HANDBOOK OF
FIRE AND
EXPLOSION PROTECTION
ENGINEERING PRINCIPLES FOR
OIL, GAS, CHEMICAL, AND
RELATED FACILITIES
by
Dennis P. Nolan, P.E.
NOYES PUBLICATIONS
Westwood, New Jersey, U.S.A.
Copyright Q 1996 by Noyes Publications
No part of this book may be reproduced or utilized in
any form or by any means, electronic or mechanical,
including photocopying, recording or by any information storage and retrieval system, without permission
in writing from the Publisher.
Library of Congress Catalog Card Number 96-10908
ISBN: 0-8155-1394-1
Printed in the United States of America by
Noyes Publications
369 Fairview Ave.
Westwood, New Jersey 07675
10 9 8 7 6 5 4 3 2 1
Library of Congress Cataloging-in-Publication Data
Nolan, Dennis P.
Handbook of fire and explosion protection engineering principles
for oil, gas, chemical, and related facilities / by Dennis P. Nolan.
p. cm.
Includes index.
ISBN 0-8155-1394-1
1. Chemical plants--Fires and fire prevention. 2. Petroleum
refineries--Fires and fire prevention. 3. Explosions. I. Title.
TH9445.C47N65
1996
660'.2804--dc20
96-10908
CIP
About the Author
Dennis P. Nolan has had a long career devoted to risk engineering, fire protection
engineering, loss prevention engineering and system safety engineering. He holds a Master
of Science degree in Systems Management from Florida Institute of Technology and a
Bachelor 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 of
California.
He is currently associated with the Fire Prevention Engineering staff of the Saudi Arabian Oil
Company (Saudi Aramco), located in Abqaiq, Saudi Arabia, site of the largest oil and gas
production facilities in the world. He has also been associated with Boeing, Lockheed,
Marathon oil Company and Occidental Petroleum Corporation in various fire protection
engineering, risk and safety roles at several locations in the United States and overseas. As
part of his career he has examined oil production, refining and marketing facilities in various
severe and unique worldwide locations, including Africa, Asia, Europe, the Middle East,
Russia, and North and South America. His activity in the aerospace field has included
engineering support for the Space Shuttle launch facilities at Kennedy Space Center (and for
those 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 Society
of Safety Engineers, National Fire Protection Association, Society of Petroleum Engineers, and
Society of Fire Protection Engineers. He is the author of the book "Application of HAZOP
and What-If Safety Reviews to the Petroleum, Petrochemical and Chemical Industries," which
is widely referred to within the petroleum and chemical industries. Mr. Nolan has also been
listed in "Who's Who in California" for the last ten years and has been elected to appear in
the 1996 International Edition of "Who's Who of Science and Engineering."
vii
List of Figures
1.
2.
3.
4.
5.
6.
7.
8
.
10.
11.
12.
Example of Autoignition Temperature Approximation Method . . . . . . . . . . . . . . . . . . . 32
Historical Average Financial Loss for Major Incidents . . . . . . . . . . . . . . . . . . . . . . . . 64
Safety Flow Chart . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
88
128
Example of Horizontal Vessel Rupture Calculation Method ....................
129
Example of Column Rupture Calculation Method . . . . . . . . . . . . . . . . . . . . . . . . . . .
132
Process Vessel Depressurization Flowchart . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International Electrical Area Classification Differences . . . . . . . . . . . . . . . . . . . . . . .
161
168
Explosion Overpressure Consequence Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Offshore Evacuation Flowchart . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
200
Electrical Installation Fire Control Flowchart . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
220
Relative Effectiveness of Various Spray Arrangements at Wellhead Flames . . . . . . . . . 233
xi
List of Tables
1.
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) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
Characteristics of Selected Common Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . .
39
Fire Hazard Zone (FHZ) Identification Example . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
56
Fire Extinguishing Explanations. Fire Hazardous Zone Drawings . . . . . . . . . . . . . . . . . 57
General Hazards of Common Petroleum Commodities . . . . . . . . . . . . . . . . . . . . . . . . .
60
Immediate Cause of Death (Gulf of Mexico. 1980-1990) . . . . . . . . . . . . . . . . . . . . . .
83
Cause of Incidents. Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
84
Example of Quantifiable Accident Scenario Summary . . . . . . . . . . . . . . . . . . . . . . . . .
92
Comparison of Industry and Insurance Spacing Tables . . . . . . . . . . . . . . . . . . . . . . .
102
Comparison of Dike Design Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
108
Drainage Requirements and Capacity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
109
Typical ESD Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
117
Typical Safety Integrity Levels (SIL) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
118
Firesafe Valve Test Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
122
General Guidelines for Material Disposal Methods . . . . . . . . . . . . . . . . . . . . . . . . . .
135
Recognized International Electrical Approval Testing Agencies . . . . . . . . . . . . . . . . . . 146
Recognized Fire Testing Laboratories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
167
Passive Fire Protective Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
170
Comparison of Fire Detectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
183
Application of Fixed Fire Detection Devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
184
Comparison of Common Hydrocarbon Vapor Hazards . . . . . . . . . . . . . . . . . . . . . . .
185
Comparison of Gas Detection Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
193
Example of Firewater Demand Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
206
Fire Pump Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
208
Test Standards for Fire Protection Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
210
Fixed Fire Suppression Design Option Basis. Application Table . . . . . . . . . . . . . . . . . 223
Fire Suppression System Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
224
Advantages and Disadvantages of Firewater Systems . . . . . . . . . . . . . . . . . . . . . . . .
225
Probability of Human Errors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
241
Color Coding Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
244
Notice
Reasonable care has been taken to assure that the book's content is authentic. timely and
relevant 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 responsibility
or 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 engaged
in rendering legal advice or other professional services. It is up to the reader to investigate and
assess his own situation. Should such study disclose a need for legal or other professional
assistance the reader should seek and engage the services of qualified professionals.
xii
Preface
The security and economic stability of many nations and multinational oil companies are highly dependent on
the safe and uninterrupted operation of their oil, gas and chemical facilities. One of the most critical impacts
that can occur to these operations are fire and explosions from accidental or political incidents. The recent
Gulf War amply demonstrates the impact these events can have on oil installations.
This publication is intended as a general engineering handbook and reference guideline for those personnel
involved with fire and explosion protection aspects of these critical hydrocarbon facilities. Several other
reference books are available that provide portions of the necessary information required to evaluate
hazards, provide fire protection measures, or determine insurance needs. However most are not fklly
complete in mentioning all technical subjects and some have become somewhat technically outdated. They
usually tend to be a collection of technical papers or else provide a broad coverage of subjects without much
practical applications or details. The main objective of this handbook is to provide some background
understanding of fire and explosion problems at oil and gas facilities and a general source of reference
material for engineers, designers and others facing fire protection issues, that can be practically applied. It
should also server as a reminder for the identification of unexpected hazards at a facility.
As stated, much of this book is intended to be a guideline. It should not be construed that the material
presented herein is the absolute requirement for any facility. Indeed, many organizations have their own
policies, standards and practices for the protection of their facilities. Portions of this book are a synopsis of
common practices employed in the industry and can be referred to as such where such information is
unavailable or outdated. Numerous design guidelines and specifications of major, small and independent oil
companies as well as information from engineering firms and published industry references have been
reviewed to assist in its preparation. Some of the latest published practices and research into fire and
explosions have also been mentioned.
This book in not intended to provide in-depth guidance on basic risk assessment principles nor on fire and
explosion protection engineering foundations or design practices. Several other excellent books are
available on these subjects and 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 prevention
and mitigation principals and methodologies from the effects of hydrocarbon fires and explosions. The
Chemical Process Industry (CPI), presents several different concerns that this book does not intend to
address. However the basic protection features of the Hydrocarbon Process Industry (HPI) are also
applicable to the chemical process industry and other related process industries.
Explosion and fire protection engineering principles for the hydrocarbon industries are still being researched,
evolved and expanded, as is the case with most engineering disciplines. This handbook does not profess to
contain all the solutions to fire protection problems associated with hydrocarbon facilities. It does however
x
Preface
try 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 resolve
concerns of fires and explosions.
Continually updated technical information is needed so that industrial processes can be designed to achieve
the optimum risk levels from the inherent material hazards but still provide acceptable economic returns.
This book is generally written from the point of reference of the United States basis, but does attempt to
reference other international codes, standards and practices where they have been referenced or heavily used
by the international oil industry. It does use SI units as the normal units of measure, as these are typically
used in the international oil industry.
Contents
.
1 INTRODUCI'ION
.......................................................
Historical Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal Influences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hazards and Their Prevention . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Systems Approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fire Protection Engineering Role . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk Management and Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Management Responsibility and Accountability ..........................
. OVERVIEW OF OIL AND GAS FACILITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2
Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Enhanced Oil Recovery @OR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Secondary Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Steam Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tertiary Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Chemical Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thermal Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recirculated Gas Drive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Refining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic Distillation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thermal Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Alkylation and Catalytic Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Typical Refinery Process Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production Percentages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
.
3 PHILOSOPHY OF PROTECTION PRINCIPALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General Philosophy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Worst Case Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ambient Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Independent Layers of Protection (ILP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Design Principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accountability and Auditability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. PHYSICAL PROPERTIES OF HYDROCARBONS
4
.............................
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Alkene Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
xiii
1
2
4
4
5
5
6
7
9
9
10
11
11
11
12
12
12
12
12
12
12
13
13
14
14
14
14
15
15
17
18
19
20
20
22
25
27
27
28
xiv
Contents
28
Alkyne Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cyclic Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
28
Characteristics of Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
29
Lower Explosive Limit &EL)/Upper Explosive Limit VEL) . . . . . . . . . . . . . . . . . . . .
29
29
Flash Point(FP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
Autoignition Temperature (AIT). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vapor Density . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33
Vapor Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33
Specific Gravity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33
Flammable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33
Combustible . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33
Heat of Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33
Description of Some Common Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . .
: . . . . . . 34
Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34
Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34
Methane (Cl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34
LNG. Liquefied Natural Gas (Cl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34
Ethane (C2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35
F’ropane(C3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35
Butane(C4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35
LPG. Liquefied Petroleum Gas (C3 & C4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35
Gasoline (C5 to C11) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
36
Condensate (C4. C5. C6 & )) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
36
Gas and Fuel Oils (C12 to C19) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
37
Lubricating Oils and Greases (C20 to C27) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
37
Asphalts and Waxes (C28 & )) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
37
5
. CHARACTERISTICS OF HYDROCARBON RELEASES. FIRES AND EXPLOSIONS
Hydrocarbon Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gaseous Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mists or Spray Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquid Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nabre and Chemistry of Hydrocarbon Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydrocarbon Fires . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nature of Hydrocarbon Explosions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Process System Explosions (Detonations) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vapor Cloud Explosions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Semi-confined Explosion Overpressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vapor Cloud Explosion Overpressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Boiling Liquid Expanding Vapor Explosions (BLEVE) .........................
Smoke and Combustion Gases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mathematical Consequence Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Methods of Flame Extinguishment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oxygen Depravation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Chemical Reaction Inhibition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flame Blow Out . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selection of Fire Control and Suppression Methods . . . . . . . . . . . . . . . . . . . . . . . . . . .
Terminology of Hydrocarbon Explosions and Fires . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . 41
42
42
43
43
44
46
48
48
48
50
50
51
52
53
55
55
55
55
55
55
56
58
. HISTORICAL SURVEY OF FIRE AND EXPLOSIONS I N THE
6
HYDROCARBON INDUSTRIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Relevancy of Incidents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
62
63
Contents xv
Offshore Oil Production and Exploration (USA) ..............................
Worst Fatal Incidents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Worst Property Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
81
81
82
85
7 RISKANALYSIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Safety Flow Chart . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk Identification and Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
A. Qualitative Reviews . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
B. Quantitative Reviews . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
C. Specialized Supplemental Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk Acceptance Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Relevant and Accurate Data Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
87
87
89
90
90
90
93
93
.
.
8 SEGREGATION. SEPARATION AND ARRANGEMENT . . . . . . . . . . . . . . . . . . . . . . . .
Segregation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Separation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Manned Facilities and Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Storage Facilities-Tanks
...............................................
Process Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Critical Utilities and Support Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fire Zones . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Facility Access and Egress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. GRADING. CONTAINMENT. AND DRAINAGE SYSTEMS .....................
9
Drainage Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Process and Area Drainage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Surface Drainage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Open Channels and Trenches . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Spill Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
.
10 PROCESS CONTROLS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
.
Human Observation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Instrumentation and Automation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electronic Process Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Process System Instrumentation and Alarms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfer and Storage Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Burner Management Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11 EMERGENCY SHUTDOWN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Definition and Objective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Design Philosophy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Activation Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Levels of Shutdown . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reliability and Fail Safe Logic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ESD/DCS Interfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Activation Points . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Activation Hardware Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Isolation Valve Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Emergency Isolation Valves (EIV) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subsea Isolation Valves (SSIV) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Protection Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
95
95
96
97
98
99
99
99
100
101
101
104
104
104
105
106
107
111
111
111
112
113
113
114
116
116
116
116
117
117
119
119
120
120
121
121
121
xvi
Contents
..................................................
123
12 DEPRESSURIZATION. BLOWDOWN AND VENTING . . . . . . . . . . . . . . . . . . . . . . . .
125
125
133
133
133
System Interactions
.
.
Objective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Blowdown . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Venting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13 OVERPRESSURE AND THERMAL RELIEF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pressure Relief Valves (PSV) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thermal Relief . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Solar Heat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thermal Relief Fluid Disposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Isolation Circumvention . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Disposal to the Oily Water Sewer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Surface Runoff . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pressure Relief Device Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
137
138
139
139
140
140
140
140
140
14 CONTROL OF IGNITION SOURCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Open Flames. Hot Work and Smoking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electrical Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electrical Area Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Surface Temperature Limits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Classified Locations and Release Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Explosionproof Rated Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intrinsically Safe Rated Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hermetically Sealed Electrical Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Relocation of Devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Surface Temperatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Static . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lightning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Internal Combustion Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SparkArrestors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
HandTools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
143
143
143
143
147
147
148
148
148
148
148
149
149
149
150
151
151
151
.
. ELIMINATION OF PROCESS RELEASES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15
Inventory Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vents and Relief Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sample Points . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drainage Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Storage Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pump Seals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vibration Stress Failure of Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rotating Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
.
16 FIRE AND EXPLOSION RESISTANT SYSTEMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Explosions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Definition of Explosion Potentials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Explosion Protective Design Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vapor Dispersion Enhancements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water Sprays . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Air Cooler Fans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
154
155
155
155
155
155
156
156
157
159
159
160
162
163
163
163
Contents
xvii
Location Optimization Based on Prevailing Winds ...........................
163
Supplemental Ventilation Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
163
164
Damage Limiting Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fireproofing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
164
166
Fireproofing Specificatioas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fireproofing Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
169
Radiation Shields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
171
Water Cooling Sprays . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
171
Vapor Dispersion Water Sprays . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
171
Locations Requiring Consideration of Fire Resistant Measures . . . . . . . . . . . . . . . . . . 172
Flame Resistance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
172
173
Fire Dampers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
173
Smoke Dampers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flame and Spark Arrestors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
173
Piping Detonation Arrestors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
174
. FIRE AND GAS DETECTION AND ALARM SYSTEMS
17
....................... 177
177
Fire and Smoke Detection Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Human Surveillance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
177
Manual Activation Callpoint (MAC)/Manual Pull Station (MPS) . . . . . . . . . . . . . . . . . 178
Telephone Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
178
Portable Radios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
178
Smoke Detectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
178
Ionization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
178
Photoelectric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
178
Dual Chamber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
179
179
Very Early Smoke Detection and Alarm P S D A ) . . . . . . . . . . . . . . . . . . . . . . . . . . .
179
Thermal or Heat Detectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
180
Optical (Flame) Detectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
180
Ultraviolet (VV)Detector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Single Frequency Infrared (IR) Detectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
181
181
Dual or Multiple Frequency Infrared (IR/IR) Detectors . . . . . . . . . . . . . . . . . . . . . . . .
182
Ultravioletflnfiared (UV/IR) Detectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Multi-Band Detectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
182
Gas Detection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
185
Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
186
187
Typical Hydrocarbon Facility Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Catalytic Detectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
188
Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
188
Infra-Red (IR) Beam Gas Detection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
189
189
Application (IR Beam) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Alarm Setting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
189
Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
190
190
Hazardous Area Classification Rating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fire and Gas Detection Control Panels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
190
191
Graphic Annunciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
191
Power Supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Emergency Baclolp Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
191
Time Delay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
191
Voting Logic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
191
Cross Zoning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
191
Executive Action . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
192
Circuit Supervision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
192
xviii
Contents
.
18 EVACUATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Alarms and Notifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Alarm Initiation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Evacuation Routes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Emergency Doors. Exits. and Escape Hatches . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Marking and Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Emergency Illumination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Offshore Evacuation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NortNSouth Atlantic and NortNSouth Pacific Environments . . . . . . . . . . . . . . . . . . .
Temperate and Tropic Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Means of Egress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flotation Assistance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
.
19 METHODS OF FIRE SUPPRESSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Portable Fire Extinguishers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water Suppression Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water Supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fire Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fire Pump Standards and Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Firewater Distribution Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Firewater Control and Isolation Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sprinkler Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water Deluge Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water Spray Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water Flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Steam Smothering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Water Curtains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Blow Out Water Iqjection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydrants. Monitors and Hose Reels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nozzles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foamwater Suppression Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Concentrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
High Expansion Foam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gaseous Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Carbon Dioxide Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Halon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Halon Replacements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oxygen Deficient Gas Inerting Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Chemical Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wet Chemical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dry Chemical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dual Agent Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Chemical and Foam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. SPECIAL LOCATIONS. FACILITIES AND EQUIPMENT
20
......................
Arctic Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Desert Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Offshore Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Offshore Floating Exploration and Production Facilities . . . . . . . . . . . . . . . . . . . . . . .
Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wellheads-Exploration (Onshore and Offshore) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loading Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
196
196
197
197
198
198
198
198
199
199
199
199
202
202
204
204
205
208
208
209
210
210
210
211
211
211
212
212
213
213
214
214
214
216
216
216
218
219
219
221
221
221
221
221
228
228
228
229
230
230
231
234
Contents
xix
Electrical Equipment and Communication Rooms . . . . . . . . . . . . . . . . . . . . . . . . . . .
Battery Rooms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Enclosed Turbines or Gas Compressor Packages . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Heat Transfer Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cooling Towers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil Filled Transformers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydrocarbon Testing Laboratories .......................................
Warehouses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cafeterias and Kitchens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
234
235
235
236
237
237
237
238
238
21 HUMAN FACTOR AND ERGONOMIC CONSIDERATIONS ....................
Human Attitude . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Access and Acceptability ...............................................
Instructions, Markings and Labeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Color and Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Colors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Numbering and Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Instrumentation Alarm Overload ........................................
Noise Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Panic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accommodation of Religious Functions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
240
243
243
243
244
244
245
245
245
246
246
246
APPENDIX A: TESTING FIREWATER SYSTEMS ...............................
