soany leak may be immediately ignited.SmallHot Oil systems are sometimes provided as a prefabricated skid package with pumps, valvesand elevated oil storage on the same skid. Any leak from the circulating pumps will immediatelyendanger the components on the skid and storage tank. The circulating pumps seals are usuallysource of leakage on the system. Leakage of the medium being heated, usually low flash pointhydrocarbons, into the Hot Oil systems occurs on occasion, further increasing the fire riskunexpectedly. Such leakagesmay precipitate considerablelow flash point hydrocarbon liquids suchthat the Hot Oil eventually takes on the characteristicsof a flammable liquid, essentially creatingmajor fire risk, akin to a process vessel operation instead of an inherently safe heat exchangesystem. Should leaks should be immediatecorrected and a means to degas the system should alsobe incorporated.If the system itself is critical to production opeiation, the pumps may be the most siriglc ci tticalcomponents. They should be adequately located away from other process risk and provided withtypical drainage facilities (containment curbing, surface grading, sewer capability, etc ). Thecollapse of the storage tank should be analyzed to determine what impact it would have on the heattransfer system and the surrounding facilities to the determine the exact needs for fireproofing.Normally if the storage tank is within the risk of other hydrocarbon fire hazards or if its storagetemperature is above its flash point its structural supports should be fireproofed. Otherwise
    • Special Locations, Facilities and Equipment 237fireproofing of the supports may not be economicallyjustified. Considerationshould also be givento designthe amount kept in storage to the minimal amounts.Cooling TowersCooling towers provided at most process industries are typically constructed of combustiblematerials. Although abundant water flows through the interior of the tower, outside surfaces andsome interior portions remain totally dry. During maintenance activities most cooling towers arealso not flowing and the entire unit may become dry. The principal causes of cooling tower firesare electrical defects to wiring, lighting, motors and switches. These defects may in turn igniteexposed surfaces of the dry combustible structure. On occasion hydrocarbon vapors are releasedfrom the process water and are ignited. Exposures from other fires may also cause destruction.Since cooling towers are designed to circulate high flow rates of air for cooling, they also willincreasethe probabilityof an electrical hot spot ignitionto a wooden combustible surface.NFPA 214, "Water Cooling Towers", provides guidance in the design of fire protection systemsand protective measures for cooling towers constructed of combustible materials. Specificprotection for the interior of the cooling tower combustible materials but also for the probablesource of origination @e., motors) should be made. Where they are critical to operations, asprinkler system is usually provided otherwise fire hose reels or monitors are installed. Highcorrosion protection measures must be considered whenever a sprinkler system is provided for acooling tower due to the interior environment of the cooling tower which is ideally suited forcorrosion development to exposed metal surface. There is an increasing industry trend to usenoncombustible materials of construction for the installation of cooling towers due to their firehazard characteristicsand high maintenancecosts associatedwith fire protection measures.Oil Filled TransformersTransformers filled with combustible oils pose a fire hazard. Transformers should be adequatelyspaced from other critical or manned facilities per the requirements of NFPA 70 and IEEE.Adequate containment and removal of spillages should be provided. Spillage immediately at atransformer should drain into a gravel covered basin which prevents spillage from being exposedbut allows drainageto be collected.Depending on the criticality and value additional fire suppression systems are provided forprotection. NFPA 850 section 5-8.6 recommendsthat oil-filled station and start-up transformersatpower generationplants be protected with a water or foamwater spray system. The most commoninstallationis a fixed water spray. Where severaltransformers are provided, a firewall is commonlyused to separateand protect one unit from another.Hydrocarbon Testing Laboratories (including Oil or Water Testing, Darkrooms,etc.)Laboratories are normally classified nonhazardous locations if the quantities of flammable andcombustible liquids are within the requirements of NFPA. Normally a vapor collection hood isprovided when sampling and measurements are conducted with exposed liquids. The primaryconcern is the exhaust of vapors and the storage and removal material saturated with liquids. Theexhaust hood, ducting and a radius of 1.5meters (5 ft.)from the exhaust vent should be consideredan electricallyclassified area.
    • 238 Handbook of Fire and Explosion ProtectionWarehousesWarehouses are normally considered low risk occupancies unless high value or critical componentsare stored. Some high valve components normally overlooked in warehouses are diamond(industrial grade) studded drill bits or critical process control computer boards. In these cases theeconomic benefits of installing an automatic sprinkler system should be investigated.Cafeterias and KitchensWet 01-dry chemical fixed suppression systems are typically provided over the kitchen cookingappliances and in exhaust plenums and ducts. Activation means is afforded by fusible links locatedin the exhaust ducts/plenums usually rated at 232°C (450°F). Manual activation means should notbe provided near the cooking area, but in the exit routes from the facility. The facility fire alarmshould sound upon activation of the fixed suppression system and power or gas to the cookingappliances should be automatically shut off. The ventilation system should also be shut down bythe activation of the fire alarm system. Protective caps should be provided on the suppressionnozzles to prevent plugging horn grease or cooking particulates.
    • Special Locations, Facilities and Equipment 239Bibliography1.2.3.4.5.6.7.8.9.10.11.12.13.14.15.16.17.Chauvin, M.R. and Bourgoyne,Jr., A. T., An Experimental Study of Suppressionof Obstructed Gas Well BlowoutFires Using Water Sprays, NBS-GCR-88-547, National Bureau of Standards (NBS), Center for Fire Research,Gaithersburg,MD, 1988.Crawford,J., OffshoreInstallationPractice, Butterworths,London,U.K., 1988EDM Services Inc., Hazardous Liquid Pipeline Risk Assessment, California State Fire Marshal, Sacramento, CA,1993.French Oil and Gas Industry, Blowout Prevention and Well Control, French Oil and Gas IndustryAssociationEditions Technip, Paris, France, 1981.Gas ProcessorsAssociation(GPA),Gas Processing Facility Safe&InspectionChecklist, GPA, Tulsa, OK, 1987Gowar,R. G., Develoomentsin Fire Protection of OffshorePlatforms,Applied SciencePublishers,London, 1978Grouset, D. et. al., "BOSS: Blow Out Spool System", Fire Safety Engineering, Second International Conference,pages 235-248, BHRA, Cranfield,UK, 1989.Instituteand Instituteof Electricaland ElectronicEngineers, Inc. (IEEE), IEEE Std. 484. RecommendedPractice forInstallationDesign and Installationof large Lead Storage Batteries for Generating Stations and Substations, IEEE,New York,NY, 1987.Instituteof Electrical and ElectronicEngineers. Inc. (IEEE), IEEE Std. 979-84. Guide to Substation Fire Protection,IEEE,New York, NY, 1988.Littleton,J. "ProvenMethods Thrive in Kuwait Well Control Success", PetroleumEngineer International,pages 31-37, January 1992.National Fire Protection Association (NFPA), NFPA 37. Installation and Use of Stationan, Combustible Enginesand Gas Turbines,NFPA, Quincy,MA, 1994.National Fire Protection Association(NFPA),NFPA 45, Fire Protection for LaboratoriesUsing Chemicals,NFPA,Quincy,MA, 1991,NationalFire ProtectionAssociation(NFPA),NFPA 69. ExplosionPrevention Svstems,NFPA, Quincy,MA, 1992.National Fire ProtectionAssociation(NFPA),NFPA 214. Water Cooling Towers,NFPA, Quincy,MA, 1992National Fire Protection Association (NFPA), NFPA 850. Fire Protection for Electric Generating Plants, NFPA,Quincy, MA, 1992.Paterson,T., OffshoreFire Safety, Penwell PublishingCompany,Houston, TX, 1993Pedersen, K. S., STF88 A83012. Fire and ExplosionRisks Offshore. The Risk Picture, SINTEF,Tronhiem,Norway, 1983.
    • Chapter 21Human Factor and Ergonomic ConsiderationsHuman factors and ergonomicsplay a key role in the prevention of accidents. Sometheories attribute up to90% of all accidentsare caused by human factor features. It is therefore imperative that an examination ofhuman factors and ergonomics be undertaken to prevent fire and explosions at petroleum facilities sincehistorical experiencehave also shown it is a major contributor either as a primary or underliningcause.Human factors and ergonomics concern the ability of personnel to perform their job functions within thephysical and mental capabilitiesor limitationsof a human being. Human beings have certain tolerances andpersonal attitudes. Tolerances can be related to the ability to accept information, how quickly theinformation can be understood and the ability and speed to perform manual activities. When information isconfbsing, lackingor overtaxing,the ability to understand and act upon it quicklyor effectivelyis absent. Itis therefore imperative to provide concise, adequate and only pertinent information to do all the tasksassociated with petroleum activities. This includes activities associated with emergency fire and explosionprotection measures.Attitudes reflect the leadership of management or personnel traits of the employees and if not constuctivecan lead to negative influenceswhich can precipatate accidents.It should also be realized that it may be virtually impossible to eliminate human errorsfiom occurringand therefore additional safeguardsare alwaysnecessary. Personnel mayforget, become conhsed or in some cases, are not admittedly knowledgeable in thetasks at hand, especiallyduring stressful environments. It is therefore usefil in criticaloperations to design systems that might not only be specified as fail-safe, but also beconsidered foolproof, This applies to not only to the design of the system foroperation but for maintenance activity periods, the time when most of the historicallycatastrophicincidentshave occurred.A human error or reliability analysis (HRA)can be performed to identify points that may contribute to anaccidental loss. Human errors may occur in all facets of a the hydrocarbon industry. They are generaIIyrelated to the complexity of the equipment, human-equipment interfaces, hardware for emergency actions,and procedures for operations, testing and training. The probabilities of certain types of errors occurring arenormally predicted as indicated in Table 29. Individualtasks can be analyzed to determine the probability ofan error occurring. From these probabilities, consequences can be identified which deterdine the risk of aparticular error.240
    • Human Factor and Ergonomic Considerations 241Probability DescriptionProcesses involvingcreativethinking, unfamiliar operations, aIshort period of time, or high stress.1.0 - 0.10.1 - 0.010.01 - 0,0010,001 - 0.00010.0001 - 0.00001Errors of omission, where dependenceis on situationcues andmemory.Errors of commission,i.e. operatingwrong button, readingwrong display,etc.Errors regularlyperformed in commonplacetasks.Extraordinaryerrors for which it is difficult to conceivehowthey might occur, occurringin stress free environmentswithpowerfUl cues.Table 29Probability of Human ErrorsDrug and alcohol influences will also contribute to an accidental event occurring. Locations where strictcontrols or testing for such influenceshave a relatively lower level of accident occurrences.
    • 242 Handbook of Fire and Explosion ProtectionHuman AttitudeThe single most influenceeffect of human performance is attitude. Attidtude is the mind set, point of viewand the way we look at things. The way we look at things is the partly responsible for the nature of ourbehavior and performance. Some of the more common attitudes which influence accidental behavior arelisted below:AttitudeApathy or IndiffernceComplacencyHostilityImpatienceImpulsivenessImpunityInvulnerabilityNegligenceOverconfidenceRebelliousnessRecklessnessNo OwnershipDescriDtion and ConseauencesSluggish, dont care, passive, not alert. Such attitude has a detrimentalaffect on co-workers in that it can infect the entire organization.Satisfied, conte t and comfortable. This happens when things are goingsmoothly. The workers then drop their guard and become vulnerable.Getting angry or mad. Chip on the shoulder and argumentative,sometimes sullen. Vision narrows and they become victims of unseenhazards.Hasty, hurried and anxious.wouldn not normally do.especially if peer pressure is involved.Impatience makes you do things youThis increases the risk taking mentality,Spontaneousor spur-of-the-meonent. This is the risk taking activity andcan activatethe act first and ask questionslater attitude.No penalty or consequence, it can$ happen to me.sanctions.Immune fromInvincible, superman complex. Invulnerabilityis an illusion that does notrecognizereality.Lax, remiss or not prudent. This is a failure to do what should be doneor deliberately doing what should be done. Forms the basis of mostnegative legals actions.Brash, risk taker. May take short cutsDefiant, disobedient, rule breaker. Often in hostile nature. Difficult towork with.Irresponsible, not trustworthy or reliable, often self centered. A risktaker.No personal stake in anything. This is the opposite of accountability.The treatment for most of these attitudes is the developement of an effective loss prevention team culturewithin the company, (i.e,, led by senior management, with employee involvement), that demostrates themutual benefits of an accident free environment.