A.l Testing of Firewater Pumping Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
A.2 Testing of Firewater Distribution Systems ..............................
A.3 Testing of Sprinkler and Deluge Systems ...............................
A.4 Testing of Foam Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
A5 Testing of Hose Reels and Monitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
249
250
254
258
259
260
.
APPENDIX B: REFERENCE DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
262
263
B.l Fire Resistance Testing Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
B.2 Explosion and Fire Resistance Ratings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
266
B.3 National Electrical Manufacturers Association (NEMA) . . . . . . . . . . . . . . . . . . . 269
273
B.4 Hydraulic Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
274
B.5 Selected Conversion Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
.........................................................
278
.............................................................
283
ACRONYM LIST
GWSSARY
INDEX
.................................................................
289
Chapter 1
Introduction
Fire, explosions and environmental pollution are the most serious "unpredictable"life affecting and business
losses having an impact on the hydrocarbon industries today. These issues have essentially existed since the
inception of industrial scale petroleum and chemical operations during the middle of the last century. They
continue to occur with ever increasing financial impacts. It almost appears that the management of industry
is oblivious, or else must be careless, to the potential perils under their command. Although in some circles
most accidents can be thought of as non-preventable, all accidents are in fact preventable.
Research and historical analyses have shown that the main cause of accidents or failures can be categorized
according to the following basic areas:
Ignorance
a. Incompetent design, construction or inspection occurs.
b. Supervision or maintenance occurs by personnel without the necessary understanding.
c. Assumption of responsibility by management without an adequate understanding of risks.
d. There is a lack of precedent.
e. There is a lack of sufficient preliminary information.
f Failure to employ competent Loss Prevention professionals.
Economic Considerations
a. Initial engineering and construction costs for safety measures appear uneconomical.
6. Operation and maintenance costs are unwittingly reduced to below what is necessary.
Oversight and Negligence
a.
b.
c.
d.
e.
Otherwise competent professional engineers and designers commit errors.
Contractual personnel or company supervisors knowingly assume high risks.
Lack of proper coordination in the review of engineering designs.
Failure to conduct prudent safety reviews or audits.
Unethical behavior occurs.
1
2
Handbook of Fire and Explosion Protection
Unusual Occurrences
a. Natural catastrophes - earthquakes, extreme weather, etc.
b. Political upheaval terrorist activities.
c. Labor unrest, vandalism.
-
As can be seen, the real cause of most accidents is what might be classified as human errors. Most people
have good intentions to perform a function properly, but where shortcuts, easier methods or considerable
economic gain opportunities appear or present themselves, human vulnerability usually succumbs to the
temptation. Therefore it is prudent in any organization, especially where high risk facilities are operated, to
have a system in place to conduct considerable independent checks, inspections, and safety audits of the
design and construction of the installation.
This book is about engineering principles and philosophies to identi@ and prevent accidents associated with
hydrocarbon 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 can
go wrong. Some of these human errors are insignificant and may be never uncovered. However others may
lead to catastrophic incidents when combined with other activities. Recent incidents have shown that any
"fully engineered" and operational process plants can experience total destruction. Initial conceptual designs
and operational philosophies have to address the possibilities of a major incident occurring and provide
measures to prevent or mitigate such events.
Historical Background
The first commercially successful oil well was drilled in August 1859 in Titusville (Oil Creek), Pennsylvania
by Colonel Edwin Drake. Few people realize that Colonel Drake's famous oil well caught fire and some
damage was sustained to the structure shortly after its operation. Later in 1861 another oil well at "Oil
Creek", close to Drake's well, caught fire and grew into a local conflagration that burned for three days
causing 19 fatalities. One of the earliest oil refiners in the area, Acme Oil Company, suffered a major fire
loss in 1880, from which it never recovered. The State of Pennsylvania passed the first anti-pollution laws
for the petroleum industry in 1863. These laws were enacted to the prevent release of crude oil into
waterways next to oil production areas. At another famous early oil field named "Spindletop", an individual
smoking set off the first of several catastrophic fires, which raged for a week, only three years after the
discovery of the reservoir. Major fires occurred at Spindletop almost 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 extensive
flaring of the then "unmarketable" reservoir gas. Hydrocarbon fires were accepted as part of the early
industry and generally little efforts were made to stem the their existence.
Ever since the inception of the petroleum industry the level of fires, explosions and environmental pollution
that have precipitated from it, has generally paralleled its growth. As the industry has grown so has the
magnitude of its accidental events. Relatively recent events such as the Flixborough incident (1974),
Occidental's Piper Alpha disaster (1988), and Exxon's Valdez oil spill (1989) have all amply demonstrated
the extreme financial impact these accidents can produce.
After the catastrophic fire that burned ancient Rome in 64 A. D., the emperor Nero rebuilt the city with fire
precautions that included wide public avenues, limitations in building heights, provision of fireproof
construction and improvements to the city water supplies to aid in fire fighting. Thus it is very evident that
Introduction
3
the basic fie protection requirements such as limiting &el supplies (fireproof construction), removing the
available ignition sources (wide avenues and limited building heights to prevent carryover of flying brand
embers) and providing f i e control and suppression (water supplies), have essentially been known since
civilization began.
Amazingly, "Heron of Alexandria", the technical writer of antiquity (circa 100 A.D.), describes a two
cylinder pumping mechanism with a dirigible nozzle for fighting fires in his journals. It is very similar to the
remains 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 to
provide fire fighting water. There is therefore considerable evidence society has generally tried to prevent or
mitigate the effects of fires, admittedly after a major mishap has occurred.
The Hydrocarbon Processing Industry (HPI), has traditionally been reluctant to invest capital where an
immediate direct return on the investment to the company is not obvious, as would any business enterprise.
Additionally financial fire losses in the petroleum and related industries were relatively small up to about the
1950's. This was due to the small size of hcilities and the relatively low value of oil and gas to the volume
of production. Until 1950, a fire or explosion loss of more than 5 million U. S. Dollars had not occurred in
the refining industry in the USA. Also in this period, the capital intensive offshore oil exploration and
production 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 well
was capped and considered as an uneconomical reservoir. Since gas development was limited, large vapor
explosions were relatively rare and catastrophic destruction from petroleum incidents was essentially
unheard of The outlays for petroleum industry safety features were traditionally the absolute minimum
required by governmental regulations. The development of loss prevention philosophies and practices were
therefore not effectively developed within the industry.
In the beginnings of the petroleum industry, usually very limited safety features for fire or explosion
protection were provided, as was evident by the many early blowouts and fires. The industry became known
as a "risky" operation, not only for economic returns, but also for safety (loss of life and property
destruction) 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 and
petrochemical complexes, increased development and uses of gas deposits, coupled with the rise of oil and
gas prices in the 1970s have sky-rocketed the value of petroleum products and facilities. It has also meant
the industry was rapidly awakened to the possibility of large financial losses if a major incident occurred. In
fact 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 and
resume production was reportably over one billion U.S. Dollars. In some instances legal settlements have
been 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 oil
reserves are eventually reduced and depleted.
It should also be remembered that a major incident may also force a company to literary withdrawn from
that portion of the business sector where public indignation, prejudice or stigma towards the company
strongly develops because of the loss of life suffered. The availability of 24 hour news transmissionsthrough
worldwide satellite networks virtually guarantees a significant incident in the hydrocarbon industry will be
known worldwide very shortly after it occurs, resulting in immediate public reaction.
Only in the last several decades has it been well understood and acknowledged by most industries, that fire
and explosion protection measures may be also be operational improvemyt measures, as well as a means of
protecting a facility against destruction. An example of how the principle of good safety practice equates to
good operating practice is the installation of emergency isolation valves at a facility inlet and outlet pipelines.
In an emergency they serve to isolate &el supplies to an incident and therefore limit damage. In theory they
could also serve as an additional isolation means to a facility for maintenance and operational activities when
4
Handbook of Fire and Explosion Protection
a major facility isolation requirement occurs. It can be qualitatively shown that it is only limitations in
practical knowledge by those involved in facility construction and cost implications that have generally
restricted application of adequate fire protection measures throughout history.
Nowadays safety features should hopehlly promulgate die design and arrangement of all petroleum
facilities. In fact, in highly industrial societies these features must demonstrate to regulatory bodies that the
facility has been adequately designed for safety, before permission is given for their construction. It is thus
imperative that these measures are well defined early in the design concept in order to avoid costly projects
change orders or later incident remedial expenses required by regulatory bodies. Industry experience has
demonstrated that reviewing a project design early in the conceptual and preliminary stages for safety and
fire protection features is more cost effective than performing reviews after the designs have been
completed. The "Cost Influence Curve" for any project acknowledges that 75% of a project cost is defined
in the first 25% of the design. On average the first 15% of the overall project cost is usually spent on 90%
of the engineering design. Retrofit or modification costs are estimated at ten times the cost after the plant is
built and 100 times after an incident occurs. It should also be realized that fire protection safety principles
and 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~ough and systematic risk
analysis.
A
i '
Legal Influences
Before 1900, the U.S. industry and the Federal Government generally paid little notice to the safety of
industrial workers. Only with the passage of the Workmen's Compensation Laws in the U.S. between 1908
and 1948 did businesses start to improve the standards for industrial safety. Making the work environmentally
safer 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 losses
incurred by industrial accidents, in order to keep production output available for the war effort. In the
1960s, a number of industry specific safety laws were enacted in the U.S. They included the Metal and
Nonmetallic Mine Safety Act, the Coal Mine Health and Safety Act, and the Construction Safety Act, all of
which mandated safety and fire protection measures for workers by the companies employing them. A
major U.S. policy towards industrial safety measures was established in 1970, when for the first time all
industrial workers in businesses affected by interstate commerce were covered by the Occupational Safety
and Health Act. Under this act, the National Institute for Occupational Safety and Health (NIOSH) was
given responsibility for conducting research on occupational health and safety standards, and the
Occupational Safety and Health Administration (OSHA) was charged with setting, promulgating, and
enforcing appropriate safety standards in industry.
Hazards and Their Prevention
Petroleum and chemical related hazards can arise from the presence of combustible or 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 as
chemical, biological, or physical hazards, can cause work related injuries or fatalities. Although all of these
hazards are of concern this book primarily concentrates on fire and explosions hazards that can cause
catastrophic events.
Hazards may also result from the interaction between company employees and the work environment; these
are called "ergonomic" hazards. If the physical, psychological, or environmental demands on workers
exceed their capabilities, an ergonomic hazard exists. These hazards, in themselves may lead to fbrther
major incidents when the individual cannot perform properly under stress during critical periods of plant
Introduction
5
operations. Ergonomic hazards can cause either physiological or psychological stress in individuals.
Industrial fire protection and safety engineers attempt to eliminate hazards at their source or to reduce their
intensity with protective systems. Hazard elimination may typically require the use of alternative and less
toxic materials, changes in the process, spacing or guarding, improved ventilation or, spill control or
inventory 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 the
cost to implement safety measures.
Systems Approach
In recent years, engineers have developed a systems approach (termed system safety engineering) to
industrial accident prevention. Because accidents arise from the interaction of workers and their work
environments, both must be carehlly examined to reduce the risk of injury. Injury can result from poor
facility designs, working conditions, the use of improperly designed equipment and tools, fatigue,
distraction, lack of skill, and risk taking. The systems approach examines all areas in a systematic fashion to
ensure all avenues of accident development have been identified and analyzed. Typically the following major
areas are examined: all work locations to eliminate or control hazards, operating methods and practices, and
the training of employees and supervisors. The systems approach, moreover, demands a thorough
examination of all accidents and near misses. Key facts about accidents and injuries are recorded, along with
the history of the worker involved, to check for and eliminate any patterns that might lead to hazards.
The systems approach also pays special attention to the capabilities and limitations of the working
population. It recognizes large individual differences among people in their physical and physiological
capabilities. The job and the worker, therefore, should be appropriately matched whenever possible.
The safety and risk of a hydrocarbon facility cannot be assessed solely on the basis of fire fighting systems or
past loss histories. The overall risk can only be assessed by defining loss scenarios and an understanding of
the risk philosophy adopted by senior management.
Due to the destructive nature of hydrocarbon forces when handled incorrectly, fire and explosion protection
principles should be the prime feature in the risk philosophy of any hydrocarbon facility. Vapor cloud
explosions in particular are consider the highest risk at a hydrocarbon facility. Disregarding the importance
of protection features or systems will eventually prove to be costly both in economic and human terms
should a catastrophic incident occur without adequate safeguards.
Fire Protection Engineering Role
Fire protection engineering is not a stand alone discipline that is brought in at an indiscriminate state of a
project design or even as an after the fact design review of a project. Fire protection principles should be an
integrated aspect of an oil or gas project that reaches into all aspects of how a facility is designed arranged
and constructed. They are usually the prime starting and focal points in the layout and process
arrangements 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 a
project team or engineering staff, he should mainly be in an advisory role. He can advise on the most
prudent and practical methods to employ for fire protection objectives. The fire protection or risk engineer
must therefore be knowledgeable in each of the various disciplines. In addition he must have expertise in
hazard, safety, risk and fire protection principles and practices applied to the petroleum or other related
industries.
6
Handbook of Fire and Explosion Protection
Risk Management and Insurance
It should also be realized that science of risk management also provides other avenues of protection besides
technical solutions to a risk. There are four elements of risk management available to resolve a concern.
The four methods, in order of preference are:
(1)
(2)
(3)
(4)
Risk Avoidance
Risk Reduction
Risk Insurance
Risk Acceptance
This handbook concentrates primarily on risk avoidance techniques and risk reduction. Risk acceptance and
risk insurance techniques are general monetary measures that are dependent on the financial options
available to the Facility Manager. These are based on a company's policy and preferences in the insurance
market. If used, they rely on financial measures within an organization to provide for financial security in
case of an incident. Although these measures can accommodate financial losses, they are ineffective in
reputation and prestige affects from an incident @e., negative effects). This is why risk avoidance and risk
reduction measures are the preferred method of solution for a high risk problem with the petroleum and
industrial community at large.
Risk avoidance involves eliminating the cause of the hazard. This is accomplished by changes in the inherent
risk features of the process or facility. Risk reduction concerns the provision of prevention or protective
measures that will lessen the consequences of a particular accidental event.
Risk insurance is the method chosen when the possible losses are financially too great to retain internally by
risk acceptance and in some cases too expensive to prevent or avoid. However even the risk insurers will
want 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-chemical
plants are owned by several companies or participating national governments. The majority owner or most
experience company is usually the onsite operator. The objective is to share the fbnding and financial risk of
finding oil, developing and operating the facility. Should the exploration hole prove "dry", i.e., commercially
uneconomical, 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 risk
over a wider range of prospects. It also lessens the financial impact to the companies if a catastrophic
incident occurs that destroys the facility, since each company must also share in the damage cost
proportionately to their investment stake. If a company historically has a poor record in relation to safe
operations, other companies may be hesitant to invest fbnds with it, since they may consider that company
too high a risk. Alternatively they may demand to be the operator since they would feel better qualified and
the risk of losing the facility would be lower.
Property damages and legal liabilities are not the only sources of financial impacts a company may suffer at
the time of an incident. Business interruption losses will also occur since the facility will not longer be able
to function as intended. Analysis of insurance industry claims data shows that business interruption losses
are generally three times the amount of physical property damage. Often the justification for a safety feature
may not be the loss of the component itself but of the impact to operations and loss revenue it produces.
Introduction
7
Most 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 have
supplied 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 has
always been one of wild, aloof or above safety features or requirements. Due to the dramatic effects of
occasional drilling blowout incidents, this impression is still difficult to eradicate. This conception also exists
within the general public. In some organizations where these drilling personnel are idolized, they will usually
or may eventually be promoted to senior management positions. Their independent attitude may still prevail
or impressions by subordinate employees will be preconceived to a lack of safety concern due to their
background. This is not to say other departments or individual job classifications within an organization may
not be just as ill perceived (e.g., construction or project management).
There are and probably will always be requirements to achieve oil and gas production or refining for any
given project as soon as possible. Therefore the demands on drilling, construction and project management
to achieve a producing or refining facility as soon as possible may be in some cases be in direct conflict with
prudent safety measures, especially if they have not been adequately planned or provided before the start of
the project. Operations management should not be mistakenly led into believing a facility is ready to operate
just because it is "felt" by those performing its construction that it is complete.
However unfortunate, drilling personnel have been historically directly connected with major incidents
within the petroleum industry on numerous occasions and the impression, consciously or unconsciously still
remains. On the other hand, it is very rare or non-existent that a loss prevention professional is promoted to
the ranks of senior management, even though they may have been keenly conscientious in maintaining a high
economic return to the company by the prevention of catastrophic accidents.
Safety achievement is a team approach. All parties to the operation must participate and contribute.
Without team cohesiveness, commitment and accountability objectives will not be met. Specifically
important is the leadership of a team, which in business operations is the senior management.
Senior management responsibility and accountability are the keys to providing effective fire and explosion
safety measures at any facility or operation. The real attitude of management towards safety will be
demonstrated 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 Prevention
personnel will not be conductive or lead to good results. The effect of indifference or lack of concern to
safety measures is always reflected top down in any organizational structure. Executive management must
express and contribute to an effective safety program in order for satisfactory results to be achieved. All
asckknts s h l d 5e thght o-€ as prevesabk. Acc*nt preventio-rl a d ek&x?ith s h ! d bc em*red as
an ultimate goal of any organization. Where a safety culture is "nurtured1',continual economic benefits are
usually derived. On the other hand, it has been stated that the 150 largest petroleum and chemical industry
incidents during the past 30 years have involved breakdowns in the management of process safety.
8
Handbook of Fire and Explosion Protection
Bibliography
1.
Ellis, W. D., On The Oil Lands, R. R. Donnelly & Sons, Willard, OH, 1983.
2.
Giddens, P. H., Earlv Days of Oil, A Pictorial Histow of the Beginnings of the Industry in Pennsylvania, Princeton
University Press, Princeton, NJ, 1948.
3. Head, George L, and Stephen Horn 11, Essentials of the Risk Management Process, Vols. I & 11, Insurance Institute
of America, Malvern, PA, 1985.
4.
Knowles, R. S., The First Pictorial Historv of the American Oil and Gas Industry 1859-1983, Ohio University Press,
Athens, OH, 1983.
5.
MacDonald, D., Coruorate Risk Control, John Wiley and Sons, Co. New York, NY, 1990.
6.
Rundell Jr., W., Earlv Texas Oil. A Photoa-aDhic Historv. 1866-1936, Texas A & M University Press, College
Station, TX, 1977.
7.
Sedgwick Energy, Limited, An Introductionto Energy Insurance, Sedgwick Energy, Ltd., London, U.K., 1994
8.
Sprague De 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 2
Overview of Oil and Gas Facilities
Petroleum and gas deposits occur naturally throughout the world in every continent and ocean. Most of the
deposits are several thousand meters deep. The petroleum industry's mission is to find, develop, refine, and
market these resources in a fashion that achieves the highest economic return to the owners or investors
while adequately protecting the fixed investment in the operation.
Oil and gas operations today are almost universally constitute a continuous run operation versus a batch
process. Once fluids and gases are found and developed they are transported from one process to another
without delay or interruption. This provides improved economics, but also increases the fuel inventories and
thereby inherent risk in the operation.
The main facets of the oil and gas industry are exploration, production, refining, transportation and
marketing. A brief description of each of these sectors is provided in this chapter. Although some
petroleum companies are fully integrated with each of these operations others are segmented and only
operate in their particular area of expertise or highest financial return.
Exploration
Exploring for oil and gas reservoirs consist mainly of geophysical testing and
drilling '!wildcat" wells. To find crude oil or gas reserves underground, geologists
search for a sedimentary basin in which shales rich in organic material have been
buried for a sufficiently long time for petroleum to.have formed. The petroleum
must also have had an opportunity to migrate into porous traps that are capable of
holding a large amount of fluid or gas. The occurrence of crude oil or gas is limited
both by these conditions, which must be met simultaneously, and by the time span
of tens of millions to a hundred million years. Surface mapping of outcrops of
sedimentary beds makes possible the interpretation of subsurface features, whch
can then be supplemented with information obtained by drilling into the crust and
retrieving cores or samples of the rock layers encountered.
Seismic techniques, the reflection and refraction of sound or shock waves propagated through the earth, are
also used to reveal details of the structure and interrelationship of various layers in the subsurface. The
shock or sound waves record densities in the earth's surface that may indicate an oil or gas reservoir.
Explosive charges or vibration devices are used to impart the required shock wave.
Ultimately the only way to prove that oil is present underground is to drill an exploratory well. Most of the
9
10
Handbook of Fire and Explosion Protection
oil provinces in the world have initially been identified by the presence of surface seeps, and most of the
actual reservoirs have been discovered by so-called wildcatters who relied perhaps as much on intuition as
on science. The term wildcatter comes from West Texas, USA, where in the early 1920s, drilling crews
came across many wildcats as they cleared locations for exploratory wells. The hunted wildcats were hung
on the oil derricks, and the wells became known as wildcat wells. A wildcat well is considered essentially a
test boring to verify the existence and "commercial" quantities of quality oil or gas deposits. Since the
absolute characteristics of a wildcat well are unknown, a high pressure volatile hydrocarbon reservoir may
be easily encountered. As drilling occurs deeper into the earth the effects of overburden pressure of any
fluid in the wellbore increases. If these reservoirs are not adequately control during exploratory drilling, they
can lead to an uncontrolled release of hydrocarbons through the drilling system. This is commonly termed a
"blowout", whether it is ignited or not. Blowout preventers, BOPS (i.e., hydraulic shear rams) are provided
to control and prevent a blowout event. Uncontrolled drilling hydrostatic pressure is considered the primary
cause of drilling blowouts (while evidently the underlying cause is human error).
An oil field may comprise more than one reservoir, i.e., more than one single, continuous, bounded
accumulation of oil. Indeed, several reservoirs may exist at various increasing depths, stacked one above the
other, isolated by intervening shales and impervious rock strata. Such reservoirs may vary in size from a few
tens of hectares to tens of square kilometers. Their layers may be from a few meters in thickness to several
hundred or more. Most of the oil that has been discovered and exploited in the world has been found in a
relatively few large reservoirs. In the USA, for example, 60 of the approximately 10,000 oil fields have
accounted for half of the productive capacity and reserves in the country.
Production
Underground oil or gas deposits are produced through wells that are drilled to penetrate the oil bearing rock
formations. 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 is
rotated by being coupled to a rotating "table" on the derrick floor. The drilling device or "bit" at the end of
the string, is generally designed with three cone-shaped wheels tipped with hardened teeth. Additional
lengths of drill pipe are added to the drill string as the bit penetrates deeper into the earth's crust. The force
required for cutting into the earth comes from the weight of the drill pipe itself. Drill cuttings or the
formation rock is continually lifted to the surface by a circulating fluid ("mud") system driven by a pump.
The drilling mud is constantly circulated down through the drill pipe, out through nozzles in the drill bit, and
then up to the surface through the space between the drill pipe and the bore through the earth (the diameter
of 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 horizontally into a reservoir.
Once the well is drilled, the oil is either released under natural pressure or
pumped out. Normally crude oil is under pressure; (were it not trapped by
impermeable rock it would have continued to migrate upward), because of
the pressure differential caused by its buoyancy When a well bore is drilled
into a pressured accumulation of oil, the oil expands into the low-pressure
sink created by the well bore in communication with the earth's surface As
the well fills up with fluid, a back pressure is exerted on the reservoir, and
the flow of additional fluid into the well bore would soon stop, were no other
conditions involved Most crude oils, however, contain a significant amount
of natural gas in solution, and this gas is kept in solution by the high pressure
in the reservoir The gas comes out of solution when the low pressure in the
well 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 the
earth's surface As fluid withdrawal continues from the reservoir, the pressure within the reservoir gradually
decreases, and the amount of gas in solution decreases As a result, the flow rate of fluid into the well bore
decreases, 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
11
be installed in the well bore to continue producing the crude oil. Gas reservoirs by their nature are high in
pressure and can be essentially tapped into to obtain the deposit.
The produced oil or gas is connected to surface flowlines from the wellhead pumping unit or surface
regulating valve assembly typically referred to as a Christmas tree but to its arrangement. The flowlines
collect the oil or gas to local tank batteries or central production facilities for primary oil, water, and gas
separation. The reliability of electrical submersible pumps (ESPs) has increased to the point where the
submersible electrical pump is commonly used for the production of liquid hydrocarbons where artificial liR
is required for production.
Primary separation facilities process the produced fluids and gases into individual streams of gas, oil and
water. These facilities are commonly referred to as Gas Oil Separation Plants (GOSP's), Central Processing
Facilities (CPF) or if located offshore on drilling, production and quarters platforms (PDQs). The offshore
platforni may either float on the sea or be supported on steel or concrete supports secured to the ocean
floor, where it is capable of resisting waves, wind, and in Arctic regions ice flows. In some instances surplus
oil tankers have been converted into offshore production and storage facilities.
The produced fluids and gases are typically directed into separation vessels. 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 and
salt will also be removed. Deadly hydrogen sulfide (HzS), is sometimes also encountered, which is extracted
simultaneously with the petroleum production. Crude oil containing H2S can be shipped by pipeline and
used as a refinery feed but it is undesirable for tanker or long pipeline transport. The normal commercial
concentration of impurities in crude oil sales is usually less than 0.5% BS & W (Basic Sediment and Water)
and 10 Ptb (Pounds of salt per 1,000 barrels of oil). The produced liquids and gases are then transported to
a gas plant or refinery by truck, railroad tank car, ship, or pipeline. Large oil field areas normally have direct
outlets to major, common-carrier pipelines.
Enhanced Oil Recovery (EOR)
Most petroleum reservoirs are developed by numerous production wells. As the primary production
approaches its economic limit, perhaps approximately 25 percent of the crude oil in place from a particular
reservoir has been withdrawn. The petroleum industry has developed unique schemes for supplementing the
production of gaseous and liquid hydrocarbons that can be obtained, by taking advantage of the natural
reservoir energy and geometry of the underground structures. These supplementary schemes, collectively
known as enhanced oil recovery (EOR) technology, can increase the recovery of crude oil, but only at the
additional cost of supplying extraneous energy to the reservoir. In this way, the recovery of crude oil has
been increased to an overall approximate average of 33 percent of the original "in the ground" oil. As the
industry matures and reservoirs are considered depleted, EOR techniques will become the prevalent method
of production for most of the petroleum reservoirs and the overall recovery rates will increases.
Secondary Recovery
Water Injection
In a completely developed oil or gas field, the wells may be drilled anywhere from 60 to 600 m (200
to 2,000 ft) horizontally from one another, depending on the nature of the reservoir. If water is
pumped into alternate wells in such a field, the pressure in the reservoir as a whole can be maintained
or even increased. In this way the daily production rate of the crude oil also can be increased. In
addition, the water physically displaces the oil, thus increasing the recovery efficiency. In some
reservoirs with a high degree of uniformity and little clay content, water flooding may increase the
recovery efficiency to as much as 60 percent or more of the original oil in place. Water flooding was
first introduced in the Pennsylvania oil fields, somewhat accidentally, in the late 19th century, and has
since been used throughout the world.
12
Handbook of Fire and Explosion Protection
Steam Injection
Steam injection is used in reservoirs that contain very viscous oils, i.e., those that are thick and flow
slowly. The steam not only provides a source of energy to displace the oil, it also causes a marked
reduction in viscosity (by raising the temperature of the reservoir), so that the crude oil flows faster
under any given pressure differential.
Gas Injection
Some 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 C 0 2 is
recovered, recompressed, and reinjected into the gaseous portion of the reservoir. The reinjected
natural gas or C 0 2 maintains reservoir pressure and helps push additional liquid oil hydrocarbons out
of liquid portion of the reservoir.
Tertiary Recovery
As the production lives of secondary methods lose their efficiency, fbrther techniques have been tested and
found to continue to release additional amounts of oil. These methods are considered tertiary methods and
are generally associated with chemical or gaseous recirculation methods of recovery. Some instances of insitu thermal recovery have been used but not on a large extent.
Chemical Injection
Proprietary methods are developed which inject chemical detergent solutions into the oil reservoirs to
increase the viscosity of the remaining oil reservoirs. After the chemical detergent solutions are
injected, polymer thickened water is provided behind the chemical detergent to drive the oil towards
producing wells.
Thermal Recovery
Underground hydrocarbons are ignited, which creates a flame front or heat barrier that pushes the oil
towards the producing well.
Recirculated Gas Drive
Natural gas or C 0 2 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 is
marginal).
Other experimental methods have been proven technologically feasible but are still commercially unviable.
These include in-situ combustion, electromagneticcharging, and similar methods.
Transportation
Transportation is the means by which onshore and offshore oil and gas production is carried to the
manufacturing centers and from which refined products are carried to wholesale and retail distribution
centers.
Petroleum commodities (gas and oil), are normally transported in pipelines from source points to collection
and processing facilities. Pipelines route unprocessed or refined products to centers of manufacturing and
sales from areas of extraction, separation and refining. Where a pipeline system is unavailable, trucking is
Overview of Oil and Gas Facilities
13
usually employed.
Shipment from continent to continent is accomplished large tanker vessels, carriers or ships, which is the
most 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 size
range between 160,000 to 550,000 dwt. Refined products are typically shipped in vessels of up to 40,000
dwt. Class rating. LNG or LPG vessels are typically in the range of up to 100,000 cubic meter (838,700
bbls.) capacity.
In order to achieve a complete transportation system a host of other subsystems support the transportation
system operations. Loading facilities, pumping and compressor stations, tank farms and metering and
control devices are necessary for a complete transportation system of liquid or gases hydrocarbon
commodities.
Refining
In its natural state, crude oil has no practical uses except for burning as fuel after removal of the more
volatile gases that flow with it from the production well. It therefore is "taken apart" and sorted into its
principal components for greater economical return. This is accomplished in a refinery that separate the
various fractions into 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 chemical
processes: (1) Distillation, (2) Molecular structure alteration (Thermal Cracking, Reforming, Catalytic
Cracking, Catalytic Reforming, Polymerization, Alkylation, etc.), and (3) Purification.
There are numerous refining methods employed to extract the fractions of petroleum liquids and gases. A
particular refinery process design is normally dependent on the raw feedstock characteristics (e.g., crude oil
and 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 a
prescribed set of parameters such as time, temperature, pressure and ingredients. The following is summary
of the some of the basic processes that are used in refinery processes.
Basic Distillation
The basic refining tool is the common distillation unit. It is usually the first process in refining crude
oils. Crude oil normally begins to vaporize at a temperature somewhat less than what is required to
boil water. Hydrocarbons with the lowest molecular weight vaporize at the lowest temperatures,
whereas successively higher temperatures are applied to separate or distill the larger molecules.
The first material to be distilled from crude oil is the gasoline fraction, followed in turn by naphtha
and then by kerosene. The residue in the batch vessel or "kettle", in the old still refineries, was then
treated with caustic and sulfuric acid, and finally steam distilled. Lubricants and distillate fuel oils
were obtained from the upper regions and waxes and asphalt fiom the lower regions of the distillation
apparatus. In the later 19th century, gasoline and naphtha fractions were actually considered a
nuisance because little need for them existed. The demand for kerosene also began to decline
because of the growing production of electricity and the wide spread use of electric lights. With the
14
Handbook of Fire and Explosion Protection
introduction of the automobile, however, the demand for gasoline suddenly burgeoned, and the need
for greater supplies of crude oil increased accordingly.
Thermal Cracking
In an effort to increase the yield from distillation a thermal cracking process was developed. In
thermal cracking, the heavier portions of the crude oil are heated under pressure and at higher
temperatures. This results in the large hydrocarbon molecules being split into smaller ones, so that
the yield of gasoline from a barrel of crude oil is increased. The efficiency of the process is limited
because at the high temperatures and pressures that are use. Typically a large amount of coke is
deposited in the reactors. This in turn requires the use of still higher temperatures and pressures to
crack the crude oil. A coking process was then invented in which fluids were re-circulated; the
process ran for a much longer time, with far less buildup of coke.
Alkylation and Catalytic Cracking
Two additional basic processes, alkylation and catalytic cracking, were introduced in the 1930s and
further increased the gasoline yield from a barrel of crude oil. In the alkylation process, small
molecules produced by thermal cracking are recombined in the presence of a catalyst. This produces
branched molecules in the gasoline boiling range that have superior properties (e.g., higher
antiknock ratings as a fuel for high-powered internal combustion engines as those used in today
automotive engines).
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 hydrocarbons that can then be
recombined by alkylation, isomerization, and catalytic reforming to produce high antiknock engine
fuels and specialty chemicals. The production of these chemicals has given birth to the Chemical
Process 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. The
petrochemical industry uses about five percent of the total supply of oil and gas in the U.S.
Purification
Purification processes are used to remove impurities such as sulfurs, mercury, gums and waxes. The
processes include absorption and stripping, solvent extraction and thermal diffision.
Typical Refinery Process Flow
At a refinery all crude oil normally first goes to crude distillation. The crude is run though piping
inside a furnace where high temperatures cause it to partially vaporize before it flows into a
fractionating 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 liquid
naptha 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 its
own lighter components.
Liberated gasses are drawn off at the top of the tower with the naptha. The gas is recovered to
manufacture refrigerated liquefied petroleum gas (LPG). The naptha is condensed at a temperature
of 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 further
reforming. 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 usually
brought up to specification with respect to sulfur content with hydrodesulfurization. The heavy oil
Overview of Oil and Gas Facilities
15
from the bottom of the crude unit can be used in fuel oil blending or can be processed hrther in
vacuum 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 of
affecting fuel oil quality by subjecting it to excessive temperatures.
After products are produced by refining they are hrther enhanced in a blending unit. In this unit the
finished products are made by mixing the components in blending tanks. To gasoline for example,
coloring dyes or special additives maybe added. The completed blends are tested and then routed to
tank farm storage or shipment.
Production Percentages
The demand for lighter distillation products for gasoline and jet engines has also increased the relative
hazard levels of refinery facility processes over the years. A comparison of product yields from 1920
to today shows the dramatic increases in light product production percentages.
Product
1920s
Today
YOChange
Gasoline
11
21
+90 %
Kerosene
5.3
5
-6 %
Gas Oils
20.4
13
-36 %
Heavy Oils
5.3
3
-6 %
By producing higher quantities of "lighter" hels, the plants themselves have become higher risks just
by the nature of the produced percentages than in previous years. The corresponding expansion of
these facilities through the decades has also combined with more explosive products to heighten risks
levels unless adequate protective measures are provided.
Marketing
Bulk Plants, Distribution and Marketing Terminals store and distribute the finished products from the
refineries and gas plants. Typically these facilities handle gasoline, diesel, jet fuels, asphalts, and
compressed 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 smaller
compared to refinery storage and are normally dictated by local commercial demands in the bulk
storage location.
16
Handbook of Fire and Explosion Protection
Bibliography
1.
Anderson, R. O., Fundamentals of the Petroleum Industry, University of Oklahoma Press, Norman,OK, 1984
2.
Baker, R., A Primer of Oilwell Drilling, Fifth Edition, Petroleum Extension Service, University of Texas at Austin,
Austin, TX, 1994.
3.
Kruse, C. F., A Primer of Offshore Operations, Second Edition, Petroleum Extension Service, University of Texas
at Austin, Austin, TX, 1985.
4.
Petroleum Extension Service, A Dictionq for the Petroleum Industry, Division of Continuing Education, Petroleum
Extension Service, University of Texas at Austin, Austin, TX, 1991.
5.
Petroleum Extension Service, Fundamentals of Petroleum, Third Edition, Petroleum Extension Service, University
of Texas at Austin, Austin, TX, 1986.
6.
Petroleum Extension Service, A Primer of Oilwell Service and Workover, Third Edition, Petroleum Extension
Service, 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 3
Philosophy of Protection Principals
The risk management techniques of the organization should be defined before any consideration of the
philosophy of protection needs for a facility are identified. An organization that is capable of obtaining a
high level insurance coverage at very low expense, even though they may have high risks, may opt to have a
limited outlay for protection measures since it is not cost effective. In reality this would probably never
occur, but serves to demonstrate influences in a corporate approach to protection levels and risk acceptance.
All insurance companies provide property risk engineers or inspectors to evaluate their insurance risks for
high value properties or operations. So in reality, a standard level of protection is maintained in the industry.
All the major oil companies have high levels of self insurance and usually high deductibles. Their insurance
coverages are also obtained in several financial layers from different agencies with considerable options,
amendments and exclusions. So hopehlly no individual insurer should be in a financial peril from a single
major incident.
A general application of loss prevention practices is considered prudent both by insurers and petroleum
companies, so overall, all facilities are required to achieve the corporate protection standards. In fact the
premium 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 place
of manual fire fighting capabilities, however the general level of overall loss prevention level or risk is
maintained. Insurers will also always make recommendations for loss prevention improvements where they
feel the protection levels are substandard and the risk high. Where they feel the risk is too high, they may
refuse to underwrite certain layers of insurance or charge substantial additional premiums for reinsurance
requirements.
The protection of petroleum facilities follows the same overall philosophy that would be applied to any
building or installation. These basic requirements are personnel evacuation, containment, isolation, and
suppression. Since these are design features that cannot be immediately brought in at the time of an incident
they must be adequately provided as part of the original facility design. What constitutes adequate is the
definition fire, risk and loss protection professionals must provide.
17
18
Handbook of Fire and Explosion Protection
General Philosophy
In general the fire and explosion protection engineering design philosophy for oil, gas and related facilities
can be defined by the following objectives (listed in order of decreasing importance):
(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 if
they were to be exposed to the operation.