    • Human Factor and Ergonomic Considerations 243Access and AcceptabilityFire fighting equipment should be mounted at heights that are easily accessibleby the average person. Thisincludes portable fire extinguishers, hose connectionsto fire hydrants, access to emergency shutoff valves,emergencystopESD push buttons, etc.Process control, valves and control panels should be easily accessibleand viewable. ASTM standard F-I 166provides graphical charts for the physical means to view and operablecontrols and instruments.Instructions, Markings and LabelingThere are six basic categories of signs. These are normally considered the following:Fire Fighting - Those givinginformation or instructionsabout fire.preventionand fire fightingequipment (e.g.,No Smoking,no open lights, etc.).0 Mandatory - Those giving instructionor informationthat must be obeyed or observed (e.g.,security).0 Emergency - Those giving instructionsto be followed in case of an emergencyWarning - Those giving informationthat should be heeded to avoid possible dangerousoccurrences(e.g.,toxic gas).0 Prohibition - Those that prohibit a particular activity (Le., no horseplay)0 General - Those that convey general informationof a non-critical nature not covered by thefive categories above.Instruction signs should be posted at all emergency systems in which the operation of the unit is notinherentlyobvious (i.e., fire pump startup, fixed foam systems, etc.). Flow arrows of water flow should beprovide on piping where the isolation means is provided. Number of hydrants, monitors, pumps, foamchambers can all enhance the operational use of such equipment. Control panel labels should be providedwhich are descriptive instead ofjust numericalidentifications.Warning and instructional signs and instruction should be primarily provided in the national language of thecountry of operation. They should be concise and direct. Use of jargon, slang or local dialect referencesshould always be avoided, as these may not always be correctly interpreted. Abbreviations should beavoidedunless the abbreviationis commonly known and used by the population, versus the descriptivewordor words.Labels shouldbe as precise as possible without distorting the intended meaning or information. They shouldnot be ambiguous, use trade names, company logos or other information not directly involved forperformingthe required functions.The following are common problems that may be faced in hydrocarbon facilitiespertaining to labeling:- Poor or missing labels.- Similarnames are used which may be confbsed.- Suppliedlabels not understood.-Labels are not provided in a consistentformat.- Labels (ie., equipment) are not specifiedin a sequentialor logical order.
    • 244 Handbook of Fire and Explosion ProtectionColor and IdentificationColorsStandard colors have been adopted in the industrial world for the identification of physical hazards, markingof safety equipment, and operating modes of typical equipment. These conventionshave been incorporatedinto standardsused worldwidefor the recognition of such devicesand are categorizedby the following colorcoding.Table 30Color Coding ApplicationsThe colors purple, brown, black, and gray have not been assigned a safety connotation. Specific color codesare also employed in the identificationof alarms panel indicators, piping, compressed gas cylinders, electricalwiring, fire sprinkler temperature ratings, etc. Although these sometimes do not correspond with similarmeanings.
    • Human Factor and Ergonomic Considerations 245It should also be mentioned that there may be slight confusion by certain color indicatinglamps or button bythe industry. Typically the industry uses red for hazardous running conditions (e.g., operating a pipelinepump) versusthe common traffic signal of red for stop and vice versa. Red is also used as the color of ESDpush buttons to stop an operation. On the face value it appears that this is a conflict of meanings. If theoverall meaning of hazardous versus safe is kept in mind then the colors have more relevance. NFPA 79provides definition of when a particular color is used, however this may be slightly confusing to personnelnew to the industry as the exampleof red above highlights.Numbering and IdentificationProcess instrumentation displaysshould be arranged in relation to each other according to their sequence ofuse or functional relationshipto the componentsthey represent. They should be arranged in their functionalgroups, whenever possible, to provide a viewing flow from left to right or from top to bottom.Process vessels and equipment should be provided with identification in the field that is legible fromapproximately30 meters (100 ft.) away. It should be viewable from the normal access points to the facilityor equipment and is of colors contrasting with the surrounding background. The identifications normallyconsist of the equipment identification number and the common name of the equipment, e.g., "V-200,Propane Surge Drum". This is beneficial during routine and emergency periods where the quickidentificationof process equipment is critical and necessary from a distance.Instrumentation Alarm OverloadProcess alarms should be arranged to provide a major common alarm that is supplemented by an individualindicator, e.g., a master alarm should be provided to indicate the status of the entire subsystem components.Multiple simultaneousalarmsthat can overload the sensesof an operator shouldbe avoided.Noise ControlHigh noise levelsemitted by facility equipment can damage the hearing of personnel working at the plant, bea nuisance to the local community,and interferewith the annunciation of emergency alarms and instructions.The principle sources are rotating equipment (pumps, compressors, turbines, etc.), air-cooler fans, furnacesor heaters, vents and flares. Noise levels may be extremely high during an emergency due to operation ofrelief systems, depressurization,blowdown and ffare systems operating at their maximum capacitieswithoutadequatemeasures to control the ambient noise levels.Distance is a major factor in reducing nuisance noise and suitable spacing should be considered in the plantinitial layout. The acceptable amount of noise generation should be specified on the purchase order for theequipment. Where sound levels cannot be alleviated by purchasing a different make of equipment, soundattenuationdevices shouldbe fitted (i.e.,enclosures) as an alternative.Whenever ambient noise levels are above emergency alarm signalsor tones, flashinglights or beacons shouldbe considered that are visible in all portions of the affected area. The color of flashing lights should beconsistent with the safety warning colors adopted at the facility.
    • 246 Handbook of Fire and Explosion ProtectionPanicPanic or irrational behavior is likely to be generated during any hydrocarbon emergency. It is the result ofunfamiliarity, conhsion and fright. Panic affects individuals in different irrational outcomes. Panic mayexacerbatethe consequencesof an explosion or fire incident in relation to the function of or lack of functionby the responsiblepersonnel. It has been observed to affect personnel in the followingways:It may produce illogical or indecisive actions to control or minimize an incident, for exampleopeningthe wrong valve or failureto activate process emergencycontrols or instructions.Personnel may impede escape mechanisms by using the wrong routes, not being organized fororderly evacuation,etc.0 It may produce hyperactivity in personnel.irritantsor toxic gases present.Hyperventilation will exacerbate the effects of0 Personnel required to perform emergency hnctions may just freeze or become unable toundertake decisive actions. Without decisive action they will succumb to the ever increasingeffects of an incident.Training,clear instructionsand personal self assuranceare ways to prevent or minimized the effects of panic.Personnel should be trained for all reasonable emergencies with adequate written generic procedures.Regular training for emergencies and evacuation should familiarize personnel with emergency events andprocedures. During an emergency, adequate instructionsshould be issued to all personnel. Mechanismsthatcan be automated once an emergency has been realized should be considered in order avoid the "humanelement".SecurityUnfortunately most hydrocarbon facilities are key political instruments for internationalaffairs. Numerous terrorist activities have been directed towards these installations,either as figurative demonstrations or for real intent of destruction. Additionallyindustrialfacilitiescan become the target of labor unrest.Management should consider these threats are real and consider contingency planningfor major events similarto accidental hydrocarbonincidents. Key isolation and shutdownmechanism shouldhave the utmost integrity where shut threats are realized.Facilitiesshould be provided with appropriate barriers to prevent unauthorized entries to the general publicand employeesnot required to be put at risk from their normaljob duties.Accommodation of Religious FunctionsIn some parts of the world religious fhctions may occur several times a day and every day of the week.These hnctions are generally required to be performed at the immediate location of an individual. Theseactivities must be respected and accommodated for the employees and any personnel who may be inattendanceat the facility. Typicallywhere hydrocarbonfacilitiesare located in areas were such practices areperformed, a specialized installation (ie., mosque) is normally provided. The primary concern in theirapplicationis that the installation does not interferewith the operation of the facility, is not provided withinthe confines of a hazardous location (i.e., process location), and that it is shielded or removed from theeffects of an explosion or fire. Typical applications provide these specialized facilities just outside thesecurityfencing and accessgate a facility.
    • Human Factor and Ergonomic Considerations 247Bibliography1. AmericanNational StandardsInstitute (ANSI),A13.1. Schemefor the Identification of Piping Systems,New York,NY, 1993.2. AmericanPetroleumInstitute (API), Standard615, SoundControl of MechanicalEquipment for Refinew Services,API, Washington, D.C., 1987.3. American Petroleum Institute (API), Publication 1637 Usin? the API Color Code Svstem to Mark Equiument andVehiclesFor Product Identification at Service Stations and Distribution Terminals, First Edition,API, Washington,D.C., 1986.4. American Societyof Testing Materials (ASTM), F-1166-88. Standard Practice for Human Engineering Design forMarine Svstems,Eauiument and Facilities,ASTM, 1988.5.6.British StandardsInstitute(BSI), BS 1710,PipingIdentificationColors, BSI, London,U.K.British StandardsInstitute(BSI), BS 5266 Emergencv Lighting,BSI, London,U.K.7. British StandardsInstitute(BSI), BS 5378: Parts 1.2. and 3: SafetvSignsand Colors, BSI, London,U.K.8. British StandardsInstitute(BSI), BS 5395. Stairs. Ladders and WalkwavsPart 3. Code of Practicefor the DesignofIndustrialTwe Stairs.Permanent Laddersand Walkways,BSI, London,U.K., 1985.9. British StandardsInstitute(BSI), BS 5499: Fire SafetvSigns.Notices and Grauhc Svmbols,BSI, London, U.K.10. Electronic Industries Association (EIA), EIA 230-59. Color Marking of Thermoplastic Covered Wire, EJA,Washington,D.C., 1981.11. Health and SafetyExecutive(HSE), Booklet HS(G)48, Human Factorsin IndustrialSafetv. HMSO. London,U.K.12. Illuminating Engineering Society of North America (IESNA), -, IESNA, New York, NY,1991.13. Illuminating Engineering Society of North America (IESNA), Lighting Handbook, (Chapters 20 & 33), IESNA,New York, NY, 1991.14. International Organization for Standardization(ISO), IS0 508:1966, Piping Identification Colors, ISO, Geneva,Switzerland, 1966.15. InternationalOrganization for Standardization(ISO),IS0 1503:1981,ErgonomicPrinciples of the Design of WorkSystems,ISO, Geneva, Switzerland, 1981.16. International Organization for Standardization(ISO), IS0 6309:1987 Fire Protection - Safetv Sims, ISO, FirstEdition, Geneva, Switzerland,1987.17. International Organization for Standardization(ISO), ISO, IS0 8995:1989. Principles of Visual Ergonomics - Thelightingof Indoor Work Systems,Geneva, Switzerland, 1989.18. Miller, G. E., “The Omission of Human Engineering in the Design of Offshore Equipment and Facilities, HowCome?”,OTC 6481,22ndAnnual Offshore TechnologyConference,Houston, TX, 1990.19. National Electrical ManufacturesAssociation,ANSI 2535.1-1991, Safetv Color Code, NEMA, Washington,D.C.1991.20. National Fire Protection Association (NFPA), NFPA 79 Electrical Standard for Industrial Machinery, NFPA,Quincy,MA, 1991.