(2) Provide inherently safe facilities.
Inherently design safety features at facilities .provides for adequate spacing, arrangement and
segregation of equipment from high hazard to low hazard. The least hazardous process systems
should be used for obtaining the desired product or production objectives. Protective systems are
provided to minimized the effects that may occur from a catastrophic incident.
(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 prescriptive
requirements and underlying objectives. Laws are provided to achieve the minimum safeguards that
are required by a society to exist without excessive turmoil. Industry must abide by these laws in
order to have a cohesive operation without 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 conceivably be designed that would comply with all laws and regulations, if
the perception exists that the facility is unsafe, it must be altered to provide for a facility is technically
judged 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 economic return to the owners. Therefore the
economic interest of the owners should be protected for long and short range survival without fear of
a potential loss of earnings.
(6) Comply with a corporation's policies, standards and guidelines.
A company's policy and guidelines are promulgated to provide guidance in the conduction of the
specific business in an efficient and cost effective manner.
(7) Consider the interest of business partners.
Where a consortium may exist, the economic interest of the partners must be considered and their
management must approve of the risk involved in the venture. Where such risks are considered
unacceptable 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. All
that is desired is a simplistic, practical and economic solution to achieve a level of safety that is
acceptable to interested parties.
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 a
facility. For onshore on offshore facilities the amount a space a facility occupies directly corresponds
to increased capital costs, however these should still be balanced with the need for adequate
separation, segregation and arrangement protection principles.
(10) Respond to operational needs and desires.
To provide effective process safety features they should be effective operational features. Providing
safeguards that are counterproductive to safety may cause the exact opposite to occur, since
operations may ovemde the safeguard for ease of operational convenience.
(11) Protect the reputation of the company.
Public perception of a company lowers if it is involved in major incident that has involved
considerable fatalities or does major harm to the environment. Although these incidents can be
economically recovered from, the stigma of the incident may linger and affect the sale of company
products 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 as
retribution. These effects may be disguised as accidental events in order to avoid persecution by the
individuals involved. Other incidents may be perpetrated by outright terrorist activities. Incidental
effects may develop into catastrophic incidents unbeknown even to the saboteur. The design of
facilities should account for periods when management and labor relations may not be optimum and
opportunities for vandalization could easily avail themselves. Where terrorist activity is ongoing
suitable preventive measures must be instituted (i.e., increased security measures, barricades, etc.).
Worst Case Conditions
Normal loss prevention practices are to design protection measures for the worst case fire event that can
occur at the facility. To interpret this literally would mean that an oil or gas facility is completely on fire or
totally destroyed by an explosion. Practical, economical and historical review considerations indicate this
rational should be redefined to the Worst Case Credible Event (WCCE) or the as referenced in the insurance
industry, the Probable Maximum Loss (PML), that could occur at the facility.
Much discussion could be presented as the most credible event at the facility. Obviously a multitude of
unbelievable 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 evidence
of similar facilities is used as a reference for the worst case credible events. Alternatively the effect of the
most probable high inventory hydrocarbon release could be postulated. The worst case event should be
agreed upon with loss prevention, operational and senior executive management for the facility. The worst
case credible event will normally define the highest hazard location(s) of the facility. From these hazards,
suitable protection arrangements can be postulated to prevent or mitigate their effects.
20
Handbook of Fire and Explosion Protection
Several additional factors are important when considering the worst case credible event.
Ambient Conditions
Weather - winds, snow, sandstorms, extremely high or low ambient temperatures, etc.
Weather conditions can impede the progress of any activity and interrupt utility services if
these become damaged.
Time of Day - personnel availability, visibility, etc., plays a key role in the activities of
personnel during an incident. Periods of off-duty time for offshore or remote installations, shift
changes and nighttime allow high density of personnel to develop on some occasions that can
be vulnerable to a high fatality risk. Poor visibility also affects transportation operations.
Independent Layers of Protection (ILP)
Most facilities are designed around layers of protection commonly referred to as Independent Layers of
Protection (ILP). A protection layer or combination of combination of protection layers qualifies as a ILP
when one of the following conditions are met: (1) the protection provided reduces the risk of a serious event
by 100 times, (2) the protective hnction is provided with a high degree of availability (i.e., greater than
0.99) or (3) it has the following characteristics - specificity, independence, dependability, and auditability.
Most petroleum and chemical facilities rely on inherent safety and control features of the process, inherent
design arrangements of 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 fire
protection measures are applicable after the initiating event has occurred and an adverse affect to the
operation has been realized. These features are used until their capability has been exhausted or the incident
has been controlled.
Philosophy of Protection Principals
The most commonly encountered Independent Layers ofProtection
(ILPs) are shown in Table 1:
Table 1
Independent Levels of Protection
21
22
Handbook of Fire and Explosion Protection
Design Principles
To achieve the project safety objectives and philosophy of protection through independent layers of
protection, a project or organization should define specific guidelines or standards to implement in its
designs. Numerous industry standards are available (Le., API, NFPA, etc.) which give options, general
recommendations or specific criteria once a design preference is chosen. It is therefore imperative to have
company specific direction in order to comply with company management directives for protection of the
facility.
Typically encountered facility safety design principles within the petroleum industry are usually as follows:
1.
Immediate facility evacuation should be considered as a prime safeguard for all personnel from a
major incident. All onsite personnel should be hlly trained and where required certified for such
an eventuality (i.e., offshore evacuation mechanisms).
2. Process system emergency safety features (i.e. ESD, isolation, depressurization and blowdown)
should be considered the prime safeguards for loss prevention over fire protection measures (i.e.
fireproofing or barriers, firewater systems, manual fire fighting).
3.
The facility design should meet the requirements of local national regulations and a company's
policies pertaining to 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 not
sufficient in itself to ensure a safe design is provide.
5. Inherent safety practices should be used. Inherent safety practices implement the least risk
options for conducting an operation and provide sufficient safety margins. General methods
using inert or high flash point materials over highly volatile low flash point materials, use of
lower pressures instead of higher pressures, smaller volumes instead of large volumes, etc.
In general these safe design characteristics can be categorized as:
a.
b.
c.
d.
e.
f
Are intrinsically safe.
Incorporate adequate design margins or safety factors.
Have sufficient reliability.
Have fail-safe features.
Incorporate fault detection and alarms.
Provide protection instrumentation.
Some specific inherent safety practices used in the industry are mentioned below.
(i.) Automatic ESD (shutdown and isolation) activation from confirmed process system
instrumentation set points.
(ii) Automatic de-inventorying of high volume hydrocarbon processes (gasses and liquids) for
emergency conditions to remote disposal systems.
(iii.) Separation distances are maximized for high risks. Occupied facilities (e.g., control
Philosophy of Protection Principals
23
rooms, accommodations, offices, etc.) should be located as far as practical from high risk
processes. High volume volatile storage is highly spaced from other high risks. Safety factors
are included in calculated spacing distances determined by mathematical modeling of
explosions and fire incidents. Spacing is implemented over passive protective barriers.
(iv.) The amounts of flammable liquids and gases that may contribute to an incident should be
minimized for normal operations and during emergency conditions (limited vessel sizes,
isolation provisions, blowdown or depressurization, etc.). The maximum allowable levels for
operational and emergency periods should be identified as part of the design process and risk
analysis.
(v.) Automatic control (DCS-BPCS, PLC, etc.) for high risk processes should be used,
which are backed-up by human supervision.
(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) and
depressure high volume gas supplies (i.e., fail open) upon disruption of utility services during
an incident.
(vii.) A dual alarm level instrumentation (e.g., highhigh, low/low, etc.) should be used for
critical alarms and controls.
(viii.) The release of or exposure of flammable vapors or liquids to the operating environment
should be avoided (e.g., pressure relief to flare system or blowdown header, avoidance of
pump usage due to seal leaks, flanged or screwed fittings, mitigation of vibrational stress on
piping components, etc.).
(ix.) Single point failure locations in the process flow should be eliminated for the prime
production hydrocarbon processes and support systems (i.e., electrical power, heat transfer,
cooling water, etc.) that are critical to.maintain the production process.
(x.) High performance corrosion protective measures or allowances should be instituted.
Corrosion monitoring systems should be used in all hydrocarbon containing systems.
(xi.) The facility should be designed with the maximum use of open space for free air
ventilation, especially for offshore installations. Enclosed spaces should be avoided when
practical.
(xii.) Ignition sources should be spaced as far as practical from hydrocarbon containing
systems (maximize electrical area classification requirements).
(xiii.) Air supplies for ventilation for control rooms, prime movers, etc., should be located at
the least likely location for accumulation of flammable vapors or routes of dispersion (e.g.,
generally provided at the lower levels of the facility for areas handling light vapors and higher
levels for facilities handling heavy vapors, where both occur a high level intake is prudent
considering dispersion effects). Locations that do not need oxygen supplies or fresh air (i,e.,
electrical switchgear enclosures), but require temperature control, should be recirculating.
(xiv.) Two separate on site evacuation mechanisms should be provided and generally
available.
(xv.) The integrity of safety systems (ESDDepresurization, Fire DetectiodSuppression,
AIarm and Evacuation means) should be maximized and preserved from accidental fire and
explosion events.
24
Handbook of Fire and Explosion Protection
(xvi.) Surface drainage and safe removal of spilled or accumulated liquids is adequately
provided.
(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 expose
other facilities to the hazard.
(xviii.) High flash point, noncombustible or inert liquids and gases are utilized whenever
possible.
(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 transfer
systems, etc.
(xxi.) Piping carrying hazardous materials is minimized where practical and where exposed, is
afforded protection considered necessary.
5.
Operational personnel should be expected to suppress only very small incipient fires. All other
emergencies are to be handled with ESDhlowdown, isolation, fire protection systems (active or
passive) or exhaustion of fuel sources by the incident.
6 . Opportunities for employee induced damages are minimized. All activities are made so that they
are direct actions and cannot be attributed to purely mechanical failures. For example, easily
broken liquid gage glasses are protected or reyoved, drains are capped, field ESD push buttons
are provided with tamper covers, work permt procedures are enforced, lock-out or tag-out
measures are used, etc.
7. The facility is secured and evacuated if weather or geological event predictions suggest severe
conditions may be imminent at 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 facility
represents.
9.
The facility is subjected to a process hazard analysis commensurate to the level of hazard the
facility represents (ie., Checklist, PHA, HAZOP, What-If review, Event Tree, FMEA, etc.). The
results of these analyses are fully understood and acknowledged by facility management. Where
high risk events are identified, quantifiable risk estimation and e e c t s of mitigation measures
should be evaluated and applied if productive.
These are some of the numerous inherent design features that can be incorporated into the design of a
process system depending on its nature. Not only should a process design achieve economic efficiency but
the inherent safety of the process should be optimized simultaneously as well.
Philosophy of Protection Principals
25
Accountability and Auditability
An organization should have a well though out protection design philosophy
that is understood and accepted by management. The safety design
philosophies should be reflected in the engineering design standards or
guidelines used by the organization. The standards or guidelines form the
basis from which the safety of the facility can be audited against.
Organizations that do not provide such information, do not have any
accountability standards to meet or achieve, and therefore he safety of the
facility will suffer accordingly. Additionally the objectives of design
standards and guidelines can be more fully understood if a philosophy of
design is documented.
The argument cannot be made that standards or guidelines restrict creativity innovation or are unduly
expensive. Waivers or exceptions to the requirements can always be allowed. This is provided they are
adequately supported by a justification that demonstrates equivalency or superiority in meeting the
requirements or safety objective. In this fashion standards or guidelines can be also improved to account for
such acceptable changes. Although not easily calculated a firm set of requirements prevents "re-inventing
the wheel" each time a facility is designed. This will also hopefully prevent mistakes made in the past from
reoccurring. Thus they establish a long term saving to the organization. Additionally reference to industry
standards, e.g., ASME, M I , NFPA, etc., will not specify the actual protection measures to be provided at a
facility. In most cases they only defined the design parameters. A project or facility requires the "Local
Jurisdiction" to determine protection requirements, which is usually the company itself. The industry codes
only provide detailed design guidance that can be used once a particular protection philosophy is specified.
Engineering designs for new process facilities or changes should be circulated for review as dictated by the
level of risk the facility represents to personnel competent to evaluate the risk. These reviews should fully
identifjr the risks (both consequences and probabilities) and address measures to prevent or mitigate their
effects.
26
Handbook of Fire and Explosion Protection
Bibliography
1.
American Petroleum Institute (API), RP 75. Recommended Practices for Develoument of a Safety and
Environmental Management Promam for Outer Continental Shelf (OCS) Ouerations and Facilities, API,
Washington, D.C., 1993.
2.
American Petroleum Institute (API), RP 750, Management of Process Hazards, API, Washington, D.C., 1990.
3.
Armistead Jr., G., Safetv in Petroleum Refining and Related Industries, Second Edition, J. G. Simmonds & Co., Inc.,
New York, NY, 1959.
4.
Center for Chemical Process Safety (CCPS), Guidelines for Enpineering Design for Process Safety, AIChE, New
York, NY, 1993.
5.
Environmental Protection Agency (EPA), U.S. Regulation 40 CFR Part 68, “Proposed Rule, Risk Management
Programs for Chemical Accidental Release Prevention”, EPA, Washington, D.C., October 20, 1993.
6.
Health and Safety Executive (HSE), A Guide to the Control of Industrial Maior Accident Hazards Regulations,
CIMAH, HMSO, London, U.K., 1985.
7.
Health and Safety Executive (HSE), A Guide to the Offshore Installations (Safetv Case) Regulations 1992, HMSO,
London, U.K., 1992.
8.
Labour Inspectorate, U.D.C. 66.013/614.8.002, Processing Plants Checklist, Areas of Attention for a Safe Design,
Second Edition, Dutch Director General of Labor, Voorburg, The Netherlands, 1989.
9.
Lees, F. P., Loss Prevention the Process Industries, Gulf Publishing, Houston, TX, 1980.
10. Norwegian Petroleum Directorate (NPD), Guidelines for Safetv Evaluation of Platform Conceutual Design, NPD,
Oslo, Norway, 1981.
11. Occupational Safety and Health Administration (OSHA), U.S. Regulation 29 CFR 1910.119, “Process Safety
Management of Highly Hazardous Chemicals; Explosives and Blasting Agents”, Department of Labor, OSHA,
Washington, D.C. May 26, 1992.
12. Russia (U.S.S.R.) GOST 12.1.010-76. Occupational Safety Standards Svstem. Explosion Safetv. General
Reauirements, State Standards Committee of the USSR, Moscow, U.S.S.R., 1984.
Chapter 4
Physical Properties of Hydrocarbons
Petroleum, or crude oil, is a naturally occurring oily, bituminous liquid composed of various organic
chemicals. It is found in large quantities below the surface of the earth and is used as a fuel and as a raw
material in the chemical industry. Modern industrial societies use it primarily to achieve a degree of mobility
as a fuel for internal combustion and jet engines. In addition, petroleum and its derivatives are used in the
manufacture of medicines, fertilizers, foodstuffs, plastic ware, building materials, paints, and cloth and to
generate electricity. Gas supplies are becoming increasing more important as the reserves of liquid
hydrocarbons are being depleted and the relatively clean burning gases are more acceptable environmentally.
Petroleum is formed under the earth's surface by the decomposition of organic material. The remains of tiny
organisms that lived in the sea and, to a lesser extent, those of land organisms were carried down to the sea
in rivers along with plants that grow on the ocean bottoms combined with the fine sands and silts in calm sea
basins. These deposits, which are rich in organic materials, become the source rocks for the formation of
carbon and hydrogen, i.e., natural gas and crude oil.
This process began many millions of years ago with the development of abundant life, and it continues to this
day. The sediments grow thicker and sink into the sea floor under their own weight. As additional deposits
pile up, the pressure on the ones below increases several thousand times, and the temperature rises by
several hundred degrees. The mud and sand harden into shale and sandstone. Carbonate precipitates and
skeletal shells harden into limestone. The remains of the dead organisms are then transformed into crude oil
and natural gas. Usually the underground and formation pressure is sufficient for the natural release of
hydrocarbon liquids and gases to the surface of the earth.
General
The range and complexity of naturally occurring petroleum is extremely large, and the variation in
composition from one reservoir to another is shows quite a range. Crude oil is graded by a specific viscosity
range indicated as degrees API. Higher degrees being lighter and lower degrees being heavier. All crude
oils differ in the fiactions of the various hydrocarbons they contain. The specific molecules vary in shape
and size from C1 to Cso or more. At the simplest, the one carbon compound has four hydrocarbon atoms
bonded to the carbon atom to produce a the compound CH4, or methane gas. Liquid hydrocarbons from
natural wells may have nitrogen, oxygen, and sulfur in quantities from trace amounts to significant, as well as
traces of metals.
Natural petroleum is distilled and reformulated to produce a variety of fbels for general use and as raw
27
28
Handbook of Fire and Explosion Protection
feedstock materials for other industries.
Three broad classes of crude petroleum exist: the paraffin types, the asphaltic types, and the mixed-base
types. The paraffin types are composed of molecules in which the number of hydrogen atoms is always two
more than twice the number of carbon atoms. The characteristic molecules in the asphaltic types are
naphthenes, composed of twice as many hydrogen atoms as carbon atoms. In the mixed-base group are both
paraffin hydrocarbons and naphthenes.
The saturated open-chain hydrocarbons form a homologous series called the paraffin series or the alkane
series. The composition of each of the members of the series corresponds to the formula CnH2n + 2, where
n is the number of carbon atoms in the molecule. All the members of the series are unreactive. They do not
react readily at ordinary temperatures with such reagents as acids, alkalies, or oxidizers.
The first four carbon molecules, C1 to C4, with the addition of hydrogen, form hydrocarbon gases: methane,
ethane, propane, and butane. Larger molecules C5 to C7, cover the range of light gasoline liquids; c 8 to
C11 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 gas
compounds may be various amounts of nitrogen, carbon dioxide, hydrogen sulfide, and occasionally helium.
Alkene Series
The unsaturated open-chain hydrocarbons include the alkene or olefin series, the diene series, and the
alkyne series. The alkene series is made up of chain hydrocarbons in which a double bond exists
between two carbon atoms. The general formula for the series is CnHzn, where n is the number of
carbon atoms. As in the paraffin series, the lower members are gases, intermediate compounds are
liquids, and the higher members of the series are solids. The alkene series compounds are more
active chemically than the saturated compounds. They react easily with substances such as halogens
by adding atoms at the double bonds.
They are not found to any extent in natural products, but are produced in the destructive distillation
of 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 dienes
contain two double bonds between pairs of carbon atoms in the molecule. They are related to the
complex hydrocarbons in natural rubber and are important in the manufacture of synthetic rubber and
plastics. The most important members of this series are butadiene, C4H6 and isoprene, C5Hg.
Alkyne Series
The members of the alkyne series contain a triple bond between two carbon atoms in the molecule.