    • 248 Handbook of Fire and Explosion Protection2 1. Woodsen,W. E., Human Factors Design Handbook,McGraw-Hill Inc.,New York, NY, 1981
    • APPENDIX ATESTING FIREWATER SYSTEMS249
    • 250 Handbook of Fire and Explosion ProtectionAppendix A.lTesting of Firewater Pumping SystemsThe following is a generic test procedure that may be used to achieve flow performance tests of fixedfirewaterpumps. The purpose of this procedure is to provide operationsand engineeringpersonnel,the basicsteps and engineeringknowledge to adequately and efficientlyperform the performance testing that may benecessary by company polices and procedures. The procedure should be revised and modified to suit theparticular facility equipment under evaluation by adding identification numbers and locations as appropriateto highlight the exact items and valves set ups that are necessary. The procedure should be according tolocalwork permit procedures.Testing periods should be arranged with the appropriate management of any installation through theapproved work orders or permits of the facility. Careful observationsof the equipmentunder test should bemade to observe any abnormalities and signs of impendingfailures. The operational testing area should berestricted to the personnel solely involvedwith the testing.Normal fire protection practices and standards recommend fire pumps be tested annually to determineperformancelevels. Commonpractice in the petroleum industry is to trend the result of flow performance toprepare predictive maintenance and replacement forecasts. Such forecast can predict poor pumpperfoniianceand prepare measures to implement correctiveactions before this occurs.Basic Procedure1. Obtain the manufacturers pump curve for the unit to be tested. Confrm the pump to be tested isproperly identified,i.e.,veri@nameplatetag number, serial number, etc.2. Ensure that calibrated pressure gages 0 - 1,380 H a (0-200 psig) are installed on the suction anddischarge of each fire pump to be tested. (Record calibration dates on the flow performance data sheet).For pumps taking suctionlift calculate the NPSH to the level of pump discharge. Offshore installationsvertical turbine fire pumps require a calculation of vertical head loss to the point of pressure readingtaking into account tide levels and seawater densities.3. Determine the flow measurement method to be used during the test, Le., flowmeter or pitot tubemeasures of the nearest available water outlets on the system. Ensure that the flow measurementdevices are calibrated or adjusted for the fire pump maximum flow output.4. Ensure independent measurement devices for verification of the driver (i.e. engine) and pump rpm areavailableand accurate, i.e. strobe light hand held tachometer.5. Ensure the recycle valve is closed if water is to be measured at the local water outlet or the systemdischargevalve is closed if water is to be recycled into storage.6. If relief valve is fitted, verifl piping is rated for maximum pump pressure output, then isolate relief valve7. Open the pump discharge valve approximately50%.only during testing period, if not leave reliefvalve in service during testing activities.8. Start up pump and let run for a minimum of I5 minutes, for stabilization of the mechanical systems.
    • Appendix A Testing Firewater Systems 251Adjust driver (i.e., engine) rpm to operate to the pump as close as possible to its rated rpm per-formance curve.9. Record five pressure (inlet and outlet) and flow readings for the pump near the following rated flowpoints - 0%, 50%, loo%, 125%, & 150%, simultaneously recording the rpm. The time of flow isdependent on assuring adequate stabilization for flow measurement.10. Plot the test points against the rated pump curve adjusted for the rated rpm of the unit. If conditionspermit data should be plotted immediately during the test to indicate abnormalities that may becorrected, e.g., partially closed or open valves.11. Continuous monitoring of engine and pump should be maintained during the test. Special attentionshould be given to the engine gauges, bearings, cooling connections (especially the cooling hoses),expected points of oil leakages and abnormal vibrations. Any unusual readings should be brought tothe attention of the maintenance personnel immediately.Supplemental ChecksFor enginedriven units, a sampleof the fuel supply in the day tank should be taken It should be analyzed forindications of water or sediment contamination. The sample should be allowed to stabilize for 24 hours todetermine content. Entrained water will collect at the bottom of the sample container and hydrocarbonfluidswill collect on top of it. Particulateswill settle to the bottom.Verify not leakages of oil or water for engine driven units.connectionsfor water cooling and fuel supplies.Especially check condition of flexibleVerify pump start up on low pressure indication if such capabilityis fitted.CorrectionFactors for Observed Test RPM to Rated RPM of DriverFlow at Rated RPM = (Rated RPWObserved RPM) x (Observed Flow Rate)Net Pressure at Rated RPM = (Rated RPWObserved RPM)2 x (Net Pressure)
    • 252 Handbook of Fire and Explosion ProtectionTypical Data Form for Fire Pump TestingSUPPLEMENT FIRE PUMP TEST INFORMATIONPUMP NO.LOCATION:DATE OF TEST:By:TIDE Feet or MeterCorrection for GPM: --------RATED RPMPUMP RPMX GPM = CORRECTION FACTORCorrection for PSI: --------RATEDRPM2 X PSI = CORRECTION FACTORPUMPR P M ~TEST POINT CORRECTION TEST POINTSGPM X CF( )=CORR. GPM 1 . 2 . 3 . 4 . 2 . 6 .PSI X CF( )=CORR. PSl1-2-3.4-5-6-NOTE: Each Change in Pump Speed requires calculating a new correction factor.DRIVER: PERFORMANCE Smooth RoughTemperature Low- Normal- High-Fuel Level 114 112 34 FUUNote any unusual noise, smoke,or mechanicalcondiionFuel Sample Clean- Dirty-Water- OtherCommentsRIGHTANGLE DRIVE: Smooth RoughCommentsPUMP PERFORMANCE:Flow: YoAbove % Below Rated CurvePressure: % Above % Below Rated CurveComments
    • Appendix A Testing Firewater Systems 253Supplemental data pump testing formFIRE PUMP TEST REPORTLocationFrne: StartstopCALIBRATION DATES:PUMP DRIVERNo. Mlg.Mfg. TypeType PowerRating Engine HoursRPM Gear RatioGages Flow Meter PSV-PSV Setting PSI BAR10 m m u1 Y) M m 80 Po IW 110 120 la IUI iw im im 180GPMPERCENT RATE CAPACITY
    • 254 Handbook of Fire and Explosion ProtectionAppendix A.2Testing of Firewater Distribution SystemsGeneral ConsiderationsTesting of firewater distribution systems is accomplishedto determine if the condition of system is adequateto support a WCCE need for firewater. The condition of piping, leaks, existence of closed valves orsediment,operabilityof valves and monitors, etc., shouldbe determined annually.Typically a network of firewater systems mains is provided in a facility that form loops. These can besegregated into sections or legs and the performance of each can be determined by flow test. Flow testsrelease quantitiesof water that are measured and graphed. Performing an initial acceptancebaseline test andrecording the results from year to year can portray the performance of the firewater system and projectionsof the useful life of the system can be determined.The following is a generic test procedure that may be used to perform a flow performance of fire waterdistribution systems.Determine which fire main is to be analyzed. Within this segment select the hydrants that are the mostremote on the system fiom the source of supply. (Most remote is intended to mean the most remotehydraulically and the selected hydrants may not be the most remote physically). A test hydrant and flowhydrant(s) are identified. The data collected will refer to the test hydrant. The flow hydrant is the nextdownstreamhydrant(s) from the test hydrant.It is imperativethat the water in the mains is flowing in one direction only during the test (i.e., from the testhydrant to the flow hydrant). In the case of looped and gridiron mains, the water may be flowing in twodirectionsand then issuingfiom the flow hydrant depending on the particular test being undertaken.
    • Appendix A Testing Firewater Systems 255TEST PROCEDUREMake preparations to conduct the testing - prepare scheduling, coordinate with operations, obtaincalibratedgages, ensurewater flowswill not affect operations, etc.Choosethe Test Hydrant and record the date, time, and location of the test. Remove one of the hydrantoutlet caps and attach a recently calibrated pressure gage fitted with a petcock valve. Slowly open thehydrant and bleed off any trapped through the petcock valve on the pressure gage cap, then close thepetcock valve.Record the reading on a pressure gage as the Fire Flow - Static Pressure. (Leave the test hydrant valveopen).Continue along the main in the direction of water travel to the next hydrant identified as the flowhydrant(s). Remove the hydrant outlet caps and veri@the outlet internal diameter to the nearest 1/16 ofan inch.Determinethe hydrant coefficientof discharge, "C" (See AppendixB.4).Slowly open the hydrant full bore and wait about 30 seconds or longer until the flow is stabilized and aclear streamis established.Insert the pitot flow measuring device into the hydrant water flow, bleed off air from the pitot tube, andthen measure the pitot gage pressure. The pitot tip should be inserted in the center of the water flowstreamat a distanceof one-half diameter away from the outlet of the hydrant.Record the Pitot Gage Pressure. If the gage pressure is oscillating, record the average of the readings.The most accurate results are obtained with pitot readings between 68.9 and 206.9Wa (10 and 30 psi).If the pitot gage readings are higher than this open another outlet on the hydrant and pitot both theflows or close the outlet on the flow until a pitot reading less than 206.9 kPa (30 psi) is obtained.Additional flow hydrants may also be used, ifdownstream of the test hydrant. If more than one outletwas opened "pitot"both outlets and record the pitot gage pressure reading of both outlets.If the pitot gage pressure reading is less than 68.9 kPa (10 psi), then a smooth bore tapering nozzleshouldbe placed on the flow outlet to reduce the size of the opening and increase the flow pressure.Simultaneouslywith the previous step, record the pressure on the test hydrant as the Fire Flow ResidualPressure.If a pressure gradient of the entire system is desired, additional pressure cap gages can be placed alongseveral points of the water main from the source of supply to the flow hydrant and these pressurereadingstaken for each flow measurement.If a second test point is desired, the flow hydrant outlet may be throttled to any desired point and thepitot gage pressure read along with the Fire Flow Residual Pressure. Obtaining a second flow point willimprove the accuracy of the flow test data.If no fkrther test readings are necessary, restore the system back to normal by slowly closing all hydrantvalves and replacingthe outlet caps. Ensure all water has stopped flowing and the hydrant is drained ofwater before replacing the cap.
    • 256 Handbook of Fire and Explosion ProtectionWhen water flow encountersa loop or grid, two features occur - (1) the flow splitsinto a determinableratio,and (2) the pressure drop across each of the two legs will be the same.There are four methodsto test a loop or grid system:Isolate the LegsBy closingthe proper sectioningvalves, the water can be forced to flow through one of the legs only. M e rrecording the appropriate data for one leg, arrange the sectioning valves to isolate and flow the section leg.The two flows can be combined to give the total flow that can be provided through the system (providedthefacilitypumps have the capacityand pressure).Chose Two Hvdrantson a Large MainNormal water paths are always in the direction of least resistance, in other words, generally from the largermains to the smaller mains. By choosingtwo hydrants on a large section of pipe (within a loop or grid) andestimatingthe water flow direction,a test can be conducted.SimultaneousFlowIn a multi-supplysystem in which good pressure and volumes are present, this method is desirable. Choosea symmetricallycentered hydrant (this is the Test Hydrant) and simultaneouslyflow two or three hydrants.Obtain the two or three pitot readings.SingleHvdrant Flow TestThis method uses a single hydrant as the Test and Flow hydrant. Static, Residual and Flow pressures are allread from the same hydrant. This techniqueis considered to produce higher levels of error with the test datathan other methods.
    • Appendix A Testing Firewater Systems 257Preparing Test ResultsThe total flow availableat any point in a system is sometimes stated as the "gpm availableat 137.9kPa (20psi) residual pressure". The 137.9 Wa (20 psi) is a safety factor which fire departments or company firebrigades should be well aware so as not to damage the water mains. Usually most fire water tests arecomparing the results from year to year to determine if deterioration of the mains is occurring (pressuregradient graph) or the availablewater supply and pressure in a particular area for design of a new fixed firewater system. Thereforethe completewater supply graph for a particular is alwaysuseful.Hydrant Flow DataReadily availableflow tables are availablethat provide the amount of flow through a given size orifice, giventhe pitot pressure reading. All pitot flow measurements should be first converted from a pressure readinginto a flow reading and then corrected for the outlet discharge coefficientby multiplying by the appropriatefactor. The results of the individual flow for each hydrant can then be plotted by marking the static pressureat no flow and then the flow at the residual pressure. Connectingthe points provides flows and pressures atany desired point. The graph can be used a visual presentation of all the pressures and volumes that can beexpected at the test hydrant through the water mains.
    • 258 Handbook of Fire and Explosion ProtectionAppendix A.3Testing of Sprinkler and Deluge SystemsWet and Dn, Pipe SprinklersWet and dry pipe sprinklers are not functionally tests for coverage since design codes haveeliminated problems with distribution patterns, provided the installation has been adequately inspected. Thenormal testing verifies adequatepressure is available,piping is not plugged and activationof alarms occurs.Main Drain - a flow of the main drain is accomplishedwhich provides an estimate of the residual systemwater pressure for the system. Condition of the water will also confirm if supplies are clean and driesfiee.Inspectors test - inspector test flows are accomplished on each portion of the system where fitted toensure systemflow can be accomplished.0 Alarm Activation - all systems should be fitted with alarms that will indicateif water flow has occurred.The alarm activationshould occur with the activationof one sprinkler head and usually simulated by thefitting of an orifice at the inspectorstest outlet.Deluge SvstemsA hll hnctional wet test of the deluge system is normally accomplished. This test ensures coverage anddensity patterns are being achieved. A calculated collection pan can be provided during the testing toconfirmthe density rate per minute. The mechanismto activatethe deluge shouldbe tested under conditionsthat will simulateas real as can be reasonably obtained. Where equipment to be protected is not normally inplace, Le., ships, trucks or rail cars, the test should not be conducted until they are in their normal positionduring operations.
    • Appendix A Testing Firewater Systems 259Appendix A.4Testing of Foam SystemsFoam systems are provided wherever there are large quantitiesof liquid hydrocarbonsthat pose a high risk.The primary concern with foam system performance is the proper production of foam and the time toprovide adequate foam sealagecoverageto the designated area.Foam systems are designed to proportion liquid foam concentrate in the foamwater distribution network atcertain ratios usually expressed in percentages. The most common of these are I%, 3%, and 6%. Thefoamwatercan then be aspirated or non-aspiratedto the appropriate liquid surface as the risk demands. Thefoam production should be verified it is being proportion in the ratio designed for the system otherwise foamconsistencymay be inadequate and foam supplieswill be consumed at rates higher than expected.Coverage confirmation, time to provide full foam coverage, leaks, blockages, rupture disk function, age offoam, portioning calibration mechanisms, performance of deliverypumps or bladder tanks, foam drain times,etc. should be verified for each unique system. NFPA 11 provides guidance in the specifictest requirementsfor severalcharacterisiticfoam systems.
    • 260 Handbook of Fire and Explosion ProtectionAppendix A.5Testing of Hose Reels and MonitorsGeneral RequirementsAll manually directed devices should be tested for coverage and range of the water sprays. Flow testingshould uncover shortcomings of water pressure or blockages and proper operation of the device. Windstrength can either enhance or degrade the range of a water spray depending if it is directed upwind ordownwind. Residual pressures should be noted during full flow conditions.Hose ReelsHard rubber fire hoses are usually provided throughout the process area of a hydrocarbon facility. The coilof a hose on a hose reel presents a considerablefriction loss factor to the flow of water through it. In someinstances a fire water hose reel may not be completely unrolled from a reel before its use. Therefore it isprudent to conduct a hose reel flow test with a partial removal of the hose and fhll unreeling from it. Thespray reaches of each scenariocan then be llly evaluated and observed.The ease of unrolling a hose reel to the protected hazard should be tested.MonitorsThe placement of monitors should be cognizant of obstructions. The arc and depth of the spray coverageshouId be confirmed.Where monitors are placed close to hazards, such as at helicopter landing sites, supplement monitor heatshould be considered for operator protection. The heat shield should not obstruct the visor of the operatorand clear heat resistant plexi-glasseshave been used at some installations.Dual coverage for high leak potential areas (e.g., pumps, compressors,etc.) should be verified during actualflow testing.
    • Appendix A Testing Firewater Systems 261Hydrants, and MonitorsStandpipesand9.3.1200 psi* 2 Hours NFPA 14, Section8-4.1Hose ReelsSprinkler Systems 200 psi* 2 Hours NFPA 13, Section 8-2.2.1Deluge andWater SpraySystemsC02 FixedSystems**Drv Chemical**Foam Water* If operationpressure is greater than 150psi, test pressure to be 50 psi above operationalpressure.** Limited to hoses and agent containersNote 3 Piping not to be hydrostaticallytested.Note 4 Hydrotestingof piping is not required.200 psi* 2 Hours NFPA 15, Section 5-2200 psi* 2 Hours NFPA 16, 5-2.1No Mention No Mention NFPA 12See note 3 NIA NFPA 17, Section2-Hydrostatic Test RequirementsWet Chemical**5.4.24.4.2See note 4 N/A NFPA 1 7 4 Section2-
    • BAPPENDIXREFERENCE DATA262
    • Appendix B: Reference Data 263Appendix B.lFire Resistance Testing StandardsThe following is a listing of specific US.industry standards for fire performance testing for specific fireexposuresthat may be appliedin the petroleum industry.API Spec 6FAAPI Spec 6FBAPI Spec 6FCAPI Bull 6F1API Bull 6F2API Std. 589API Std. 607ASTM E-84ASTM E-IO8ASTME-108(Modified)ASTME-119ASTM E-136ASTM E-152ASTM E-162ASTM E-163ASTM E-286ASTM E-648ASTME-662ASTM E-814ASTM E-1529BS 476, Part 4BS 476, Part 6BS 476, Part 7BS 476, Part 10BS 476, Part 11BS 476, Part 20BS 476, Part 22BS 476, Part 23BS 476, Part 24BS 476, Part 31UK HSESpecificationfor Fire Test for Valves, 1994.Fire Test For End Connections, 1992.Specificationfor Fire Test for Valve with AutomaticBackseats, 1994.Bulletin on Performance of API and ANSI End Connectionsin a Fire Test AccordingtoAPI Spec 6FA, 1994.Bulletin on Fire ResistanceImprovementsfor API Flanges, 1994.Fire Test for Evaluationof Valve Stem Packing, 1993.Fire Test for Soft Seated Quarter Turn Valves, 1993.SurfaceBurning Characteristicsof BurningMaterials.Fire Tests of Roof Coverings.Fire Tests of Exterior Walls.Fire Tests of Building Constructionand Materials.Standard Test Method for Behavior ofMaterials in a Vertical TubeFurnace at 750degrees C, 1993.Fire Tests of Door Assemblies, 1981.SurfaceFlammabilityof MaterialsUsing a Radiant Heat Energy Source, 1990.Fire Test of Window Assemblies,Methods, 1984.SurfaceFlammabilityof Building MaterialsUsing a 8 Ft. TunnelFurnace, 1984.CriticalRadiant Flux of Floor Covering SystemsUsing a Radiant Heat Energy SourceNST(NBS) Flooring Radiant Panel], 1993.SpecificOpticalDensity of SmokeGenerated by SolidMaterials N S T (NBS) SmokeChamber], 1993.Standard Test Method for Fire Test of ThroughPenetrationFire Stops, 1994.Standard Test Methods for DeterminingEffects ofLarge Hydrocarbon Pool Fires onStructuralMembersand Assemblies, 1993.Non-combustibilityTest for Materials.Method of Test for Fire Propagation for Products.Surface Spread of Flame Test for Materials.Guideto the Principlesand Applicationo€FireTesting.Method ofAssessingthe Heat Emission from BuildingMaterials.Method for the Determinationof the Fire Resistanceof Elements of Construction(Similar to ASTME 119).Methods for Determinationof the Fire Resistance of Non-load bearingElements ofConstruction.Methods for Determinationof the Contributionof Componentsto the Fire Resistance of aStructure.Method for Determinationof the Fire Resistance of VentilationDucts.Methods for Measuring SmokePenetrationthrough Doorsets and Shutter Assemblies.Department of Energy, HydrocarbonFire Test.
    • 264 Handbook of Fire and Explosion ProtectionIEEE 817IEEE 1202IMOIS0 834IS0 1182IS0 3008IS0 3009IS0 5657IS0 6944NFPA 251NFPA 252NFPA 253NFPA 255NFPA 256NFPA 257NFPA 258NFPA 259NFPA 260NFPA 261NFPA 262NFPA 263NFPA 264NFPA 264ANFPA 268PSOLASUBC 17-4UBC 17-6UBC 42-1UBC 42-2UBC 43-1UBC 43-2UBC 43-4UBC 43-6Standard Test Procedure for Flame Coatings Applied to Insulated Cables inTrays, 1993.Standard for Flame Testing of Cables for Use in Industrialand CommercialOccupancies.1991.Fire Tests for Bulkheadsand Decks.Fire ResistanceTests - Elements of Building Construction, 1975,(similarto ASTM E119).Fire Tests - BuildingMaterials- Non-combustibilityTest, 1990.Fire ResistanceTests - Door and Shutter Assemblies, 1976(1984), (similarto ASTM EFire ResistanceTests - Glazed Elements, 1976(1984), (similar to ASTM E 163).Fire Tests - Reaction to Fire - IgnitabilityofBuilding Products, 1986.Fire ResistanceTests - VentilationDucts, 1985.152).StandardMethods of Fire Tests of Building Construction and Materials, 1990(SimilartoStandardMethods of Fire Tests of Door Assemblies, 1990(similar to ASTM E-152).StandardMethod of Test for CriticalRadiantFlux of Floor Coveriig SystemsUsing aRadiant Heat Source Energy Source, 1990(similar to ASTM E 648).StandardMethod of Test of SurfaceBurning Characteristicsof Building Materials,(similarto ASTM E-84).StandardMethods of Fire Tests of Roof Coverings, 1993 (similar to ASTM E-108).Standard for Fire Tests of Window Assemblies, (similar to ASTM E 163).Standard Research Test Method for Determining Smoke Generationof SolidMaterials(similarto ASTM E 662).StandardTest Method for PotentialHeat of BuildingMaterials, 1993.StandardMethods of Tests and Classificationfor Cigarette Ignition ResistanceofComponentsof Upholstered Furniture 1989.StandardMethods of Tests for DetermingResistanceof Mock-up UpholsteredFurnitureMaterial Assemblies to Ignition by SmolderingCigarettes, 1989.Method of Test for Fire and SmokeCharacteristicsof ElectricalWire and Cables, 1990.StandardMethod of Test for Heat and Visible SmokeReleaseRates for MaterialsandProducts, 1990.StandardMethod of Test for Heat and Visible SmokeReleaseRates for MaterialsandProducts Using an Oxygen ConsumptionCalorimeter, 1992.StandardMethod of Test for Heat ReleaseRates for UpholsteredFurniture Componentsor Compositesand Mattresses Using an Oxygen Consumption Calorimeter, 1990.Ignitabilityof Exterior Wall AssembliesUsing a RadiantHeat Energy Source, 1994.ASTM E-119).StandardFire Test, (Definedin SOLASRegulation 3 Part 2), (Similarto ASTM E-119).Fire Test Standard for Insulated Roof Deck Construction(FM Calorimeter).Evaluationof FlammabilityCharacteristicsof Exterior, Nonload-Bearing Wall PanelAssembliesUsing Foam Plastic Insulation.Test Method for SurfixeBurning Characteristicsof BuildingMaterials (similar to ASTME 84).Standard Test Method for EvaluatingRoom Fire Growth Contributionof TextileWallcovering.Fire Tests of Building Constructionand Materials(similar to ASTM E-119).Fire Tests of Door Assemblies (similar to UL 10B).Fire Tests of Window Assemblies (similarto ASTM E-163).Fire Tests of Through-PenetrationFire Stops (similarto ASTM E-814).