They are very active chemically and are not found free in nature. They form a series analogous to the
alkene series. The first and most important member of the series is acetylene, C2H2.
Cyclic Hydrocarbons
The simplest of the saturated cyclic hydrocarbons, or cycloalkanes, is cyclopropane, C3H6, the
molecules of which are made up of three carbon atoms to each of which two hydrogen atoms are
attached. Cyclopropane is somewhat more reactive than the corresponding open-chain alkane,
propane, C3H8. Other cycloalkanes make up a part of ordinary gasoline.
Several unsaturated cyclic hydrocarbons, having the general formula C 10H16, occur in certain
fragrant natural oils that are distilled from plant materials. These hydrocarbons are called terpenes
and include pinene (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
29
tar. 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 or
groups of atoms. The aromatic hydrocarbons include benzene, toluene, anthracene, and naphthalene.
Characteristics of Hydrocarbons
Hydrocarbon materials have several different characteristics that 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 be
evaluated as a synergism. It should also be realized that these characteristics have been tested under strict
laboratory conditions and procedures that may alter when applied to industrial environments. The main
characteristics of combustible hydrocarbon materials which are of high interest for fire and explosion
influences are 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 terms
flammable limits and explosive limits are interchangeable. Where the range between the limits is large, the
hydrocarbon may be considered relatively more dangerous (e.g., hydrogen 4 to 75 % versus gasoline 1.4
to 7.6 YO)when compared against each other since it has a higher probability of ignition in any particular
situation. Flammability limits are not an inherent property of a material but are dependent on the surface
to volume ratio and velocity or direction of air flow under the test.
Some common petroleum materials and their flammable limits under normal conditions are listed below
beginning with the widest ranges:
Material
Hydrogen
Ethane
Methane
Propane
Butane
Pentane
Hexane
Heptane
YORange
4.0 to 75.6
3.0 to 15.5
5.0 to 15.0
2.0 to 9.5
1.5 to 8.5
1.4to 8.0
1.7 to 7.4
1.1 to 6.7
Difference
71.6
12.5
10.0
7.5
7.0
6.6
5.7
5.6
Flash Point (FP)
The lowest temperature of a flammable liquid at which it gives off sufficient vapor to form an ignitable
mixture with the air near the surface of the liquid or within the vessel used. The flash point has been
commonly determined by the open cup or closed cup method but recent research has yielded higher and
lower flash points dependent on the surface area of the ignition source. Because of this aspect ASTM
and other standard test methods have been recently withdrawn. They are under review until an adequate
determination of 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 Protection
below:
Material
Flash Point
Hydrogen
Methane
Propane
Ethane
Butane
Pentane
Hexane
Heptane
Gas
Gas
Gas
Gas
-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 a
substance in air must be heated to initiate or cause self sustaining combustion independent of the heating
source. It is an extrinsic property, i.e., the value is specific to the particular experimental method that is
used to determine it. The two most significant factors that influence a measurement of AITs are the
volume to surface ratio of the source of ignition (Le., a hot wire versus a heated cup will yield different
results). Ignition temperatures should always be thought of as approximations and not as exact
characteristic of the material for this reason.
For straight paraffinic hydrocarbons (i.e., methane, ethane, propane, etc.) the commonly accepted
autoignition temperatures decrease as the paraffinic carbon atoms increase (e.g., methane 540 OC (1004
OF) and octane 220 OC (428 OF)).
Some common petroleum materials AITs under normal conditions are listed below:
Material
ATT
Heptane
Hexane
Pentane
Butane
Propane
Ethane
Hydrogen
Methane
204 O C
225 O C
260 OC
287 O C
450 O C
472 OC
(399 OF)
(437 OF)
(500 OF)
(550 OF)
(842 OF)
(882 OF)
500 O C (932 OF)
537 o c (999 OF)
A mathematical method for obtaining a general approximation of hydrocarbon ignition temperatures
based on the molecular weight of the vapor is mentioned in the NFPA Fire Protection Handbook. It
states that the autoignition temperature of a paraffinic hydrocarbon series decreases as the molecular
weight of the substances increases. A figure is provided by which if the "average carbon chain length" is
known, the minimum ignition temperature can be theoretically approximated.
For hydrocarbon mixtures containing only paraffinic components, an approximation of the ignition
temperature can be made by using the average molecular weight of the substance. It can be estimated by
multiplying the molecular weight of each pure vapor by its concentration (Le., measured percentage) in
the mixture, to arrive at an average mixture moiecular weight (average carbon chain length). Once this
known it can be compared to the ignition temperature of a known substance with an equal weight or
reference can be made to the figure in the NFPA Fire Protection Handbook. Again remembering that all
AITs are only just an approximation.
Physical Properties of Hydrocarbons
31
By general inspection, where a large percentage of high ignition temperature paraffinic gas coexists in a
mixture with a low percentage of ignition temperature paraffinic gas, it can be conferred that the mixture
will 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 is
converted into combustion, it takes less energy to sustain the reaction than it would for a lower molecular
weight (less energy) containing molecule. This is because more energy is being used for release in the high
molecular weight hydrocarbon substances.
This principle only applies to straight chain hydrocarbons and is inappropriate if other types of substances
are involved (e.g., hydrogen).
Figure 1 provides a suggested method to obtain an autoignition temperature approximation for paraffinic
hydrocarbon vapor mixtures. Although this method can be made to achieve a general approximation, it is
still best to obtain a laboratory analysis of the autoignition temperature for a gas mixture when
performing major process designs.
Autoignition temperatures are vitally important for process designs as it is the temperature at which to
prevent or eliminate readily available ignition sources. (e.g., operating temperatures of electrical
equipment, light fixtures, etc.).
Recently revised test methods have revealed that nonluminous or barely luminous combustion reactions
are occurring where previously it was reported that no combustion activity was occurring based on flame
observance.
As a result of these new testing methods the following terminology for ignition temperature definitions
has been proposed:
Hot Flame Ignition - A rapid self-sustaining, sometimes audible gas phase reaction of the sample or
its decomposition products with an oxidant. A readily visible yellow or blue flame usually
accompanies the reaction.
Cool Flame Ignition - A relatively slow self sustaining, barely luminous, gas phase reaction of the
sample or its decomposition products with an oxidant. Cool flames are visible only in a darken area.
Pre-Flame Reaction - A slow nonluminous gas phase reaction of the sample or its decomposition
products with an oxidant.
Catalytic Reaction - A relatively fast, self-sustaining, energetic, sometimes luminous, sometimes
audible reaction that occurs as a result of the catalytic action of any substance on the sample or its
decomposition products, in a mixture with an oxidant.
Non-Combustive Reaction - A reaction other than combustion or thermal degradation that is
undergone by certain substances when they are exposed to heat.
NFPA now normally refers to autoignition as the Hot Flame Ignition Temperature, as a more precise
definition. Subsequently the following two additional terms are being adopted by NFPA to hrther refine
the ignition properties of materials. The lowest temperatures at which cool flame ignitions are observed
are named the Cool Flame Reaction Threshold (CFT). The lowest flame temperatures at which an
exothermic gas phase reaction is noticed are named the Preflame Reaction Threshold (RTT).
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Handbook of Fire and Explosion Protection
Example:
NGL Column Bottoms Liquid Percentage Concentration from sample analysis:
Symbol Name
c1
C2
C3
C4
C5
C6
Molecular Weight
Methane
Ethane
Propane
Butane
Pentane
Hexane
Ignition Temperature
540 OC
16
30
515 OC
44
58
72
86
450 OC
405 O C
260 O C
225 OC
Percentage
2.3 %
0.2 %
30 Yo
25 %
15.5 Yo
23 Yo
Wave
= 16(0.023) + 30(0.002) + 44(.30) + 58(0.25) + 72(0.155) + 86(0.23)
= 58.2 or
equivalent to C4
The NGL column bottoms has average molecular weight equivalent to normal butane and therefore has an
approximate autoignition temperature of 405 OC (761 OF).
Figure 1
Example of Autoignition Temperature Approximation Method
(suitable for paraffinic hydrocarbon mixtures only)
Physical Properties of Hydrocarbons
33
Vapor Density
Vapor 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. Vapors
with a vapor density of greater than 1.O are heavier than air and will follow the surface of the ground until
dissipated. Vapors with a vapor density less than 1.O will rise into the atmosphere, the lower the density
the faster they will rise.
Common petroleum materials with some of the highest vapor densities under normal conditions are listed
below:
Material
Vapor Densitv Ratio
Hydrogen
Methane
Ethane
Propane
Butane
Pentane
Hexane
Heptane
0.069
0.554
1.035
1.56
2.01
2.48
2.97
3.45
Vapor Pressure
This is the property of a substance to vaporize. Liquids are usually classified by the Reid vapor pressure,
which is calculated on the basis o f a specific oil at a temperature of 37.8 OC (100 OF).
Specific Gravity
The specific gravity is the ratio of weight of equal volumes of a substance to that of another substance
usually water. For petroleum products it is customary to measure the ratio at 15.6 OC (60 OF)
Flammable
Capable of being easily set on fire; combustible. It is a synonym to inflammable. Inflammable is
considered an obsolete term in the U.S.A. because of the connotation of the negative prefix that
incorrectly suggests the material is not flammable.
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,
Combustible and Flammable Liquids Code, defines differences between the classification of combustible
liquids and flammable liquids based on flash point and vapor pressure).
Heat of Combustion
The heat of combustion of a fie1 is defined as the amount of heat released when unit quantity is oxidized
completely to yield stable products.
34
Handbook of Fire and Explosion Protection
Description of Some Common Hydrocarbons
Natural Gas
Naturally occurring mixtures of hydrocarbon gases 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 no
poisonous ingredients. Breathing natural gas is harmful when there is not an adequate supply of oxygen
in the atmosphere.
Crude Oil
Crude oils consist primarily of hydrocarbons and compounds containing sulfur, nitrogen, oxygen, and
trace metals as minor constituents. The physical and chemical characteristics of crude oils -vary widely,
depending on the percentages of the various compounds that are present. Its specific gravities cover a
wide range, but most crude oils are between 0.80 and 0.97 g/ml or gravity between 45 and 15 degrees
MI. There is also a wide variation in viscosities, but most crude oils are in the range of 2.3 to 23
centistokes.
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 oil
may 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 flash
point classification. In atmospheric burning heavy smoke production normally occurs.
Methane (Cl)
Methane, also referred to as marsh gas, is a gas composed of carbon and hydrogen with a chemical
formula of CH4. It is the first member of the paraffin or alkane series of hydrocarbons. It is lighter than
air, colorless, odorless, tasteless and is flammable. It occurs in natural gas and as a by-product of
petroleum refining. In atmospheric burning no smoke production normally occurs. In air methane burns
with a pale, faintly luminous flame. With excess air carbon dioxide and water vapor is formed during
combustion, with an air deficiency carbon monoxide and water is formed. It forms an explosive mixture
with air over a moderate range. Its primary uses are as a fuel and raw feedstock for petrochemical
products.
Methane melts at -182.5 OC (-296.5 OF) and boils at -161.5 OC (-258.7 OF) Its fuel value is 995 Btu per
cubic ft.
LNG, Liquefied Natural Gas (Cl)
Commercial liquefied natural gas (NGL) is composed of at least 99% methane that has been cooled to
approximately -160 OC (-256 OF), at atmospheric pressure. At this temperature is occupies only 11600 of
its original volume. LNG is less than half as dense as water, is colorless, odorless, non-toxic and sulfur
fke. It is vaporized as needed for use as a high quality fbel. In atmospheric burning no smoke
production normally occurs.
Physical Properties of Hydrocarbons
35
Ethane (C2)
A gaseous paraffinic hydrocarbon, CH3,CH3 that is colorless and odorless and normally found in natural
gas, usually in small proportions. It is slightly heavier than air and practically insoluble in water. When
ignited in atmospheric burning it produces a pale faintly luminous flame with little or no smoke
production. With excess air during combustion it produces carbon dioxide and water, with limited air
supplies the combustion process will produce carbon monoxide and water. It forms an explosive mixture
with air over a moderate range.
Ethane has a boiling point of -88 OC (-126 OF). The fuel value ofEthane is 1730 Btu per cubic ft
Propane (C3)
Propane is a colorless, odorless gas of the alkane series of hydrocarbons, of formula C3H8. It occurs in
crude oil, natural gas, and as a by-product of refinery cracking gas during petroleum refining. Propane
does not react strongly at room temperature. It does react, however, with chlorine at room temperature if
the mixture is exposed to light. At higher temperatures, propane burns in air, producing carbon dioxide
and water as final products, and is valuable as a fitel. In atmospheric burning smoke production normally
occurs.
About half the propane produced annually in the U.S. is used as a domestic and industrial fuel. When it is
used as a fuel, propane is not separated from the related compounds, butane, ethane, and propylene.
Butane, with boiling point -0.5 OC (3 1.1 OF), however, reduces somewhat the rate of evaporation of the
liquid mixture. Propane forms a solid hydrate at low temperatures, and this causes great inconvenience
when a blockage occurs in a natural-gas line. Propane is used also as so-called bottled gas, as a motor
fuel, as a refrigerant, as a low-temperature solvent, and as a source of propylene and ethylene.
Propane melts at -189.9 OC (-309.8 OF) and boils at -42.1 O C (-43.8 OF)
Butane (C4)
Butane, is the either of two saturated hydrocarbons, or alkanes, with the chemical formula of C4H10 of
the 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 forms
a side branch. This difference in structure results in small but distinct differences in properties. Thus, nbutane melts at -138.3 O C (-216.9 OF) and boils at -0.5 O C (31.1 OF), and i-butane melts at -145 OC (-229
OF) and boils at -10.2 OC (13.6 OF).
Both butanes occur in natural gas, petroleum, and refinery gases. They show little chemical reactivity at
ordinary temperatures but burn readily when ignited in air or oxygen. In atmospheric burning smoke
production normally occurs.
They make up the most volatile portion of gasoline and are sometimes added to propane to be marketed
as bottled gas. Most n-butane, however, is converted to butadiene, which is used to make synthetic
rubber and latex paints.
LPG, Liquefied Petroleum Gas (C3 & C4)
Commercial Liquefied Petroleum Gas (LPG), is a mixture of the liquefied gases of propane (C3) and
butane (C4). It is obtained from natural gas or petroleum. LPG is liquefied for transport and then
vaporized for use as a heating fuel, engine fitel or as a feedstock in the petrochemical or chemical
industries. It has a flammability range 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 Protection
air. One volume of LPG liquid may form 2,300 to 13,500 time the volume of gas in air. LPG vapor is an
anesthetic and asphyxiant in high concentrations. LPGs are odorless, colorless, non-corrosive and nontoxic. It has a low viscosity and therefore is more likely to find a leakage path than other petroleum
products. In case of a leakage it tends to spread on the surface accompanied by a visible fog of
condensed water vapor, however the ignitable vapor mixture extends beyond the visible area.
Gasoline (C5 to C11)
Gasoline is a mixture of the lighter liquid hydrocarbons that distills within the range of 38 to 204 OC (100
to 400 OF). Commercial gasolines are a mixture of straight -run, cracked, reformed, and natural
gasolines. It is produced by the fractional distillation of petroleum; by condensation or adsorption from
natural gas; by thermal or catalytic decomposition of petroleum or its fractions; by the hydrogenation of
producer gas or by the polymerization of hydrocarbons of lower molecular weight
Gasoline produced by the direct distillation of crude petroleum is known as straight-run gasoline. It is
usually distilled continuously in a bubble tower, which separates the gasoline from the other fractions of
the oil having higher boiling points, such as kerosene, &el oil, lubricating oil, and grease. The range of
temperatures in which gasoline boils and is distilled off is roughly between 38 and 205 O C (100 and 400
OF). The yield of gasoline from this process varies from about 1 percent to about 50 percent, depending
on the petroleum. Straight-run gasoline now makes up only a small part of gasoline production because of
the superior merits of the various cracking processes. The flash point of gasoline is well below -17.8 O C
(0 OF) at atmospheric pressure. In atmospheric burning smoke production normally occurs.
In some instances natural gas contains a percentage of natural gasoline that may be recovered by
condensation or adsorption. The most common process for the extraction of natural gasoline includes
passing 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 the
gasoline on activated alumina, activated carbon, or silica gel.
High-grade gasoline can be produced by a process known as hydrofining, that is, the hydrogenation of
refined 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 time
purifies the gasoline chemically by removing undesirable elements such as sulfir. Producer gas, coal, and
coal-tar distillates can also be hydrogenated to form gasoline.
Condensate (C4, C5, C6 & >)
Condensate is normally considered the entrapped liquids in process or production gas streams due to
temperature or pressure, in the typically in the range of C3,C4, CS or heavier hydrocarbon liquids. It is
also known as natural gasoline C5 plus and pentanes plus, and as a liquid at normal temperatures and
pressures it generally consists of a mixture of the C5 (pentanes) and heavier hydrocarbons. It is normally
condensed (i,e., by expansion and cooling of the gas) out of the process stream in primary separation
processes, where it is then sent to other refinery processes to firther separate the condensate into its
primary fractions, Le., propane, butane, and liquids constituents.
The flash point of condenstate is generally taken as that of hexane, where precise measurements have not
been taken. Hexane has the lowest flash point of any material in the constitution of condensate. In
atmospheric burning smoke production normally occurs.
Physical Properties of Hydrocarbons
37
Gas and Fuel Oils (C12 to C19)
Gas oil or fbels oil is a generic term applied to petroleum distillates boiling between kerosene and
lubricating 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 contain
fkel oils such as kerosene, diesel fkels, gas turbine fuels, etc. In atmospheric burning smoke production
normally occurs.
Kerosene
Kerosene or sometimes referred to as Fuel Oil # 1 is a refined petroleum distillate. Kerosenes usually
have flash points within the range of 37.8 OC to 54.4 O C (100 OF to 130 OF). Therefore unless
heated, kerosene will usually not produce ignitable mixtures over its surface. In atmospheric burning
smoke production normally occurs. It is commonly used as a firel and a solvent. In some
applications it is treated with sulfuric acid to reduce the content of aromatics, which burn with a
smoky flame.
Diesel
Diesel 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 combustion
characteristics of diesel fbels are expressed in terms of a centane number, which is a measure of
ignition delay. A short ignition delay, i.e., the time between injection and ignition is desirabie for a
smooth running engine.
Fuel Oils # 4, 5, & 6
These are fuels for low and medium speed engines or as a feedstock for catalytic cracker refining
processes.
Lubricating Oils and Greases (C20 to C27)
Vacuum distillates or residual fraction of vacuum distillates are the main source of lubricating oils
from the petroleum industry. Although they account for only 1% of the volume of petroleum fuel
sales they are a high value unit. Besides lubrication they are used as heat transfer mediums, hydraulic
fluids, 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 other
thickening agents. Greases range from soft semi-fluids to hard solids, the hardness increasing as the
content of the thickening agent increases. Greases are classified according to the type of thickener
used, e.g., lithium, calcium, organic, etc., and their consistency.