    • Appendix B: Reference Data 265UBC 43-7UBC 43-12UBC 43-13UL9UL 1OBUL 72UL 94UL 155UL 214UL 263UL 555UL 55.54UL 723UL 790UL 910UL 1056UL 1256UL 1479UL 1666UL 1685UL 1709UL 1715UL 1820UL 1887UL 1895UL 1975UL 2043Fire Dampers and CeilingDampers.Smoked Dampers (similarto UL 555s).Horizontal SlidingFire Doors Used in a ExitFire Tests of Window Assemblies, 1989.(similarto ASTM E 163).Fire Tests of Door Assemblies, 1986(similarto ASTM E 152).Tests for Fire Resistance of Record Protection Equipment, 199I ,Tests for Flammabilityof Plastic Materials for Parts in Devices and Appliances, 1991.Tests for Fire Resistance of Vault and File Room Doors, 1990.(similar to ASTM E 152)Tests for Flame Propagationof Fabrics and Film, 1976.Fire Tests of Building Construction and Materials, 1992(similarto ASTM E 119).Fire Dampers, 1990.SmokeDampers.Tests for SurfaceBurning Characteristicsof Building Materials, 1983.(similarto ASTME 84).Tests for Fire Resistance of Roof CoveringMaterials, 1983.(similarto ASTM E 108)Tests for Flame Propagation and SmokeDensity Values for Electrical and OpticalFiberCablesin SpacesTransporting EnvironmentalAir, 1991.Fire Test of Upholstered Furniture, 1989.Fire Test of Roof Deck Constructions, 1985.Fire Test of Through-Penetration Firestops, 1983.(similar to ASTM E 814).Test for Flame PropagationHeight of Electrical and Optical Fiber CablesInstalledVertically in Shafts, 1991.Vertical Tray Fire Propagation and SmokeRelease Test for Electrical and Optical FiberCables, 1992.Rapid Rise Fire Tests of Protection Materials for StructuralSteel, 1989.Fire Test of Interior Finish Material, 1989.Fire Test of Pneumatic Tubing for Flame and Smoke Characteristics, 1989.Fire Test of Plastic SprinklerPipe for Flame and Smoke Characteristics, 1989.Fire Tests of Mattresses, 1991.Fire Tests for Foamed Plastics Used for DecorativePurposes, 1990.Fire Test for Heat and Visible SmokeRelease for Discrete Products and TheirAccessoriesInstalled in Air-Handling Spaces, 1992.
    • 266 Handbook of Fire and Explosion ProtectionAppendix B.2Explosion and Fire Resistance RatingsFire Resistance Ratings“A”,“B“,and ”C”fire barriers are normally specified for ships and were originallydefined by the Safety ofLife at Sea (SOLAS) Regulations. Sincethen they have used extensivelyfor offshore oi and gas installationconstruction specifications. Recently, as more knowledge of hydrocarbonsfires was gained, “H”fire ratedbarriershave been specifiedand are typically defined by a high rise fire test such as the UL.fire test UL 1709.“J” fire ratings have been mentioned lately and are being referred to for protection against high pressurehydrocarbonjet fires.A BarriersA 0 CellulosicFire, 60 minute barrier against flame and heat passage, no temperature insulation.A 15 CellulosicFire, 60 minute barrier against flame and heat passage, 15min. temperature insulation.A 30 CellulosicFire, 60 minutebarrier against flameand heat passage, 30 min. temperature insulation.A 60 CellulosicFire, 60 minute barrier against flame and heat passage, 60 min. temperature insulation.Class A divisionsare those divisionsthat are formed by decks and bulkheads that comply with the following:(1) They are constructed of steel or material of equivalent properties.(2) They are suitable stiffened(3) They are constructedto prevent the passage of smoke and flame for a one hour standard firetest.(4) They are insulated with approved noncombustiblematerials such that the averagetemperatureofthe unexposed sidewill not rise more than 180OC above the originaltemperature, within thetime listed (Le. A-60: 60 minutes, A-30: 30 minutes, A-15: 15 minutes, A-0: 0 minutes).B BarriersB 0B 15 CellulosicFire, 30 minute barrier against flame and heat passage, 15min. temperature insulation.CellulosicFire, 30 minute barrier against flame and heat passage, no temperature insulation.Class B barriers are those divisionsformed by ceilings, bulkheads or decks that complywith the following:(1) They are constructed to prevent the passage of flamefor 30 minutes for a standardfire test(2) They have an insulation layer such that the average temperature on the unexposed side will notrise more than 139 OC abovethe originaltemperature, nor will the temperature at any one point,includinganyjoint rise more than 225 OC abovethe originaltemperature @e.,a Class B-15: 15minutes, Class B-0: 0 minutes).(3) They are of noncombustibleconstruction.
    • Appendix B: Reference Data 267C BarriersC Noncombustible Construction.Class C barriers are made of noncombustiblematerials and are not rated to provide any smoke, flame ortemperature passage restrictions.H BarriersH 0 HydrocarbonFire, 120minute barrier against flameand heat passage, no temperature insulation.H 60 HydrocarbonFire, 120minute barrier against flame and heat passage, 60 min. temp. insulation.H 120 HydrocarbonFire, 120minutebarrier against flame and heat passage, 120 min. temp. insulation.H 180 HydrocarbonFire, 120minute barrier against flame and heat passage, 180 min. temp. insulation.H 240 HydrocarbonFire, 120minute barrier against flame and heat passage, 240 min. temp. insulation.J RatingsJet Fire or "J" ratings are specified by some vendors for resistance to hydrocarbon jet fires. Currently nospecific standard or test specification has been adopted by the industry as a whole or a governmentalregulatory body. Some recognized testing agencies (e.g., SINTEF, Shell Research, British Gas, etc.) haveproposed J fire test standards which are currently being used by some of the major operators in lieu of arecognized standard.Heat FluxHeat rate input:is normally taken as 205 kW/m2 (65,000 Btu/ft2) - hr @ 5 minutes for hydrocarbon firesFire Doors0.3 Hours (20 minutes), CellulosicFire0.5Hours (30 minutes), CellulosicFire0.75 Hours (45 minutes), CellulosicFire1.O Hour, CellulosicFire1.5Hours, CellulosicFire3.0Hours, CellulosicFire4.0 Hours, CellulosicFireThe doors are also rated at three temperature levels that indicate the maximum temperature transmitted tothe unexposed side after 30 minutes,: up to 121OC (250 OF), up to 250 OC (450 OF), and up to 361 OC (650OF).Fire Windows0.3 Hours (20 minutes), CellulosicFire0.5Hours (30 minutes), CellulosicFire0.75 Hours (45 minutes), CellulosicFire1.OHour, CellulosicFire1.5Hours, CellulosicFire3.0Hours, CellulosicFire
    • 268 Handbook of Fire and Explosion ProtectionFire Dampers0.3 Hours (20 minutes), CellulosicFire0.75 hours (45 minutes), CellulosicFire1 hour, CellulosicFire1.5hours, CellulosicFireSmoke DampersSmoke dampers are specified on the leakage class, maximum pressure, maximum velocity, installation mode(horizontal or vertical)and degradationtest temperature of the fire (Ref UL Std. 555 S).Blast RatingsExplosion blast ratings are taken as the maximum peak overpressure that may be expected to occur.Commonlyindustry rating requested are listed below. No standardizedtest criteria has been adopted by theindustry or regulatingbodies, rather the operator is required analysethe exposures and demostrate adequateprotection is afforded where required.0.1 Bar (1.5 psi) Overpressure0.25 Bar (3.6psi) Overpressure0.5 Bar (7.3 psi) Overpressure1.0 Bar (14.5 psi) OverpressureElectrical Svstem Temperature ODeratingLimitsElectrical components are guaranteed for performance at a maximum ambient temperature. Most electricalor electronic equipment is rated for a maximum operating temperature of 40 OC (104 OF) unless otherwisespecified, e.g., hazardous area lighting fixtures are normally specified for maximum ambient operatingtemperature of 40 OC (104 OF). At temperatures above these levels the performance of the electricalcomponentscannot be assured.
    • Appendix B: Reference Data 269Appendix B.3National Electrical Manufacturers Association (NEMA)NEMA ClassificationsType 1 - General PurposeA general purpose enclosure that is intended to primarily prevent accidental contact with the enclosedapparatus. It is suitable for general purpose applications indoors where it is not exposed to unusual serviceconditionsand is primarily designed to keep out dirt.A Type 1 enclosure serves as a protection against dust and light indirect splashing, but is not dust tight.Typical applications are ofice buildings,warehouses, etc.Type 1A - Semi-Dust TightA semi-dust tight enclosure that is similar to Type 1 enclosure, with the addition of a gasket around thecover.Type 1B -Flush TypeA flush type enclosure that is similar to Type 1 enclosure, but is designed for mounting in a wall and isprovided with a cover that also serves as a flush plate.Type 2 - Drip Proof IndoorsA drip tight enclosure that is intended to prevent accidental contact with the enclosed apparatus and inaddition,issrrcomtractecf ast r r ~ x c l a d e f ~ f i n g r n ~ ~ ~ ~ ~ o t - ~tbutisnutdrmt tigtii.Type 2 enclosures are suitable for applications where condensation may be severe, such as encountered incooling rooms and laundriesType 3 -Dust Tight, Rain Tight and Sleet (Ice) Resistant OutdoorA weather resistant enclosureintended to provide suitable protection against specifiedweather hazards. It issuitable for use outdoors. It is designed to provide a degree of protection against rain, sleet, windblowndust, and damage from external ice formation.A Type 3 enclosureis suitablefor applications outdoors i?ice is not a seriousproblemType 3R - Rain Proof, Sleet (Ice) Resistant OutdoorAn outdoor enclosure designed against rain, sleet, and damage from external ice formation. They are notdust tight, snow or sleet (ice) proof.Type 3s - Dust Tight, Rain Tight, and Sleet (Ice) Proof - OutdoorAn outdoor enclosuredesigned to protect against dust and water and to operate covered with ice or sleet.