Petrolatum is produced from lubricating oils. Petrolatum is used in the medicinal field where it is
combined with other compounds to form salves, creams, ointments and petroleum jelly.
Asphalts and Waxes (C28 & >)
Asphalt
Asphalt is a bituminous substance that is found in natural deposits or as the residual of in petroleum or
coal 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 Protection
nature varying in consistency at room temperature from solid to semisolid depending on the amount of
light hydrocarbon fiactions that have been removed. It can be poured when heated to the temperature of
boiling water. The quality of asphalt is affected by the nature of the crude oil and the refining process. It
is used in surfacing roads, in water-retaining structures such as reservoirs and swimming pools, and in
roofing materials and floor tiles. Asphalt should not to be c o h s e d with tar. Tar is a black fluid
substance derived from coal.
About 75 percent of U.S. production of petroleum asphalt is used for paving while 15 percent is used for
roofing. The remaining 10 percent is used for the more than 200 other known uses of asphalt.
Wax
Wax is a soft impressionable semi-solid material having a dull luster and a somewhat soapy or greasy
texture. It softens gradually upon heating, going through a soR, malleable state before ultimately forming
a liquid. Paraffin wax is a mixture of saturated hydrocarbons of higher molecular mass, produced during
the refining of petroleum. Natural petroleum waxes may occur during the production of some
hydrocarbon reservoirs containing heavy oils. Most commercial waxes now come from petroleum.
Chlorinated paraffin waxes have come into considerable use because of their fire resistant properties.
Physical Properties of Hydrocarbons
Table
2
Characteristics of Selected Common Hydrocarbons
39
40
Handbook of Fire and Explosion Protection
Bibliography
1.
Compressed Gas Association, Handbook of Commessed Gases, Third Edition, Van Nostrand Reinhold, New York,
NY, 1990.
2.
Fenstemaker, R. W., "Study of Autoignition for Low Pressure Fuel-Gas Blends Helps Promote Safety", Oil and
Gas Journal, February 15, 1982.
3.
Factory Mutual, Handbook of Industrial Loss Prevention, Second Edition, McGraw-Hill, New York, NY, 1967
4. Maxwell, J. B., Data Book on Hvdrocarbons. Apolication to Process Engineering, Krieger Publishing Company,
Malabar, FL 1968.
5.
National Fire Protection Association (NFPA), Fire Protection Handbook, 17th Edition, NFPA, Quincy, MA, 1991
6.
National Fire Protection Association (NFPA), NFPA 30. Flammable and Combustible Liauids Code, NFPA,
Quincy, MA, 1993.
7
National Fire Protection Association (NFPA), NFPA 325M, Fire Hazard Properties of Flammable Liauids. Gases
and Volatile Solids, NFPA, Quincy, MA, 1991.
8
Society of Fire Protection Engineers (SFPE), Handbook of Fire Protection Engineering, NFPA, Qwncy, MA, 1988.
9.
Zabetakis, M. G., Bulletin 627, Flammabilitv Characteristics of Combustible Gases and Vapors, Bureau of Mines
(BOM),U. S. Department of the Interior, Pittsburgh, PA, 1965.
Chapter 5
Characteristics of Hydrocarbon
Releases, Fires and Explosions
Petroleum (oil and gas), is a highly dangerous commodity that should be recognized for its hazards and
handled with the proper precautions. The ignition of combustible gas clouds or vapors can produce highly
damaging explosions and high temperature fires. These events can completely destroy an entire installation
if allowed to developed or left uncontrolled. Ordinary wood and combustibles burn with a relatively gradual
increase in temperature to a moderate levei while hydrocarbon fires immediate reach a high temperature
level within minutes and continue at this level until exhausted. By comparison to ordinary combustible tires,
hydrocarbon fires are a magnitude greater in intensity. Fire barriers or suppression mechanisms adequate for
ordinary occupancies are quite easily overtaxed when a high intensity hydrocarbon fire is prevalent.
The most destructive incidents in the petroleum and related industries are usually initiated by an explosive
blast that can damage and destroy unprotected facilities. These blasts have been commonly equated with the
force of a TNT explosion and are quite literally a "bomb". The protection of hydrocarbon and chemical
industries is in rather a unique discipline by itself, which requires specialized techniques of mitigation and
protection in a systems based approach. The first step in this approach is to understand the characteristics of
hydrocarbon 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 variations in the properties of the hydrocarbon materials involved. Open fires of any kind
generally 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 the
material becomes from heat effects, uncontained pressure releases or other factors, the fire will bum with
flames rising to higher elevations, with less tendency to bum at the point of origin. There may be localized
effects that determine the shape and configuration of the upward flames and products of combustion.
Localized failures of pressurized piping, process pumps, vessels or other parts of the process under pressure
will cause a "torch" or "jet" fire. These fires may project flames in any direction, for a considerable distance,
depending on the contained pressures and volumes of the source. Any facility that retains large amounts of
high pressure liquids or gases can produce jet for extended periods if adequate isolation and depressurization
capability is unavailable. The worst offenders in these cases are wellheads, high pressure gas pipelines and
storage facilities.
41
42
Handbook of Fire and Explosion Protection
Hydrocarbon Releases
Hydrocarbon releases in the petroleum industry are either gaseous, mists or liquids and are either
atmospheric releases or pressurized. Gas and mist releases are considered more significant since they are
readily ignitable since they are in the gas state and due to the generation of vapor clouds which if ignited are
instantly destructive in a widespread nature versus liquid fires that may be less prone to ignition, generally
localized and relatively controllable.
The cause of a release can be external or internal corrosion, internal erosion, equipment wear, metallurgical
defects, operator errors third party damage or for operational requirements.
Generally releases are categorized as:
1. Catastrophic Failure: A vessel or tank opens completely immediately releasing its contents. The
amount of release is dependent of the size of the container.
2. Long Rupture: A section of pipe is removed leading to two sources of gas. Each section being
vented 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 exposing the cross sectional area of the pipe (e.g.,
drilling blowouts).
4. Short Rupture: A split occurs on the side of the pipe or hose. The cross sectional area of the
opening will typically be equal to the cross sectional area of the pipe or hose (e.g., pipe seam split).
5. Leak: Leaks are typically developed from valve or pump seal packing failures, localized corrosion
or erosion effects 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 fail
which release vapors or liquids to the environment unexpectedly.
7. Normal Operational Releases: Process storage or sewer vents, relief valve outlets, tank seals,
which are considered normal and acceptable practices that release to the atmosphere.
Gaseous Releases
There are a number of factors that determine the release rate and initial geometry of a hydrocarbon gas
release. 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 is
isolated, depleted or hlly depressured. Common long duration sources are underground reservoirs (e.g.,
blowouts), or long pipelines without intermediate isolation capabilities.
If released under atmospheric conditions the gas will either rise or fall depending on its vapor density and
will be directed in the path of the prevailing wind. In the absence of a wind, heavier gases will collect in low
points in the terrain. Normally atmospheric gas releases are dispersed within relatively close distances to
their point source, usually about 3 meters (10 ft.) (Reference NFPA 30, Table 5-3.5.3). These atmospheric
releases, if ignited, will burn relatively close to the source point, normally in a vertical position with flames of
short length.
For gases released under pressure, there are a number of determining factors that influence the release rates
and initial geometry of the escaping gases. The pressurized gas is released as gas jet and depending on the
nature 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
43
surrounding structures or equipment.
If adequate isolation capabilities are available and employed, the initial release will be characterized by high
flow and momentum which decreases as isolation is applied or supplied are exhausted. Within a few pipe
diameters of the release point, the pressure of released gases decreases. Escaping gases are normally very
turbulent and air will immediately be drawn into the mixture. The mixing of air will also reduce the velocity
of the escaping gas jet. Obstacles such overhead platforms or structures will disrupt momentum forces of
any pressurized release. These releases will generally produce a vapor cloud, which if not ignited will
eventually disperse in the atmosphere. Where turbulent dispersion processes are prevalent (e.g., high
pressure flow, winds, congestion, etc.), the gas will spread in both horizontal and vertical dimensions while
continuing mixing with available oxygen in the air. Initially escaping gases are above the UEL but with
dispersion and turbulence effects they rapidly pass into the flammable limits. If not ignited and given an
adequate distance they will eventually disperse below the LEL. Various computer software programs are
currently available that can calculate the turbulent jet dispersion, downwind explosive atmospheric locations,
and volumes for any given flammable commodity, release rates and atmospheric data input.
Generally most gases have a low vapor density and will rise. In any event, the height of a gas plume will
mostly be limited by the ambient atmospheric stability and wind speed. If the gases are ignited, the height of
the plume will rise due to the increased buoyancy of the high temperature gases from the combustion
process.
Mists or Spray Releases
Spray and mists releases generally behave like a gas or vapor release. The fuel is highly atomized and mixed
with air. Sprays or mists can easily be ignited, even below the flash point temperature of the material
involved, since mixing of the fuel with the air has already occurred.
Liquid Releases
Liquids releases can be characterized by either being contained, allowed to runoff or spread to lower surface
elevations. If they are highly volatile, dissipation by vaporization may occur when the vaporization rate
equals the spread rate. Depending on the viscosity of non-volatile liquids, they will spread-out immediately
and 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 a
level surface will cover approximately 1.8 square meters (20 sq. ft.), regardless of viscosity. A pool on calm
water will spread under the influence of gravity until limited by surface tension, typically giving a minimum
oil slick thickness of 10 mm (0.04 inches) on the water. A pool on the water will also drift in the direction
of wind and current If not ignition occurs, the lighter ends will evaporate and eventually the residual oil will
be broken up by wave action and bacteriological digestion. During the evaporation of the lighter fractions,
combustible vapors may form immediately above the oil spill for a short distance.
Liquids under pressure (pipeline leaks, pump seal failures, etc.), will be thrown some distance from the point
source, while atmospheric leakages will emit at the point of release. The other characteristic of liquid
releases is their flash points. High flash point liquids, not operating above their flash point temperatures, are
inherently safer than low flash point liquids. Most liquid fires are relatively easy to contain and suppress
while gas fires are prone to explosion possibilities if extinguished and source points are not isolated.
44
Handbook of Fire and Explosion Protection
Liquid releases are characterized by the following features:
1 . Leaks and Drips:
Leaks and drips are characterized by small diameter releases of high
frequencies. They are typically caused by corrosion and erosion failures of piping, mechanical and
maintenance failures of gaskets and valves.
2. Streams: Medium size releases of moderate to low frequencies. Typically small diameter pipe
openings that have not be adequately closed, i.e., sample or drain lines.
3. Sprays and Mists: Medium sized releases of moderate frequencies that are mixed immediately in
to air upon release. Typically pipe gasket, pump seal and valve stem failures under high pressure.
On occasion releases occur from flare stacks.
4. Ruptures: Large releases of very low frequencies. Typically vessel, tank pipeline or hose failures
from internal, external, or third party sources and fire conditions (i.e., B L E W conditions).
Nature and Chemistry of Hydrocarbon Combustion
Simple hydrocarbon fires combine with 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 of
radiation energy, usually heat and light. In the case of common fuels, the process is one of chemical
combination with atmospheric oxygen to produce as the principal products carbon dioxide, carbon
monoxide, and water. Hydrocarbons are freely burning and generally easily ignitable in open air situations.
The energy released by the combustion causes a rise of temperature of the products of combustion. The
temperature attained depends on the rate of release, ‘dissipation of the energy, and the quantity of
combustion products. Air is the most convenient source of oxygen, but because air is three-quarters
nitrogen by weight, nitrogen becomes the major constituent of the products of combustion, and the rise in
temperature is substantially less than if pure oxygen was used. Theoretically, in any combustion, a minimum
ratio of air to fuel is required for complete combustion. The combustion, however, can be made more
readily 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 of
combustion and the final temperature desired. Air with enriched oxygen content or pure oxygen, as in the
case of the oxyacetylene torch will produce high temperatures. The rate of combustion may be increased by
finely dividing the fuel to increase its surface area and hence its rate of reaction, and by mixing it with the air
to provide the necessary amount of oxygen to the hel.
Hydrocarbon materials must first be in a vapor condition before combustion processes can occur. For any
gaseous material this is an inherent property. Liquids however must have significant vapor emissions in
order for flammable concentrations to be present for combustion processes to occur. Therefore
hydrocarbon liquid releases are nominally less dangerous than a gas release.
Gases by their nature are immediately ignitable (versus liquid releases that must vaporized to support
combustion), and can produce a fast burning flame front that generates into an explosive force in confined
areas. If pressurized gas leak fires are extinguished, but the leakage is not stopped, the vapors can again be
re-ignited and produce an explosive blast.
When an ignition source is brought into contact with a flammable gas or mixture of gases, a combustion
chemical reaction will occur at the point of introduction provided an oxidizer is present, normally oxygen.
The combustion components are commonly referred to as a simple fire triangle:
Characteristics of Hydrocarbon Releases, Fires and Explosions
Ignition Source
45
Oxidizer
Fire Triangle
A more scientific representation is a fire tetrahedron with the combustion chemical reaction considered as a
fourth parameter or side of the tetrahedron.
Combustion will occur which travels from the point of origin throughout 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 a
suppression mechanism interrupts the process.
The basic equation for the chemical reaction of hydrocarbon molecules in ideal combustion is provided by
the following:
In ideal combustion 0.45 kgs (1 lb.) of air combines with 1.8kgs (4 Ibs.) of oxygen to produce 1.2 kgs (2.75
lbs.) of carbon dioxide and 1.02 kgs (2.25 lbs.) of water vapor. Carbon monoxide, carbon dioxide, nitrogen
and water vapor are the typical exhaust gases of ordinary combustion processes. If other materials are
present they will also contribute to the exhaust gases forming other compounds, which in some cases can be
highly toxic. Imperfect combustion will occur during accidental fires and explosion incidents. This mainly
due to turbulence, lack of adequate oxidizer supplies and 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 liquid
hydrocarbon 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 is
mixed-in during the free air combustion process). Because of this, it is sometimes used as the main
constituent in tire mass release dispersion modeling. The mass flow rate is normally taken as fiReen times
the burning rate of the hydrocarbon material. A typical fuel burning rate for liquid hydrocarbons is 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. Ordinary
combustibles produce a moderate level of heat release but hydrocarbon molecules have a very high level of
heat release. In ideal combustion of 0.45 kgs (1 lb.) of methane, approximately 25,157 kilo-joules (23,850
Btu) are released. The temperature of the combustion products is normally taken to be 1200 OC (2192 OF),
which is a typical hydrocarbon fire temperature.
A heat flux rate is commonly specified during consequent modeling of hydrocarbon fires. Heat flux is
considered the more appropriate measure by which to examine the radiation effects from a fire. A radiant
heat flux of 4.7 kw/m2 (1,469 Btu/fk2) will cause pain on exposed skin, a flux density of 12.6 kw/m2 (3,938
Btu/il2) or more may cause secondary fires and a flux density of 37.8 kw/m2 (11,813 Btu/fL2) will cause
major damage to a process plant and storage tanks.
Under atmospheric conditions flame travel in an unconfined gas cloud precedes as definite flame front at a
determinable 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 Protection
propagation results from the conduction transfer of energy from the flame front to the layer of gases in front
of it. These gases are in turn ignited, which continues the process. In mixtures that contain the fuel and
oxidizer in proportions outside the LELMiL, insufficient heat energy is released by combustion heat to the
adjacent layers of gases to produce sustained combustion. Where the combustion is within the LEL/UEL
limits flame propagation appears most rapid in an upward direction, which is chiefly due to convection
currents. When any large accumulation of gaseous fuel and air mixture is ignited, convection currents cause
flames to be carried upwards, while burring in the horizontal direction is relatively slower.
In normal atmospheric conditions, fire usually is initialed by a combustible material coming in contact with a
heat source. The spread of fire occurs due to direct flame impingement or the transfer of heat to the
surrounding combustible materials. Heat transfer occurs by three principal mechanisms - conduction,
convection, and radiation. Conduction is 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 fire
if left unprotected.
Convection signifies the transfer of heat from one location to another by a carrier medium moving between
them, such as when a gas is heated at one point and travels to another point at which it gives up its heat.
Convection currents of heated hot air and gases normally account for 75 to 85% of the heat generated from
a fire. Large masses of heated air by flame convection currents will quickly raise the temperature of all
combustible material in their path to the required ignition temperature. Where prevented by rising by
structural components (i.e., ceilings, decks, etc.), the fire will spread out laterally and form a heat layer with
increasing depth and intensity as the fire progresses. Within enclosed spaces the ambient conditions soon are
raised to a temperature above the ignition point and combustion occurs simultaneously everywhere, known
as a flashover.
Radiation is the transfer of energy by electromagnetic waves and can be compared to the transmission of
light through the atmosphere. When radiation waves meet an object, their energy is absorbed by that object
at it's surface. The rate of heat transfer by conduction is proportional to the temperature difference between
the point giving up and receiving the heat. In convection the rate of heat transfer is dependent upon the rate
of movement of the carrier medium. This movement may be caused by differences in density of the material
or due to mechanical pumping (e.g., hot air blowing systems). In the radiation of heat, the transfer rate is
approximately proportional to the fourth power of the temperature difference between the radiating source
and the receiver. Thus the radiant heat transmission from fires is a high factor to consider for any fire
incident and hence the importance placed on cooling exposed surfaces of processes and preservation of
structural support by fireproofing materials.
If a hydrocarbon release is ignited, various possible fire and explosion events may result. The events are
primarily dependent on the type of material, the rate of release, the item at which it is ignited and nature of
the surrounding structure.
Eydrocarbon Fires
A
Typically hydrocarbon fire events can be categorized as follows:
Jet Fire
Most fires involving gas in the oil and gas industry will be associated with a high pressure and
labeled 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. If
such a release is ignited soon after it occurs, (i.e., within 2 -3 minutes), the result is an intense jet
Characteristics of Hydrocarbon Releases, Fires and Explosions
47
flame. This jet fire stabilizes to a point that is close to the source of release, until the release is
stopped. A jet fire is usually a very localized, but very destructive to anything close to it. This is
partly because as well as producing thermal radiation, the jet fire causes considerable convective
heating in the region beyond the tip of the flame. The high velocity of the escaping gas entrains
air 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 immersed in 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 first
10% of a jet fire length is conservatively considered unignited gas, as a result of the exit velocity
causing the flame to lift off the gas point of release. This effect has been measured on
hydrocarbon facility flares at 20% of the jet length, but a value of 10% is used to account for the
extra turbulence around the edges of a real release point as compared to the smooth gas release
from a flare tip. Jet flames have a relatively cool core near the source. The greatest heat flux
usually occurs at impingement distances beyond 40% of the flame length, fiom its source. The
greatest heat flux is not necessarily on the directly impinged side.
Pool Fire
Pool fires have some of the characteristics of a vertical jet fire, but their convective heating will
be much less. Heat transfer to objects impinged or engulfed by pool fires is both by convection
and radiation. Once a pool of liquid is ignited, gas evaporates rapidly from the pool as it is
heated by the radiation and convective heat of the flame. This heating mechanism creates a
feedback loop whereby more gas becomes vaporized fiom the liquid surface. The surface fire
increases in size in a continuing process of radiation and convection heating to the surrounding
area until essentially the entire surface of the combustible liquid is on fire. The consequences of a
pool fire are represented numerically by a flame zone surrounded by envelopes of different
thermal radiation levels. Heat transfer rates to any equipment or structure in the flame will be in
the range of 30 to 50 kw/sq. m. (9,375 to 15,625 Btdsq. ft.).
Flash Fire
If a combustible gas release is not ignited immediately, a vapor plume will form. This will drift
and 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 be
isolated during this time, the flash fire will burn back to a jet fire at the source of the release. A
flash fire is represented by its limiting envelope, since no damage is caused beyond it. This
envelope is usually taken as the LEL of the gas cloud.
Mathematical estimates are available that can calculate the flame and heat effects (i.e., size, rate and
duration) for pool, jet and flash hydrocarbon fires. These estimates are based on the "assumed" parameter of
the material release rate. To some extent, the ambient wind speed also has a varying influence.
All hydrocarbon fire mechanisms and estimates will be affected by to some extent of flame stability features
such 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 level
where precise estimations can be made without scale model tests or on site measurements.
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Handbook of Fire and Explosion Protection
Nature of Hydrocarbon Explosions
A combustible vapor explodes under a very specific set of conditions. There are two explosive mechanisms
that need to be considered when evaluating combustible vapor incidents - detonations or deflagrations. A
detonation is a shock reaction where the flames travel at supersonic speeds (ie., faster than sound).
Deflagrations are where the flames are traveling at subsonic speeds.
During the 1970s, considerable progress was made in the understanding of supersonic explosions, i.e.,
detonations. It was shown that the conditions needed to initiate a denotation - whether by shock, flame jet
ignition or flame acceleration are too extreme to occur in everyday operation for all non-pressurized natural
gas and air systems. However they can still occur in pressurized gas and air systems (i.e., process vessels
and piping). It is generally recognized that vapor cloud explosions have flames that travel at subsonic speeds
and are therefore technically classified as deflagrationsbut are still commonly referred to as explosions.
Process System Explosions (Detonations)
Detonations can occur in solids and liquids but are particularly frequent in petroleum facilities in mixtures of
hydrocarbon vapors with air or oxygen. Detonations will develop more rapidly at initial pressures above
ambient atmospheric pressure. If the initial pressure is high the detonation pressure will be more severe and
destructive.
Detonations produce much higher pressures than what be considered ordinary explosions. In most cases a
process vessel or piping systems will be unable to contain detonation pressure. The only safe procedure is to
avoid process system detonations is to preventing the formation of flammable vapor and air mixtures within
vessels and piping systems. While the flame speed of explosions is at relatively slow speed, detonations
travel at supersonic speeds and will be more destructive.
Vapor Cloud Explosions
An unconfined vapor cloud explosion (UCVE) is a popular term that tries to explain the ignition of
combustible gas or vapor releases in the open atmosphere. In fact a considerable amount of published
literature states that "open" air explosion will only occur if there is sufficient congestion or in some cases
turbulence of the open air is occurring, Gas or vapor clouds ignited under certain conditions produce an
explosion. Two types of explosions are classified, detonation (supersonic, shock reaction) and deflagration
(subsonic, turbulent flame). Research into the mechanism of flames indicates that vapor cloud explosions
are high-speed, but have subsonic combustion resulting in a deflagration not a detonation. Experiments have
also demonstrated that flames traveling though unenclosed gas and air clouds produce negligible
overpressures. When objects such as pipes and vessels are near or in the presence of an ignited gas cloud
they generate turbulence produce damaging explosion overpressures ahead of the flame front.
In order for a vapor cloud explosion to occur in a hydrocarbon facility, four conditions have to be achieved:
(1) There has to a significant release of flammable material.
(2) The flammable material has to be sufficiently mixed with the surrounding air.
(3) There has to be an ignition source.
(4) There has to be sufficient confinement, congestion, or turbulence in the released area.
Characteristics of Hydrocarbon Releases, Fires and Explosions
49
The amount of explosion overpressure is determined by the flame speed of the explosion. Flame speed is a
fknction of the turbulence created within the vapor cloud that is released and the level of &el mixture within
the combustible limits. Maximum flame velocities in test conditions are usually obtained in mixtures that
contain slightly more he1 than is required for stoichiometric combustion. Turbulence is created by the
confinement and congestion within the particular area. Modern open air explosion theories suggest that all
onshore hydrocarbon process plants have enough congestion and confinement to produce vapor cloud
explosions. Certainly confinement and congestion are available on most offshore production platforms to
some degree.
Two types of open air explosions are possible, representing two different mechanisms for pressure buildup.
Semi-confined Vapor Cloud Explosions
These require some degree of confinement, usually inside a building or module. The mechanism of
pressure 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 insufficient
gas for the flame fiont to accelerate to the necessary speed. These explosions can occur with small
amounts of gas.
Vapor Cloud Explosions
These explosions may occur in unconfined areas, although some degree of congestion is still required.
The overpressure is created by the rapid and accelerating combustion of the gas and air mixture. The
speed of the flame front can reach over 2,000 meters per second, (6,000 fth)creating a shock wave
as it pushes the air ahead of it. Vapor cloud explosions can 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 a
blast wind that is a transient flow behind the blast wave. The impact of the blast wave on structures near the
explosion is known as blast loading. The two important aspects of the blast loading concern is the
prediction of the magnitude of the blast and of the pressure loading onto the local structures. Pressure
loading predications as a result of a blast, resemble a pulse of trapezoidal or triangular shape. They normally
have a duration of between approximately 40 msec and 400 msec. The time to maximum pressure is
typically 20 msec.
Primary damage from an explosion may result from several events:
1. Overpressure
-
the pressure developed between the expanding gas and it’s surrounding
atmosphere.
2. Pulse - the differential pressure across a plant as a pressure wave passes might cause collapse
or movement, both positive and negative.
3. Missiles and Shrapnel - are whole or partial items that are thrown by the blast of expanding
gases 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 lift
heavy items such as vessels, valves, etc. This is in direct opposite to a rupture, in which the
rupture or internal vessel explosion, causes portions of the vessel or container to be thrown far
distances. In general these “missiles” from atmospheric vapor cloud explosions cause minor
impacts to process equipment since insufficient energy is available to lift heavy objects and
cause major impacts. Small projectile objects are still a hazard to personnel and may cause
injuries 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 Protection
pressure relief systems (overpressure safety valves, depressuring capability, etc.) in the
hydrocarbon and chemical industries.
In oil and gas facilities, these effects can be generally related to flame velocity, where this velocity is below
100 m / s (300 ft./s), damage is considered unlikely (Note: This is generally within the limits of confinement
normally found in offshore facilities). The size of a vapor cloud or plume in which such velocities can occur
has been experimentally investigated at the Christian Michelsen Institute (CMI, Norway). The experiments
demonstrated that flames need a "run-up" distance of approximately 5.5 meters (18 fi.) to reach damaging
speeds. Therefore vapor clouds with dimensions less than this may not cause substantial damage. This is a
much over-simplification of the factors and variables involved, but does assume the WCCE of congestion,
confinement and gas concentrations.
Semi-confined Explosion Overpressures
The overpressure developed in semi-confined explosions depends on the following key parameters:
- The Volume of the Area:
Large confined areas experiences the largest overpressures.
- Ventilation Area:
The degree of confinement is of vital importance. The existence of openings,
whether permanent vents or covered by light claddings greatly reduce the predicted overpressure.
- Obstacles. Process Equipment, and Piping:
Structural steel and other obstacles create turbulence in
the burning cloud, which increases the overpressure The profile, size and location of obstacles
will all influence the amount of overpressure developed.
- Ignition Point:
Ignition points at long distances from the vent areas increase the overpressure.
- Gas Mixture:
Most studies have been on methane and air mixtures, but propane and air mixtures
are known to be slightly more reactive and create higher overpressures. Increasing the content of
the higher hydrocarbon gases is therefore expected to have a similar effect. The initial temperature
of the mixture may also influence overpressure outcomes.
- Gas:Combustible gasses must be mixed with air to achieve the explosive range limits for
the particular gas. A worst case mixture, slightly richer in fuel than stoichiometric, corresponding
to the fastest burning mixture is normally used in calculation estimates providing a conservative
approach.
Some consulting companies and the risk engineering departments of insurance agencies have software
available to perform estimates of overpressures for semi-confined explosions, taking in account these
particular parameters. These proprietary software models are generally based on empirical formulas, with
validation against 1 :5 scale experimental testing and studies against actual historical incidents, Le., Piper
Alpha, Flixborough and others.
Vapor Cloud Explosion Overpressures
Previous studies of Vapor Cloud Explosions (VCE) have used a correlation between the mass of a gas in the
cloud and equivalent mass of TNT to predict explosion overpressures. This was always thought to give
conservative results, but recent research evidence indicates that this approach is not accurate to natural gas
and air mixtures. The TNT models do not correlate well in the areas near to the point of ignition, and
generally over estimate the level of overpressures in the near field. Experiments on methane explosions in
"unconfined" areas have indicated a maximum overpressure of 0.2 bar (2.9 psio). This overpressure then
decays with distance. Therefore newer computer models have been generated to better simulate the effects
Characteristics of Hydrocarbon Releases, Fires and Explosions
51
of real gas and air explosion from historical and experimental evidence.
The criteria selected for an overpressure hazard is normally taken as 0.2 bar (3.0 psio). Although fatalities
due to direct effects of an explosion may require up to 2.0 bar (29.0 psio) or higher, significantly lower
levels result in damages to structures and buildings that would likely cause a fatality to occur. An
overpressure of 0.2 to 0.28 bar (3.0 to 4.0 psio) would destroy a frameless steel panel building, 0.35 bar (5.0
psio) would snap wooden utility poles and severely damage facility structures, and 0.35 to 0.5 bar (5.0 to
7.0 psio) would cause complete destruction of houses.
Historically, all reported vapor cloud explosions have involved the release of at least 100 kgs (220 lbs.) of
combustible gas, 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.) of
material or more be examined for the possibilities of explosions. Additionally the possibilities associated
with vapor clouds exploding that are 4,536 kgs (10,000 lbs.) or less, are considered very low. Most major
catastrophic incidents in the process industries have occurred when the level of material released has been of
a large quantity. Generally for vapor cloud explosions that are less than 4,536 kgs (10,000 lbs.), less
damage occurs than at greater volumes (Le., greater than 4,536 kgs (10,000 lbs.)).
A natural gas and air mixture is only likely to explode if all of the following conditions are met:
(1) A high degree of congestion from obstacles creating turbulence.
(2) A large area, allowing the flame front to accelerate to high velocities.
(3) A minimum flammable mass of 100 kgs (220 lbs.) is generally required flame front
acceleration.
It could be argued that vapor cloud explosions for hydrocarbon facilities need only be calculated for those
facilities that contain large volumes of volatile hydrocarbon gases that can be accidentally released and
where some degree of confinement or congestion exist. The most probable amount for an incident to occur
is 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) at
say 46 meters (150 ft.), indicates a minimum of 907 kgs (2,000 Ibs.) of material is needed to cause that
amount of overpressure. A limit of 907 kgs (2,000 lbs.) release of hydrocarbon vapor is considered a
prudent and conservative approach.
Boiling Liquid Expanding Vapor Explosions (BLEVE)
BLEVE types of incidents arise from the reduction in yield stress of a vessel or pipe wall to the point that it
cannot contain the imposed stresses by the design and construction of the container and are also influenced
by the relief valve set point. This results in a sudden catastrophic failure of the containment causing the
violent discharge of 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). The
metal may not be able to withstand the internal stress and therefore failure occurs. The contained liquid
space of the vessel normally acts as a heat absorber, so the wetted portions of the container are usually not
at risk, only the surfaces of internal vapor spaces. Most BLEWs occur when containers are less than 1/2 to
113 full of liquids. The liquid vaporization expansion energy is such that container pieces have been thrown
as far as 0.8 km (1/2 mile) from the rupture and fatalities from such incidents have occurred up to 244
meters (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 have
occurred to personnel as much as 76 meters (250 Ft.) away from the point of rupture.
52
Handbook of Fire and Explosion F’rotection
A study of B L E W occurrences in LPG storage vessels ranging from 3.8 to 113 cubic meters (32 to 947
bbls) capacity, showed a time range to rupture of 8 to 30 minutes, with approximately 58% occurring within
15 minutes or less.
Smoke and Combustion Gases
Smoke is a by-product of most fires caused by the incomplete oxidation of the fuel
suppIy during the chemical process of combustion. It accounts for a large majority of
fatalities of from fire incidents at both onshore and offshore petroleum facilities In the
Piper Alpha incident of 1988, probably the worst petroleum industry offshore life loss
incident, the majority of deaths were not from burns, drowning or explosion impacts but
from smoke and gas inhalation. The report on the incident concluded that, of the
bodies recovered from the incident, 83% were as a result of inhalation of smoke and
gas. Most of these victims were assembled in the accommodation awaiting evacuation
directions or 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. At
high combustion temperatures, carbon reacts directly with oxygen to form carbon monoxide (CO) and
carbon dioxide (C02).
The main dangers of smoke are the presence of narcotic gases principally carbon monoxide (CO), hydrogen
cyanide (HCN), carbon dioxide (C02) and the asphyxiating effects of an oxygen depleting atmosphere due
to the combustion process that severely affect human respiration. Inhaling narcotic gases often leads to a
hyperventilation and therefore increased inhalation of gases as the breathing rate increases. Narcotic gases
also cause incapacitationby an attack on the central nervous system.
A low level of oxygen in the brain leads to psychological disorders which cause impaired judgments and
concentration. These effects may confuse, panic or incapacitate personnel. Carbon monoxide poisoning
causes suffocation by blocking transport of oxygen in the blood. Incapacity occurs in less than 10 minutes
with a 0.2% concentration of CO if heavy activities are being performed. Carbon monoxide kills because it
combines with the hemoglobin of the blood, preventing oxygen to bind with the hemoglobin which is
necessary for sustained life. Carbon monoxide has an affinityfor hemoglobin 300 times that of oxygen. The
degree of poisoning depends on the time of exposure and concentration of the gas. If the percentage of
carbon monoxide in the blood rises to 70% to SO%, death is likely to 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 the
oxygen unavailable to the tissues, and cause death through asphyxia. Inhaling concentrations of more than
180 ppm of HCN will lead to unconsciousness in a matter of minutes, but the fatal effects would normally be
caused by carbon monoxide poisoning after HCN has made the victim unconscious. Exposure to HCN
concentrations of 100 to 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 could
result in 6 to 24 hours after the exposure.
Characteristics of Hydrocarbon Releases, Fires and Explosions
53
Psychologically the sight and smell of smoke may induce panic and disorientation. When this occurs
movement of personal to achieve evacuation objectives may be severely inhibited. This is especially critical
where personnel are unfamiliar to the facility. Smoke will also hinder fire fighting and rescue efforts.
Smoke travel is affected by the combustion particles rise, spread, rate of bum, coagulation and ambient air
movements. Combustion products due to heating by the fire tend to generally rise because they are lighter in
weight than the surrounding air. They will spread out when encountering objects such as a ceiling or
structural components. The smoke particulates will readily penetrate every available opening, such as
cracks, crevices, staircases, etc. Rate of bum is the amount of material consumed by combustion in any
given time period. Particle coagulation is the rate at which combustion particles gather into groups large
enough to precipitate out of the air. Coagulation occurs continuously because of the mutual attraction of
the combustion particles. Air movement will direct smoke particles in a particular pattern or direction.
Currently a mathematical model for the dispersion of smoke plumes from hydrocarbon liquids is unavailable,
but dispersion models for combustion gases may be used as a rough comparison. At close distances to a fire
this is provides a reasonable approximation, since the solid particles tend to be entrained in the combustion
gases. However gases tend to disperse much more readily in the ambient air than solid particles, so this
technique is not suited to predict extremely long smoke plumes generated from hydrocarbon fires.
Additionally ambient atmospheric conditions at the time of an incident will greatly influence the dissipation
or collection of smoke partjculates. For interior locations, smoke generation from hydrocarbon fires is
assumed to completely fill the enclosure.
Whenever the effects of smoke will affect personnel adequate respiratory protection must be provided, such
as smoke resistant barriers and fresh air supplies.
Mathematical Consequence Modeling
The use of computers for rapidly and easily estimating the effects from explosion,
fire, and smoke events has grown tremendously in the last several years.
Specialized risk consultants and even insurance risk ofices can now offer a variety
of software products or services to conduct mathematical consequence modeling of
most hydrocarbon adverse events. The primarily advantage of these tools is that
some estimate can be provided on the possible effects of an explosion or fire
incident where previously these effects were rough guesses or unavailable
Although these models are effective in providing estimate they still should be used
with caution and consideration of other physical features that may alter the real
incident outcome,
All mathematical models require some assumed data on the source of release for a material. These
assumptions form the input data which is then easily placed into a mathematical equation. The assumed data
is usually the size or rate of mass released, wind direction, etc. They cannot possibly take into account all
the variables that might exist at the time of the incident. Unfortunately most of the mathematical equations
are also still based on empirical studies, laboratory results or in some cases TNT explosion equivalents.
Therefore they still need considerable verification with tests simulations before they can be fully accepted as
valid.
54
Handbook of Fire and Explosion Protection
The 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 of
similar incidents for the industry and location. In other cases where additional analysis is needed, several
release scenarios (small, medium and large) can be examined and probabilities can be assigned to each
outcome. This would then essentially be an Event Tree exercise normally conducted during a quantitative
risk analysis. Certain releases may also be considered so rare an event they may be outside the realm of
accepted industry practical protective requirements.
Some readily available commercial consequence models include the following:
Gas discharge from an orifice
Gas discharge from a pipe
Liquid discharge from an orifice
Liquid discharge from a pipe
Two-phase discharge from a orifice
Two-phase discharge from a pipe
Adiabatic expansion
Liquid "pool" spill and vaporization
Vapor plume rise
Jet dispersion
Dense cloud dispersion
Neutrally buoyant dispersion
Liquid "poolrrfire
Jet flame
FirebalVBLEVE
Vapor cloud explosion blast pressures
Indoor gas build-up
From the estimates of fire or explosion exposures, the effectiveness of various fire protection systems can be
examined or compared, e.g., heat absorption of deluge water sprays at various densities, fire proofing at
various thicknesses or types of materials, etc. Some cases of theoretical fire modeling have proven very cost
effective, by demonstrating for example that fireproofing was not beneficial to the subject application since
the 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 savings
obtained by decreased amounts of fireproofing installation requirements.