    • 270 Handbook of Fire and Explosion ProtectionType 4 - Water Tight and Dust TightAn enclosure so designed to provide a degree of protection against windblown dust and rain, splashingwater, water directed under pressure, and damage from external ice formations.A Type 4 enclosureis suitable for application outdoors on loading docks, and in water pump houses but notin hazardouslocations.Type 4X - Water Tight, Dust Tight, and Corrosion ResistantA Type 4 outdoor enclosurethat is also protected to provide corrosion resistanceType 5 -- Dust Tight, WatertightAn indoor enclosurewith a degree of protection against settlingdust, dirt, and noncorrosiveliquidsType 6 - SubmersibleType 6 enclosures are intended for indoor or outdoor use primarily to provide a degree of protection againstthe entry of water during occasional temporary submersion at a limited depth. They are not intended toprovide protection against conditions such as internal condensation, internal icing, or corrosiveenvironments.A Type 6 enclosure is suitable for application where the equipment may be subject to temporarysubmersion. The design of the enclosurewill depend upon the specificconditionsof pressure and time. It isalso dust tight and sleet (ice) resistant.Type 6P - Prolonged SubmersibleAn enclosure for indoor or outdoor use to provide a degree of protection against direct pressurized waterapplication, entry of water during prolonged submersion, and damage from external ice formation.Type 7 (A, B, C, or D) Hazardous Locations - Class I Air BreakThese enclosures are designed to meet the applicable requirements of the National Electrical Code (NFPA70) for Class I Groups A, B, C, or D hazardous locations that may be in effect. In this type of equipment,the circuit interruptionoccurs in air.Specifically note that Type 7 (explosion-proof)enclosures and their associated conduit systems are neithergas or liquid tight. Consequently, corrosive gases such as hydrogen sulfide and water from rain or internalcondensation can accumulate with the enclosure. Premature failure of electrical devices andinterconnectionsoften results when preventive measures such as drains, air purges, and dual rated enclosuresare not used to remove or excludethese corrosive elements. Type 7 enclosuresare intended for indoor use.Type 8 (A, B, C, & D) Hazardous Locations - Class I Oil ImmersedThese enclosures are designed to meet the application requirementsof the National Electrical Code (NFPA70), for Class I Groups A, B, C, or D hazardous locationseither indoors or outdoors. The apparatus may beimmersed in oilType 9 (E, F, or G) Hazardous Locations - Class I1These enclosures are designed to the applications requirementsof the National Electrical Code (NFPA 70),
    • Appendix B: Reference Data 271for Class 11, Groups E, F, or G hazardous locationsThe letters or letter following the type number indicates the particular groups or groups of hazardouslocations (as defined by the National Electrical Code) for which the enclosure is designed. The designationis incompletewithout a suffix letter or letters.Type 10 -Mine Safety and Health Administration (MSHA) - Explosion ProofA Type 10 enclosure is designed to meet the explosion proof requirements of the U.S. Mine Safety andHealth Administration(MSHA). It is suitablefor use in gaseous coal mines.Type 11 - Acid and Fume Resistant - Oil ImmersedA Type 11 enclosure is suitable for application indoors where the equipment may be subject to corrosiveacid or fumes, as in chemical plants, plating rooms, sewage plants, etc. The apparatus may be immersed inoil.Type 12 -Industrial UseA Type 12 enclosure is designed for use in those industrieswhere it is desired to exclude such materials asdust, lint fibers, and flyings, oil seepage,or coolant seepage.Type 13 -Oil Tight and Dust Tight IndoorAn indoor enclosure for pilot devices such as limit switches, selector switches, foot switches, push buttons,and pilot lights for protection against lint, dust seepage, external condensation, and spraying of water, oil orcoolant
    • 272 Handbook of Fire and Explosion ProtectionNEMA Type 7 (Indoor) and Type 8 (Indoor and Outdoor)Applications for Hydrocarbon EnvironmentsSourceNational Electrical Manufacturers Association, Publication No. 250
    • Coeflicient of DischargeFactorsOutletAppendix B: Reference Data 273Appendix B.4Hydraulic DataDischargeCoefficientNozzles, UnderwritersPlaypipes or similarNozzles, Deluge Sets or MonitorNozzles,RingOpen Pipe, SmoothOpeningOpenPipe, Burred OpeningSprinklerHead (nominal 1/2inch orifice)Standard Orifice(sharp edge)Hydrant butt, smooth on well rounded outlet, flowing fullHydrantbutt, square and sharp at hydrantbarrelHydrant but, outlet square, projecting into barrel0.970.990.750.800.700.750.620.900.800.70
    • 274 Handbook of Fire and Explosion ProtectionAppendix B.5Selected Conversion FactorsMetric Prefixes, Symbols and Multiplying FactorsPrefixexaPebtera€k3amegakilohectodecadecicentimillimicronanofemtoattopic0Symbol MultiplyingFactorE 1018P 1015T 1012G 109M 106k I03h 102da 101100a 10-1C 10-2m 10-3I.L 10-6I1 10-9P 10-12f 10-15a 10-181,000,000,000,000,000,0001,000,000,000,000,0001,000,000,000,0001,000,000,0001,000,0001,0001001010.10.010.0010.000,00I0.000,000,00I0.000,000,000,0010.000,000,000,000,0010.000,000,000,000,000,001Word= one trillion= one billion= one million= one thousand= one hundred=ten= one= one tenth= one hundredth= one thousandth= one millionth= one billionth= one trillionthThe prefixes should be attached directly to the SI base unit: e.g., kilogram, millisecond, gigameter, etc. Similarly,the abbreviationsattach directly to the abbreviation for the SI units: e+, an,Mg, mK, etc. Do not use two or more of the SI units. Although kilogramis the normal base unit for mass,the prefixes are added to gram (g), not kilogram (kg).Temperature Conversion9= PC x 1.8)+32OC =("F- 32)/1.8%= 9f 459.67%=OC+273.15Freezing Point of Water: Celsius =0 deg., Fahr. = 32 degreesBoiling Point of Water: Celsius = 100 deg.,Fahr. =212 degrees
    • Appendix B: Reference Data 275MultiplySelected ConversionFactorsby to ObtainAcresAcresAcre feetAcre feetAcre feetAtmospheresAtmospheresAtmospheresAtmospheresAtmospheresAtmospheresBarrels,OilBarrels,OilBarrels,OilBarrels,OilBarsBarsBarsBarsBarsBtUBtuBtuBtu/A2Btulttt"?/hrBtLl/fiZ/hr/FBtuflb (OF)Btdft2/hr/F/in.BtuflbBtdcubic footBtdgallonBtu/hourBtu/minuteBtdminuteBtdminuteCentimetersCentimetersof MercuryCentimetersof MercuryCentimetersof MercuryCentimetersof MercuryCubic CentimetersCubic footCubic footCubic footCubic footCubic footCubic footflbCubic foot/minuteCubic foot/minuteCubic foot/minuteCubic foot/secondCubic inchCubic inchCubic mete1Cubic meterCubic meterCubicyardCubicyardCubicyard43,5604,04743,5601,233325,85029.9276.033.9014.69595101.3251.013255.6145830.158987342158.987310010,19714.50.9869233777.981,054.807.56511.3603.1525.6740.I442.3264.186837.25895278.71360.29310.0175712.960.023560.39370.013160.446127.850.19340.061020.02831684728.316257.480521728O:mKr20.06242796472.00.47200.1247448.316.390.01639264,172135.3I4676.2898110.7645627202.0106SquarefeetSquaremetersCubic feetCubic metersGallons(U.S.)Inches of mercuryCms of mercuryFeet of waterPounddsquare inchKilopascalsBarCubic feetCubicmetersGallons (U.S.)LiterskiloPascalsQmedsquare centimeterKilograms/squaremeterPoundslsquareinchAtmospheresJoules (abs)Kilogram-meterJoulelmWatt/m2 (IC-factor)watt/& KWatt/m KKilojouleflulogramEcllojoulefluIogram(C)Kilojoulelcubic meterKilojoulelcubic meterWattsKilowattsFoot-punds/secondHorse-powerInchesAtmospheresFeet of waterPoundslsquarefeetPoundslsquareinchCubic inchesCubic metersLitersGallonsCubic inchesCubic meterCubic meterskilogramCubic centimeterslsecondLiterdsecondGallonslsecondGallons/niinuteCubic centimetersLitersGallonsCubic feetBarrels,OilCubic metersCubic feetGallonsFoot-pounds
    • 276 Handbook of Fire and Explosion ProtectionFeetFeetFeetFeet of waterFeet of waterFeet of waterFeet of waterFootlsecondGallonsGallonsGallonsGallonsGallonsof waterGallons per minuteGallonsper minuteGallonsper minuteHorsepowerInchInchInchInches of mercuryInchesof mercuryInches of mercuryInchesof mercuryInchesof waterI n c h of waterInches of waterInches of waterInches of waterJoulesJoluesJoulePC%localorieKilogramsKilogradsquarecentimeterKilograms/mmZKilometersKilowattsKilowattKilowattKilowatt-hoursKilowatt-hoursKilowatt-hoursKilograms/squarecmLitersLitersLitersLiterslsecondLitershecondLiterdsecondLuxLuxMetersMetersMetersMeterMeterhinuteMilesMilesMileshourMileshourMileshourMillibarMillimetersMillimetersof mercuryMMCFDFoot-pounds30.480.3048304.80.030482989.070.02949980.02989071.35630.483.785330.133682313,785.4348.34530.0022288.02080.0630902745.725.42.5400,02543.3890.033421.1330.49120.0024580.073555.2020.03613248.80.0009478170.2388460.0005265654.1842.2046214.229.8070.62141.3413,412.141,0003,412.142.655 x IO63.6 x lo697.06650.264261.020.0353115.85032951.01942.118881.00.09293.28139.371.0945,2800.054681.6093445,280881.4671.6093441000.039370.133328,300CentimetersMetersMillimetersKilograms/squarecentimetcPascalAtmospheresBarsJoulesCentimeterdsecondLitersCubic feetCubic inchesCubic centimetersLbs. of waterCubic feetlsecondCubic feetmourLiters/secondWattsIvhlimetersCentimetersMeterkilopascalsAtmospheresFeet of waterPounds/squarefeetAtmospheresInches of mercuryPounds/squarefeetPoundshquare inchPascalsBtuCalorieBtUPFkiloJoulesPoundsPounddsquare inchMPaMilesHorsepowerBtu/hourJoule/secondBtUFoot-po~dsJoulesKilopascals&Pa)Gallons(U.S.)Cubic inchesCubic feetGallonsper minute (gpm)Gallonsper hourCubic fi./minuteLumenskquare meterFoot-candlesFeetInchesYardsFeetFeetlsecondalometersFeetFeethinUteFeethecondkilometershourPascalsInchesMoPascalscubic meterdday
    • Appendix B: Reference Data 277Ounces (fluid)PascalPoundPounddsquare inchPounds/squareinchPoundslsquareinchPounds/squareinchPounddsquare inchPounds/squareinchPounds/squarefootPounddcubic footQuartsSlugsSquareCentimetersSquareCentimetersSquarefootSquareInchesSquaremetersSquaremetersSquaremetersSquareYardsSquareYardsWattsWattsWattsYardsYards0.29570.000I450380.45359242.3070.068042.0366.8947576,8950.068947.8816.018460.946332.1740.001076390.154999690.929645.21,55010.763871.1960.836112963.413040.73781.341x IOe33.00.9144Miscellaneous Constants1gallonof fresh water = 8.33lbs. = xx kgs.1cubicA. of freshwater = 62.4 lbs. = xx kgs.AbsoluteZero: -273.16deg. Celsius; -459.69degreesFahr.LitersPounds/squareinchKilogram (kgs)Feet of waterAtmospheresInchesof mercuryKilopascals(Wa)PascalsBarsPascalsKilograms/cubicmeterLitersPoundsSquarefeetSquareinchesSquaremetersSquaremillimetersSquareinchesSquarefeetSquareyardsSquaremetersSquareinchesBtu/hourFoot-pounds/secondHorsepowerFeetMeters
    • ACRONYM LISTABSACAFFFAFNORAlAAIChEAlTALARPANSIAODCAOVAPIASAASCEASHRAEASMEASSEASTMAWWABACTBASEEFABLEVEBMSBPCSBPDBOMBOPBOSSBSBSIBS&WBTU°CCADCCPSCENELECCFMCFRCFTCIMAHCMICONCAWECO2CPICSACVDdBAmerican Bureau of ShippingAlternating CurrentAqueous Film Forming FoamFrench Standards(Association Francaisde Normalization)American Insurance AssociationAmerican Institute of Chemical EngineersAutoignition TemperatureAs Low As ReasonablyPracticableAmerican National StandardsInstituteAssociation of Offshore Diving ContractorsAir Operated ValveAmerican Petroleum InstituteAcoustical Society of AmericaAmerican Society of Civil EngineersAmerican Society ofHeating, Refrigerating and Air-ConditioningEngineersAmerican Society ofMechanical EngineersAmerican Society of Safety EngineersAmerican Society for Testing and MaterialsAmerican Water Works AssociationBest Available Control TechnologyBritish Approval Sciencefor Electrical Equipment in FlammableAtmospheresBoiling Liquid Expanding Vapor ExplosionBurner Management SystemBasic ProcessControl SystemBarrels per DayBureau ofMines (U.S.)Blowout PreventerBlowout Spool SystemBritish StandardBritish StandardsInstituteBasic Sedimentand WaterBritish Thermal UnitDegrees CentigradeComputer Aided DesignCenter for Chemical ProcessSafetyEuropean Committee for Electrotechnical StandardizationCubic Feet per MinuteCode of Federal RegulationsCool-Flame Reaction ThresholdControl of Industrial Major Accident HazardsChristian Michelsen Institute (Norway)Conservation ofClean Air/Water EuropeCarbon DioxideChemicalProcessingIndustryCanadianStandardsAssociationCombustible Vapor DispersionDecibel278
    • Acronym List 279DCDCSDHSVDINDNVOFEIVEOLREORESPESDESVETFAFACPFARFCFCCFCVFDFHZFMFMEAFOFPFSFSAFTFWFWKOGORGQSPGOSTGOVGPAgpmHAZOPWCHCNHFESHIPSHMSOHOVHPIHPRHRAHSEHSIHVACHzIADCIECH2ShPDirect CurrentDistributed Control SystemDown hole safety valveGerman StandardsDet Norske VeritasDegrees FahrenheitEmergency Isolation ValveEnd of Line ResistorEnhanced Oil RecoveryElectrical SubmersiblePumpEmergency ShutdownEmergency ShutdownValveEvent TreeFire AlarmFire Alarm Control PanelFatality Accident RateFail ClosedFluid CatalyticCrackerFlow Control ValveFire DepartmentFire Hazard ZoneFactory MutualFailureMode and Effects AnalysisFail OpenFlash PointFail Steady(i.e.last operating position)Formal Safety AssessmentFault TreeFirewaterFree Water Knock OutGas Oil RatioGas Oil SeparationPlantRussian (U.S.S.R.) StandardsGas Operated ValveGas Processors AssociationGallonsPer MinuteHazard and Operability(Review or Study)HydrocarbonHydrogen Cyanide(HydrocyanicAcid)Hydrogen SulfideHuman Factors and Ergonomics SocietyHigh IntegrityProtective SystemHer Majesty’sStationaryOfficeHydraulicOperated ValveHorsepowerHydrocarbonProcessingIndustryHighly Protected RiskHuman Reliability Analysis (or Human Error Analysis)Health and SafetyExecutive (U. K.)Hydraulics StandardsInstituteHeating, Ventilation and Air ConditioningHertzInternationalAssociation of Drilling ContractorsInternationalElectrotechnicalCommission
    • 280 Handbook of Fire and Explosion ProtectionIEEEILPIMOLpLRIRIISISAIS0.TISLISLAHLALLFLLEDLELLNGLPGLSHLSLMACMgMMCFMMSMOVMPSMSDSMSHAMTBFMwNACENECNEMANDTNFACNFPANGLMOSHNPDOIAOILOIMOREDAOSHAOTCowsPAHPALPCPCVPDQP.E.PFDPHAInstitute of Electronic and Electrical EngineersIndependent Layers of ProtectionInternationalMaritime OrganizationInstitute of Petroleum (U.K.)InfraredIndustrial Risk Insurers (U.S.)IntrinsicallySafeInstrument Societyof AmericaInternationalOrganizationfor StandardizationJapaneseIndustrial StandardsLiters per SecondLevel Alarm HighLevel Alarm LowLower FlammableLimitLight EmittingDiodeLower Explosive Limit (synonymouswith LFL)LiquefiedNatural Gas (Methane)LiquefiedPetroleum Gas (Butane or Propane)Level SafetyHigh (high level sensor)Level SafetyLow (low level sensor)Manual Activation CallpointMass flow rate of gasOne Million CubicFeetMinerals Management Service(U.S.)Motor Operated ValveManual Pull StationMaterial SafetyData SheetMine Safetyand Health Administration(U.S.)Mean Time Between FailuresMass flow rate ofwaterNational Association of Corrosion EngineersNational Electrical CodeNational Electrical ManufacturersAssociationNon Destructive TestingNational Fire Alarm CodeNationalFire Protection AssociationNatural Gas LiquidsNational Institute €or OccupationalSafety and Health (U.S.)Norwegian PetroleumDirectorateOil InsuranceAssociationOil InsuranceLimited (Bermuda)Offshore Installation ManagerOffshore ReliabilityDataOccupationalSafety and Health Administration(U.S.)Offshore Technology ConferenceOily Water SewerPressure Alarm HighPressure Alarm LowPersonalComputerPressure Control ValveProduction, Drilling, QuartersProfessionalEngineerProcess Flow DiagramProcess Hazard Analysis
    • Acronym List 281PIPIBP & I DPLCPLLPMLPOBPPmPSHpsipsiaPsigpsi0PSVPtbQAQCQRARORRPRPMRRFRTTRVRVPSASOSCADASFPESISIHSILSINTEFSISSMACNASNiPSOLASSPESSIVTAHTALTMRTNTTSHTSRUBCUFLUELU K.ULULCCUMCUPSu.sPressure IndicatorProcess InterfaceBuildingPiping and InstrumentationDrawingProgrammableLogic ControllerPotential Loss of LifeProbable MaximumLossPersonnel On BoardParts Per MillionPressure SwitchHighPounds per Square InchPounds per Square Inch AbsolutePounds per Square Inch GagePounds per Square Inch OverpressurePressure SafetyValvePounds of salt (Na C1) equivalent per thousand barrels of crude oilQuality AssuranceQualityControlQuantitativeRisk AssessmentRate of RiseRecommendedPracticeRevolutionsper MinuteRisk ReductionFactorPreflame-Reaction ThresholdRelief ValveReid Vapor PressureSaudi Arabian Standards OrganizationSupervisoryControl and Data AcquisitionSocietyof Fire Protection EngineersSystemeInternational&UnitesSatelliteInstrumentationHouseSafetyIntegrityLevelNorges BranntekniskeLaboratorium(NorwegianFire ResearchLaboratory)Swedish Standards AssociationSheet Metal and Air ConditioningContractors National AssociationRussian (U.S.S.R.)RegulationsSafetyof Life at SeaSociety of PetroleumEngineersSubsea Isolation ValveTemperatureAlarm HighTemperature Alarm LowTripIe Modular RedundantTrinitrolueneTemperature SafetyHigh (high temperature sensor)Temporary SafeRefbgeUniform Building CodeUpper FlammableLimitUpper Explosive Limit (synonymouswith UFL)United KingdomUnderwritersLaboratories (U.S.)Ultra Large Crude CarrierUniformMaterials CodeUniterruptable Power SupplyUnited States
    • 282 Handbook of Fire and Explosion ProtectionUSCGuvUVCEVDCVESDAVLCCvocWCCE100220022003United States Coast GuardUltravioletUnconfined Vapor Cloud ExplosionVolts Direct CurrentVery Early SmokeDetection and AlarmVery Large Crude CarrierVolatile Organic CompoundsWorst Case Creditable EventOne Out Of TwoTwo Out Of TwoTwo Out Of Three
    • GlossaryAccident - An event or sequenceof events that results in undesirable consequencesAPI Gravity - The gravity (weight per unit volume) of crude oil expressed in degrees according toAmerican Petroleum Institute recommended system. API gravity divides the number 141.5 by the actualspecific gravity of the oil at 15.5 O C (60 OF) and subtracts 131.5 from the he resulting number. The higherthe API gravity the lighter the crude oil. Higher gravity crudes are generallyconsidered more valuable.Autoignition Temperature (AIT) - The lowest temperature at which a flammablegas or vapor-air mixturewill ignite from its own heat source or a contracted heat source without the necessity of a spark or flame.Availability - The probability or mean fractional total time that a protective system is able to hnction ondemand.Barrel (BBL) - A barrel has been traditionallythe standard liquid quantity of measurement in the petroleumindustry. One barrel of oil equals 159liters (42 U.S.gallons).Basic Process Control System (BPCS) - Pneumatic, electronic, hydraulic or programmable instrumentsand mechanisms that monitor and/or operate a facility or system to achieve a desired function, Le., flowcontrol, temperature measurement, etc., which are supervisedby human observation.Best Available Control Technology (BACT) - The most currently commercial optimum hardware andoperating methodology appliedto a process.Blast - A transient change in gas density, pressure (both positive and negative), and velocity of the airsurroundingan explosion point.Boiling Liquid Expanding Vapor Explosion (BLEVE) - The nearly instantaneous vaporization andcorresponding release of energy of a liquid upon its sudden release from a containment under greater thanatmospheric pressure and at a temperature above its atmosphericboiling point.Blowdown - The disposal of voluntary discharges of liquids or condensablevapors from process and vesseldrain valves, thermal relief or pressure relief valves.Blowout - A uncontrolled flow of gas, oil or other well fluids from a wellbore at the wellhead or into theformation, caused by the formation pressure exceeding the drilling fluid pressure. It usually occurs duringdrilling on unknown reservoirs.Blowout Preventer (BOP) - An assembly of heavy duty valves attached to the top of a well casing tocontrol pressure and flow.283
    • 284 Handbook of Fire and Explosion ProtectionBoilover - A boiling liquid eruption in a hydrocarbon storage tank; usually described as an event in theburning of certain oils in an open top tank when, after a long period of quiescent burning, there is a suddenincrease in fire intensity associated with the expulsion of burning oil from the tank, due to water at thebottom of the tank being heated to vaporizationand causing a boiling eruption.Christmas Tree - An assembly of valves, gauges, and chokes mounted on a well casinghead to control theflow and pressure of oil or gas to a pipeline.Classified Area - Any area that is electrically classified following the guidelines of a nationally recognizedelectrical code such as the requirementsof the NEC, Article 500 or API RP 500.Combustion- A rapid chemical process that involvesreaction of an oxidizer (usually oxygen.in air) with anoxidizablematerial, sufficientto produce radiation effects, i.e., heat or light.Combustible- In a general sense any material than can burn. This implies a lower degree of flammability,although there is no precise distinction between a material that is flammable and one that is combustible(NFPA 30 defines the differences between the classification of combustible liquids and flammable liquidsbased on flash point temperatures and vapor pressure).Combustible Liquid - A liquid having a flash point at or above 37.8 OC (100 OF) as determined underspecified conditions. When the ambient temperature of a combustibleliquid is raised above its flash point, itessentiallybecomes a flammableliquid.Condensate - Liquid hydrocarbons that have been separated from natural gas, usually by cooling theprocess stream which "condense" the "entrained" liquid. Typically the fractions of C3, C4 and C5 orheavier.Crude Oil or Petroleum - Liquid petroleum as it comes out of the ground. Crude oils range from very light(high in gasoline) to very heavy (high in residual oils). Sour crude is high in sulfur content. Sweet crude islow in sulfur, and therefore more valuable. Generally considered crude oils are hydrocarbon mixtures thathave a flash point below 65.6 OC (150 OF) and that have not been processed in a refinery.Deluge - The immediate release of a commodity, usually refemng to a water spray release for firesuppression purposes.Depressurization - The release of unwanted gas pressure from a vessel or piping system to an effectivedisposal system.Detonation - A propagating chemical reaction of a substance in which the reaction front advances into theunreacted substanceat greater than sonicvelocity in the unreacted substance.Distillate - A generic term for several petroleum fuels that are heavier than gasolineand lighter than residualfUels; for example, home heating oil, dieseloil, andjet fuels.Distributed Control System (DCS) - A generic, microprocessor based, regulatory system for managing asystem,process or facility.Diverter - The part of the bell nipple at the top of a marine riser, that controls the flow of gas or other fluidsthat may enter the wellbore under pressure, before the BOP stack has be set in place. It is used when drillingthrough shallowundergroundgas zones for divertinggas kicks in deep high pressure zones.Emergency - A condition of danger that requires immediateremedial actionEmergency Shutdown (ESD) - A method to rapidly cease the operation of the process and isolate it from
    • Glossary 285incoming and going connectionsor flows to reduce the likelihood of an unwanted event fiom continuing oroccumng.Ergonomics - The study of the design requirementsof work in relation to the physical and psychologicalcapabilitiesand limitationsof human beings.Executive Action - Control process performed to initiate critical instructionsor signalsto safety devices.Explosion - A rapid increase in pressure in a confined space or semi-confined space.Explosionproof - A common term characterizing an electrical apparatus that is so designed that anexplosion of flammablegas inside the enclosurewill not ignite flammablegas outside the enclosure. Nothingis really considered technicallyexplosionproof.Fail Safe - A system design or condition such that the failure of a component, subsystem or system or inputto it, will automatically revert to a predetermined safe static condition or a state of least criticalconsequence.Fail to Danger - A system design or condition such that the failure of a component, subsystem or system orinput to it, will automatically revert to an unsafe condition or state of highest critical consequence for thecomponent, subsystem,or system.Failure Mode - The action of a device or system to revert to a specified state upon failure of the utilitypower source that normally activates or controls the device or system. Failure modes are normally specifiedas fail open (FO), fail closed (FC) or fail steady (FS) which will result in a fail safe or fail to dangerarrangement.Fire - A combustible vapor or gas combining with an oxidizer in a combustion process manifested by theevolution of light, heat and flame.Fireproof - Resistant to a specific fire exposure; essentially nothing is absolutely "fireproof" but somematerials or building assembliesare resistant to damage or fire penetration at certain level of fire exposuresthat may develop in the petroleum industry.Fireproofing - A common industry term used to denote materials or methods of construction used toprovide fire resistance for a defined fire exposure and specified time. Essentially nothing is fireproof if it isexposed to high temperatures for extended time periods.Fire Retardant - In general a term that denotes a substantially lower degree of fire resistance than "fireresistive. It is frequently used to refer to materials or structures that are combustible but have beensubjected to treatment or surface coatingsto prevent or retard ignition of the spread of fire.Fire Resistive - Properties of materials or designs that are capable of resisting the effects of any fire towhich the material or structure may be expected to be subjected.Flame - The glowing gaseous part of a fire.Flammable - In a general sense refers to any material that is easily ignited and burns rapidly. It is-3ynonymous-with-the-ternL-inflarmrabk-that.isgenerally .can3i&~d&sotete dx$8 its.prc€k-whichmay+cincorrectly misunderstood as not flammable(e.g.,incomplete is not complete).Flammable Liquid - A liquid having a flash point below 37.8 OC (100 OF) and having a vapor pressure notexceeding 2068 mm Hg (40 psia) at 37.8 O C (100 OF) as determined under specified conditions.
    • 286 Handbook of Fire and Explosion ProtectionFlash Point (FP) - The minimum temperature of a liquid at which it gives off sufficient vapors to form anignitable mixture with air immediately above the surface of the liquid or within the vessel used on theapplicationof an ignition source under specifiedconditions.Foam - A fluid aggregate of air filled bubbles, formed by chemical means that will float on the surface offlammable liquids or flow over solid surfaces. The foam fimctions to blanket and extinguish fires and/orprevent the ignition ofthe material.Foam Concentrate - Fire suppression surfactant material used to seal the vapors from the surface of acombustibleliquid.Foam Solution - Fire suppression foam concentrates mixed in proper proportion to water as required byspecification of the foam concentrate (currently foam concentrates are available for 1%, 3%, and 6% bywater solution mix).Foolproof - So plain, simple, or reliableas to leave no opportunityfor error, misuse or failure.Fusible Link - A release device activated by the heat effects of a tire. It usually consists of two pieces ofmetal joined by a low melting point solder. Fusible links are manufactured at various temperature ratingsand are subject to varying normal maximum tension. When installed and the fixed temperature is reached,the solder melts and the two metal parts separate, initiating desired actions.Halon -As employed in the fire protection industry, a gaseous fire suppression agent. Halon is an acronymfor halogenated hydrocarbons, commonly bromotrifluoromethane (Halon 1301)and bromochlorodifluoro-methane (Halon 1211). Considered obsolete for fire protection purposes due to a possible environmentalimpact to the Earths atmospheric ozone layer and beginning to be phased out or eliminated.Heat Flux - The rate of heat transfer per unit area normal to the direction of heat flow. It is the total heattransmitted by radiation, conduction, and convection.Human Factors - A disciplineconcerned with designing machines, operations, and work environmentstomatch human capabilitiesand limitations.Hydrocarbons - An organic compound containing only hydrogen and carbon. The simplest hydrocarbonsare gases at ordinary temperatures;but with increasing molecular weight, they changeto the liquid form andfinally,to the solid state. They form the principal constituents of petroleum and natural gas.Ignition - The process of starting a combustion process through the input of energy. Ignition occurs whenthe temperature of a substanceis raised to the point at which its moleculeswill react spontaneously with anoxidizer and combustion occurs.Independent Protection Layer (IPL) - Protection measures that reduce the level of risk of a serious eventby 100times, which have a high degree of avaiIabiIity (greater than 0.99) or have specificity,independence,dependabilityand auditability.Inerting - The process of removing an oxidizer (usually air or oxygen) to prevent a combustion processfrom occurringnormally accomplishedby purging.Inflammable - Identical meaning as flammable, however the prefix "in" indicates a negative in many wordsand can cause cohsion, therefore the use of flammableis preferred over inflammable.Inherently Safe - An essential character of a process, system or equipment that makes it without or verylow in hazard or risk.
    • Glossary 287Intrinsically Safe (IS) - A circuit or device in which any spark or thermal effect is incapable of causingignition of a mixture of flammableor combustiblematerial in air under prescribed test conditions.Intumensent - A fireproofingmaterial (epoxy coating, sealingcompound or paint) which foams or swellstoseveraItimes its volume when exposed to heat from a fire and simultaneous forms an outer char covering,that together forms an insulatingthermo layer against a high temperature fire.Liquefied Natural Gas (LNG) - Natural gas that has been converted to a liquid through cooling toapproximately-162OC (-260 OF) at atmospheric pressure.Liquefied Petroleum Gas (LPG) - Hydrocarbon fractions lighter than gasoline, such as ethane, propane,and butane, kept in a liquid state through compressionand/or refrigeration, commonly referred to as "bottledgas".Lower Explosive Limit (LEL) - The minimum concentration of combustible gas or vapor in air belowwhich propagation of flamedoes not occur on contact with an ignition source.Naphtha - Straight run gasoline distillate, below the boiling point of kerosene. Naphthas are generallyunsuitable for blending as a component of premium gasolines, hence they are used as a feedstock forcatalytic reforming in hydrocarbon production processes or in chemical manufacturing processes.Natural Gas -A mixture of hydrocarbon compounds and small amounts of various nonhydrocarbons (suchas carbon dioxide, helium, hydrogen sulfide, and nitrogen) existing in the gaseous phase or in solution withcrude oil in natural underground reservoirs.Natural Gas Liquids (NGL) - The portions of natural gas that are liquefied at the surface in productionseparators, field facilities, or gas processing plants, leaving dry natural gas. They incIude but are not limitedto ethane, propane, butane, natural gasoline, and condensate.Overpressure- Is any pressure relative to ambient pressure caused by an explosive blast, both positive andnegative.Process - Any activityor operation leadingto a particular event.Programmable Logic Controller (PLC) - A digital electronic controller that uses computer basedprogrammablememory for implementing operating instructionsthrough digital or analog inputs and outputs.Reid Vapor Pressure (RVP) - The pressure caused by vaporized part if a liquid and the enclosed air andwater vapor as measured under standardized conditions in standardizedapparatus, the result given in psi at100 OF, although normally reported as R W in Ibs. R W is not the same as the true "vapor pressure" of theliquid, but provides a relative index of the volatility of a liquid.Reliability - The probability that a component or system will perform its defined logic function under thestated conditionsfor a defined period of time.Risk - The combination of expected likelihood or probability (eventdyr.) and consequence or severity(effectdevent) of an accident.Safety -A general term denoting an acceptablelevel of risk of, relative freedom from and low probability ofharm.Safety Integrity Level (SIL) - The degree of redundancy and independence from the effects of inherent andoperationalfailuresand external conditionsthat may affect system performance.
    • 288 Handbook of Fire and Explosion ProtectionSmoke - The.gaseous products of the burning of carbonaceous materials made visible by the presence ofsmall particles of carbon, the small particles that are of liquid or solid consistencies are produced as a byproduct of insufficient air suppliesto a combustion process.Snuffing Steam - Pressurized steam (water vapor) used to smother and inhibit fire conditions.Sprinkler - Water deflector spray nozzle devices used to provide distribution of water at specificcharacteristic patterns and densities for purposes of cooling exposures, suppression of fires and vapordispersions.Triple Modular Redundant (TMR) - A system that employs a 2 out of 3 (2003), voting scheme todetermine the appropriate output action. It is based on the application of three separate operating systemsrunning in parallel.Vapor Pressure (VP) - The pressure, measured in psia, exerted by a volatile liquid as determined by ASTM.D 323, StandardMethod of Test for Vapor Pressure of PetroleumProducts (Reid method).
    • IndexAir intakes - 100Alarm overload - 245Arctic environments - 228Arrangement - 101Asphalt - 37Autoignition temperature - 30Alarms - 197Backup power - 191Basic process control system - 111Battery rooms -- 235Blowdown - 133Blowdown capability study - 91Blowout suppression system - 212BOP failures - 83Butane - 35BLEW -51Carbon dioxide systems - 216Carbon monoxide - 53Checklist safety review - 89Classified locations - 147Color coding - 243Combustible vapor dispersion study - 91Combustion - 44Communication facilities - 100Communication rooms - 234Condensate - 36Consequence modeling - 53, 89Conversion factors - 275Cooling towers - 237Critical utilities - 99Cross zoning - 191Crude oil - 34Deluge systems - 210Depressurization capability study - 91Desert environments - 228Design principles - 22Detonation arrestors - 174Detonations - 48Diesel - 37Distributed control system - 112DOW hazard index - 90Drainage systems - 104, 155Dry chemical - 221Dual agent suppression systems - 221Dual agent systems - 221Electrical area classification - 143, 146Electrical equipment - 234Electronic process control - 112Emergency isolation valves - 121Ergonomics - 240Ethane - 34Evacuation modeling - 91Evacuation routes - 197Event trees - 90Exits - 198Explosion overpressure study - 91Explosionproof equipment - 148Explosions - 48, 159, 160Facility access - 101Fail safe - 117Fatality accident rates - 91Fault trees - 90Fire control - 56Fire dampers - 174Fire detection - 177Fire models - 91Fire protection engineering - 5Fire pumps - 205Fire testing laboratories - 1678Fire triangle - 44Fire zones - 100Fireproofing - 164, 166, 169Firesafe valve standards - 122Firewater distribution systems - 208Firewater pumps - 98, 208Firewater reliability study - 91Flame arrestors - 173Flame blow out - 55Flame extinguishment methods - 55Flame resistance - 172Flares - 98, 133Flash fire - 47Flash point - 29289
    • 290 Handbook of Fire and Explosion ProtectionFloating production facilities - 230Flow performance tests - 250Foam - 213Foam water deluge - 215Fuel oils - 37FMEA - 90Gas compressor - 235Gas detection - 185-190Gaseous releases - 42Gasoline - 36Graphic annunciation - 191Greases - 37Halon - 218Halon replacements - 219Heat detectors - 179Heat flux - 45Heat transfer systems - 236High expansion foam - 216Hose reels - 212Hot work - 143Human attitude - 242Human error analysis - 91Human errors - 241Human factors - 240Human reliability analysis - 91Human surveillance - 177Hydrants - 212Hydrogen cyanide - 52M O P - 90Illumination - 198Independent layers of protection- 20Infrared OR) detectors - 181Infra-red (IR) beam gas detection - 189Insurance - 6Internal combustion engines - 151Intrinsically safe - 148Ionization detectors - 178Jet fire - 46Kerosene - 37Kitchens - 238Laboratories - 237Leak estimation - 91Lightning - 150Liquefied natural gas - 34Liquefied petroleum gas - 35Liquid releases - 43Loading facilities - 234Lower explosive limit - 29Lubricating oils - 37Management accountability - 7Methane - 34MOND hazard index - 90Monitors - 212Multi-band detectors - 182Natural gas - 34NEMA classifications - 269Noise - 245Nozzles - 213Offshore evacuation - 198, 200Offshore facilities - 229Oily water sewer - 140Open flames - 143Optical (flame) detectors - 180Overhead foam injection - 215Overpressures - 50Panic - 246Philosophy of protection - 17Photoelectric detectors - 178Pipelines - 230Pool fire - 47Portable fire extinguishers - 202Potential loss of life - 91Power supplies - 98Preliminary hazard analysis - 90Pressure relief - 140Pressure relief valves - 138Process units - 98Propane - 35Pump seals - 156Purging - 148Radiation shields - 171Risk acceptance criteria - 93Risk evaluation - 89Risk management - 6Safety flow chart - 87Safety integrity levels - 118Sample points - 155Security - 246Segregation - 95Semi-confined explosions - 49Separation - 96Smart technology - 112Smoke - 52Smoke dampers - 173Smoke detection - 177SCADA - 112
    • Index 291Smoke detectors - 178Smoke models - 91Solar heat - 139Spark arrestors - 151, 173Spill containment - 107Sprinkler systems - 210Static - 149Steam smothering - 55, 211Storage tanks - 98Subsea isolation valves - 121Subsurface foam injection - 215Surface drainage - 105Surface temperatures - 149Survivability of safety systems study - 91Thermal relief - 139Time temperature curves - 168Transformers - 237Turbines - 235Ultraviolet (UV)detector - 180Ultraviolet/infrared (UV/IR) detectors - 182Upper explosive limit - 29Valves - 209Vapor cloud explosions - 49Vapor density - 33Vapor dispersion - 163, 171, 211Venting - 133Voting logic - 191Warehouses - 238Water cooling sprays - 171Water curtains - 211Water flooding - 211Water spray - 210Water sprays - 163Water supplies - 204Wax - 38Welding - 143Wellheads - 231Wet chemical systems - 221What-if reviews - 90