Characteristics of Hydrocarbon Releases, Fires and Explosions
55
Methods of Flame Extinguishment
If any one of the principle elements of the combustion process cam be removed from a fire, it will be
extinguished. The principle methods of extinguishment are 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 ignition temperature results in extinguishment of the fire. For liquid
hydrocarbon fires it also slows and eventually stops the rate of release of combustible vapors and
gases. Cooling by water also produces steam, which may partially dilute the ambient oxygen
concentration local to the fire point. Because heat is continually being released by the fire in the form
of radiation, convection and conduction it is only necessary that a small amount of a heat absorbing
commodity be applied to the fire in order for it to be extinguished by cooling means.
Oxygen Depravation (steam smothering , inerting, foam sealing, C 0 2 application, etc.)
The combustion process requires oxygen to support its reaction. Without oxygen the combustion
process will cease. The normal oxygen level in the atmosphere is approximately 21 percent
(approximately 20.9 % Oxygen, 78.1% Nitrogen, 1% Argon, C 0 2 and other gases). Combustion of
stable hydrocarbon gases and vapors will usually not occur when the ambient oxygen level is lowered
to below 15 percent. Acetylene which is an unstable hydrocarbon, requires the oxygen concentration
to be below 4 percent for flame extinguishment. For ordinary combustibles (wood, paper, cotton,
etc.), the oxygen concentration levels must 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 combustion process will
be terminated. For some suppression methods, oxygen is not removed from a fire but merely
separated from 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 be
available for the combustion process to continue and it will cease. In some cases, a fuel is not
literally removed from a fire, but is separated from the oxidization agent. Foam suppression methods
are 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, as
methods of fuel removal.
Chemical Reaction Inhibition (Halon, Inergen, etc., applications)
The chemical chain reaction is the mechanism by which the fuel and oxidizing agents produce fire. If
sufficient amounts of a combustion inhibiting agent (e.g., Dry Chemical agents or Halogenated
Hydrocarbon agents) are introduced the combustion process will stop. Chemical flame inhibition
interrupts the chemical process of combustion by inhibiting the chain reaction.
Flame Blow Out
Flame extinguishment can be accomplished dynamically through the combined action of oxygen
dilution and flame blow-out or application of rapid ambient air velocity such as when a candle is
blown out. It is achieved when the ambient air velocity exceeds the flame velocity. Techniques such
as these are applied during specialized well blowout control measures. The detonation of a high
explosive results in a pressure wave that "blows out" the wellhead fire by separating the flame from
the available combustible gas. Some specialized apparatus is also available that uses jet engines to
literary "blow out" wellhead fires. These jet engine devices have been used to control blowouts in the
Russian oil industry and several wellhead fires in the aftermath of the Gulf War.
56
Handbook of Fire and Explosion Protection
Selection of Fire Control and Suppression Methods
The method of fire incident protection, control and suppression can be generally determined by reference to
NFPA 325M, "Fire Hazard Properties of Flammable Liquids, Gases and Volatile Solids". This reference
provides a basic guideline to determine the most effective protection method to apply for an emergency
situation. Although this guide is a gross oversimplification of the type of incident and configurations that
may be involved, it does provide a starting point and supporting documentation to justify the selection of a
particular fire protection, control and suppression methodology to a hydrocarbon facility .
The first step in this methodology is to fully identiry the type of materials that may be present during the fire
incident. Once this is known a Fire Risk Hazardous Zone should be identified which is the most probable
location of the fire. This is typically the enclosed area ofa spillage or liquid runoff areas at a vessel, pump or
tank. Based upon isolatable inventories or risk analysis consequential modeling, the drawing can be further
subdivided into specific levels of Fire Risk Hazardous Zones for the duration of fire events. Reference to
NFP A 325M can then be made to determine what is the optimum fire protection, control and suppression
method to apply. The duration or fire resistance of the fire protection option can also determined. Once this
is accomplished, suitable fixed passive or active protection equipment and ratings or capacities can be
designed or specified. The need for primary process safeguards (ESD, isolation, depresurization, and
blowdown), can also be determined or reconfirmed. Process safeguards should always be considered the
primary loss prevention system for any process facility and fire protection measures are backups or
secondary protection systems.
The easiest way to document the selection process is to prepare a table of the materials involved and the
required extinguishing methods. Tables 3 and 4 provide examples of documentation that is prepared in the
industry .Fire Risk Hazardous Zone drawings are prepared using published literature on commodity hazards
and extinguishing methods (Ref. NFPA 325M).
Table
3
Fire Hazard Zone Identification Example
Characteristics of Hydrocarbon Releases, Fires and Explosions
Table
4
Fire Extinguishing Explanations, Fire Hazardous Zone Drawings
57
58
Handbook of Fire and Explosion Protection
Terminology of Hydrocarbon Explosions and Fires
The following terminology is used in the description of the various fires and explosions that can occur at a
hydrocarbon facility.
Blast - Is the transient change in gas density, pressure, and velocity of the air surrounding an
explosion point.
Blowout - A blowout is a high pressure release of hydrocarbons, which may or may not ignite, that
occurs when a high pressure oil or gas accumulation is unexpectedly met while drilling and the mud
column fails to contain the formation fluid that is expelled through the wellhead bore.
Boiling Liquid Expanding Vapor Explosion (BLEW) - Is the nearly instantaneous vaporization
and corresponding release of energy of a liquid upon its sudden release from a containment under
greater than atmospheric pressure and at a temperature above its atmospheric boiling point.
Deflagration - Is a propagating chemical reaction of a substance in which the reaction front advances
into the unreacted substance rapidly, but at a less than sonic velocity in the unreacted material.
Detonation - Is a propagating chemical reaction of a substance in which the reaction front advances
into the unreacted substance at greater than sonic velocity in the unreacted material.
Explosion - Is a release of energy that causes a blast.
Fireball - Is a rapid turbulent combustion of a fuel-air cloud whose energy is emitted primarily in the
form of radiant heat, usually rising as a ball of flame.
Flash Fires - Is a fire resulting from the ignition of a cloud of flammable vapor, gas or mist in which
the 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 flame
speed.
Implosion - Is an inward rupture normally caused by vacuum conditions in a vessel or tank.
Jet or Spray Fires - Are turbulent diffusion flames resulting from the combustion of a liquid or gas
continuously released under pressure in a particular direction.
Overpressure - Is any pressure relative to ambient pressure caused by a blast, both positive and
negative, sometimes referred to as "psio".
Running Fire - Is a fire from a burning liquid &el that flows by gravity to lower elevations. The fire
characteristics are similar to pool fires except it is moving or draining to a lower level.
-
Ruptures or Internal Vessel Explosions An catastrophic opening of a container (i.e., tank, vessel
or pipe), commonly from overpressure or metallurgical failure, resulting in the immediate release of
its contents.
Smoke - The gaseous products of the burning of carbonaceous materials made visible by the
presence of small particles of carbon, the small particles which are of liquid or solid consistency, are
produced as a by product of insufficient air supplies to a combustion process.
Spill or Pool Fire - Is a release of a flammable liquid and or condensed gas that accumulates on a
surface forming a pool, where flammable vapors burn above the liquid surface of the accumulated
liquid.
Characteristics of Hydrocarbon Releases, Fires and Explosions
59
Vapor Cloud Explosion (VCE) - Is an explosion resulting from the ignition of a cloud of flammable
vapor, gas or mist in which the flame speed accelerates to produce an overpressure.
60
Handbook of Fire and Explosion Protection
Commodity
Methane
LNG
Ethane
Propane
Butane
LPG
Crude Oil
Gasoline
Diesel
Explosion
X
X
X
X
X
X
X
X
Pool
Fire
X
X
X
X
X
Jet
Fire
X
X
X
X
X
X
Smoke
X
X
X
X
Table 5
General Hazards of Common Petroleum Commodities
(Under typical process operations and conditions)
Characteristics of Hydrocarbon Releases, Fires and Explosions
61
Bibliography
1.
A. D. Little, Inc., ADL FlRST Facilitv Risk Screenin? Tool, AD. Little, Cambridge, MA, 1992.
2.
American Petroleum Institute (API), Publication 4545. Hazard Response Modeling Uncertainty (A Ouantitative
Method): Users Guide for Software for Evaluatin? Hazardous Gas Dispersion Models, Volume 1, API, Washington,
D.C., 1992.
3.
American Petroleum Institute (API), Publication 4546. Hazard Response Modelinp Uncertaintv (A Ouantitative
Method): Evaluation of Commodv Used Hazardous Dispersion Models, Volume 2, API, Washington, D.C.: 1992.
4.
American Petroleum Institute (API), Publication 4547, Hazard Response Modeling Uncertainty (A Ouantitative
Method): Components of Uncertainw in Hazardous Gas Dispersion Models, Volume 3, API, Washington, D.C.,
1992.
5.
DNV Technica. Ltd. WHAZAN 11, DNV Technica, London, U.K.
6.
Dugan, Dr.K., Unconfined Vapor Cloud Explosions, Gulf Publishing, Houston, TX, 1978.
7.
Kreith, F., Principles of Heat Transfer, International Textbook Company, Scranton, PA, 1965.
8.
National Fire Protection Association (NFPA), Fire Protection Handbook, 17th Edition, NFPA, Quincy, MA, 1991
9.
National Fire Protection Association (NFPA), NFPA 325M, Fire Hazard Prooerties of Flammable Liquids. Gases,
and Volatile Solids, NFPA, Quincy, MA, 1991.
10. Sedgwick Energy, "Loss Control Newsletter", Sedgwick Energy Limited, 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., Fundamentals of 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 6
Historical Survey of Fire and Explosions
in the Hydrocarbon Industries
Historical records show that there were many fires during the inception of the oil industry that unfortunately
continue until today. The general trend is of an ever increasing financial impact. Figure 2 graphically
portrays the U.S. Dollar amounts of the average of the single major losses for the last several decades. As
can be readily seen the recent amounts have risen dramatically from past decades and can be financially
disastrous in real dollar terms.
There is a great benefit from reviewing accident data, since we can learn from past mistakes and make
design improvements. However when analyzing accident data, only the most relatively recent data availabIe
statistics and descriptions should be used. Technological improvements and management controls are
continually improving so that the comparisons of data from historical records of say, over 15 to 25 years old,
it may be of little technical value. Although the general categories of loss mechanisms might be useful from
such outdated data, overall the precise data cannot be compared directly to todays operating environment.
Caution must also be used when comparing loss data from different geographical and political environments.
Environmental, cultural and technological differences will influence how a facility is designed and operated,
so that direct comparisons to one another cannot be made.
The National Fire Protection Association ("A)
and the insurance industry are the most available and
descriptive sources of accident data for the petroleum industry. The Occupational Safety and Health
Administration (OSHA), collects data on injuries and fatalities and does some inspections, but generally
undertakes no analysis of the causes of fires and explosions in the petroleum industry. It rather determines if
federal laws are broken and assigns a fine. In fact there is essentially no national (or international)
governmental data bank available where fire and explosion incidents from the entire petroleum, chemical or
related industries are logged or analyzed. The National Transportation Safety Board (NTSB) investigates
major incidents associated with transportation incident, i.e., pipelines, ships, and railroads in the U. S. The
Federal Aviation Administration (FAA) investigates and analyzes aircraft accidents. The MMS periodically
publishes brief offshore incident historical data for the U.S. continental shelf. Insurance agencies such as M
& MPC, Sedgwick Energy, and a few others have published comprehensive lists of onshore and offshore
incidents that have become known to them. They have undertaken to perform trend analysis and are
constantly refining the methods used determine the causes and probable consequences of an incident. With
these reviews methods of mitigation and protection are evolved. Insurance rates and coverages are also
formulated from this data.
The insurance industry as a whole has a substantial self interest in analyzing accidents, sponsoring research
and issuing publications in the methods to prevent accidents or mitigate their effects. Hence their data is the
62
Characteristics of Hydrocarbon Releases, Fires and Explosions
63
most usefbl and more readily available. Because of their own self interest, their recommendations are
sometimes considered overzealous, however the petroleum industry has typically not provided the evidence
to prove that their concerns are unduly precautions. Much of the petroleum industry is rather reluctant to
publicly divulge such information. Public outcry to have a governmental review and analysis of petroleum
incidents is essentially nonexistent. This is probably due to the generally low level of fatalities and the
perceived low level of public exposure to hydrocarbon incidents. Since petroleum and chemical industries
generally 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 environmental
regulations have amply demonstrated and the ever increasing magnitude of catastrophic incidents indicates.
Nowadays all operating oil companies have considerable legal constraints in divulging information publicly
when injuries and property damage are 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 operating
companies. They also probably have a concerted or maybe a subconscious desire to portray their operations
as safe in order to achieve a lower cost of insurance and achieve a more public acceptance of oil and gas
operations. As anyone in the petroleum industry will confidentially tell you, not all incidents that occur at
field installations are mentioned or reported and it is probably facetious to think otherwise. This is due to
the 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 incidents
in a company other than it may be difficult to deny if physical damage or injuries result. The system basically
resorts to personal honesty. In other cases where the incident is reported, it may be described in such a
fashion that it may not be recognized for the risk that it was or could represent.
Relevancy of Incidents
In reviewing accident histories, remember that the technology and operating practices employed in earlier
decades have changed tremendously to the current date and are likely to do so in the fbture. The latest
control 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 current
operating environments of most hydrocarbon facilities.
Similarly, only loss histories that can be directly related to the facility under review should be studied. Not
only should the type of facility be examined for applicability (e.g., refinery versus refinery), but the ambient
conditions in which the facility exists should be considered. For example, an oil production facility in
Northern 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 of
Mexico cannot be applied to the North Sea, however it could have similarities with the Arabian Gulf or the
South China Sea. Ideally the best loss history is from the facility itself, since every location has its own
character and operating practices. For entirely new facilities the closest representation has to be chosen.
64
Handbook of Fire and Explosion Protection
1950
1970
1990
Date
Figure 2
Historical Average Financial Loss for Major Incidents
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
65
The following is a brief selective listing of major worldwide fire and explosion incidents within the
hydrocarbon 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 other
refaences. Where the number of fatalities has been reported in public accounts they are listed next to the
financial loss. Financial losses are direct property damage losses and do not include business interruption,
legal, or environmental impacts.
1970
01.06.70
South China Sea, Blowout, Explosioflire
Drilling barge struck shallow gas followed by explosion and fireball
7 Fatalities, extensive damage to drilling barge
02.10.70
Gulf of Mexico, Main Pass Block 4 1, Platform C, Fire
Unmmed automated platform, cause of accident &own.
3 Relief wells extinguished fire.
Total platform lost.
05.28.70
Gulf of Mexico, Galveston Island Block 189, Platform A, ExplosionRire
Offshore Oil Storage Platform Fuel Tank Explosion due to welding on piping connected to tanks still containing oil
9 Fatalities
09.17.70
Beaumount TX, USA, Refinery, Fire
Lighting struck slop oil tank
lack of intermediate diking let fire spread to other tanks
$6,500,000
11.11.70
Tulsa, OK, USA, Wellhead, Explosion
Experimental Test for Reservoir Perforation using liquid explosive
9 Fatalities
12.01.70
Gulf of Mexico, South Timbalier Block 26, Blowout, ExplosiodFire
2 drilling rigs conducting wireline operations at fixed jacket platform
4 Fatalities, Platform and two drilling rigs a total loss
12.05.70
Linden, NJ, USA, Refinery, ExplosionRire
Failure of hydrocracker unit reactor due to localized overheating
$27,173,000 loss
1971
01.11.71
English Channel, Natural Gas Tanker, ExplosionEire
Ship collided with another vessel
8 Fatalities, Tanker sank
01.21.71
Mediterranean Sea, Oil Tanker, Fire/Explosion
39 Fatalities
02.11.71
66
Handbook of Fire and Explosion Protection
Newark, NJ, USA, Chemical Plant, Explosions
Two Chemical plants demolished
4 Fatalities
02.26.71
Longview, TX, USA, Chemical Plant, ExplosionEire
Drain fitting failed at compressor
Vapor released and ignited from exhaust of engine driven compressor resulting in explosion.
4 Fatalities, $5,600,000 loss.
05.26.71
Bayport, TX, USA, Chemical Plant, ExplosionlFire
Explosion shortly after plant turnaround caused impact to incoming power and fire water system
$4,500,000 loss
10.13.71
Offshore Peru, Drilling Barge, ExplosiodFire
Blowout incident.
19 Fatalities
10.16.71
Gulf of Mexico, Eugene Island Block 2 15,Platform B, Blowout/Explosion/Fire
4 Relief wells drilled to extinguish fire.
Production platform lost.
1972
02.29.72
Delaware City DL, USA, Refinery, Fire
Hot Oil transfer line failure, lack of ESD capability
$6,002,000 loss.
03.30.72
Rio de Janeiro, Brazil, Refinery, ExplosionlFire
Drain valve of LPG tank left open forming vapor cloud, which exploded, Most of refinery damaged
37 fatalities, $4,800,000 Loss.
05.1 1.72
Atlantic Ocean, Oil tanker, Fire
Vessel collided with another in fog and fire erupted
83 fatalities, vessels total loss
08.14.72
Billings, MT, USA, Refinery, ExplosionlFire
Lack of adequate piping isolation during maintenance
1 Fatality, $5,000,000 loss
08.21.72
Atlantic Ocean, Oil Tanker, ExplosionEire
Vessel collided with another in fog and explosion occurred
50 Fatalities
10.25.72
Carteret NJ, USA, Barge, ExplosionEire
Oil barge undergoing loading operations
$5,000,000 loss
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
67
1973
0 1.06.73
Bayonne, NJ, USA, Refinery Fire
Leaking pump released fuel oil which was ignited by nearby welding and spread to other tanks.
$4,300,000 loss
02.10.73
Staten Island, NY, USA, LNG Storage Tank, ExplosiodFire
Tank was undergoing refurbishment for an internal tom lining
40 Fatalities, $14,000,000 loss
03.30.73
Hong Kong Harbor, Oil Tanker, Fire
Vessel collided with another and fire ensued
3 Fatalities
07.05,73
Kingman, AZ,USA, Railroad Propane tank, BLEVE
Leaking transfer valve ignited when struck while tightening
13 Fatalities
07.08.73
Tokuyama, Japan, Chemical Plant, ExplosionEire
Chemical process upset due to instrumentation failure caused flange failure
I fatality, $1 6,000,000 loss
07.13.73
Potchefstrwm, S. Africa, Chemical Plant, Explosion
Brittle failure of the dished end of a 50 ton horizontal pressure vessel released anhydrous ammonia vapors which caused
the explosion to occur.
I 8 Fatalities
08.24.73
St. Croix, VI, Refinery Fire
Pipeline weld failure
$10,500,000 loss
10.08.73
Goi, Japan, Chemical Plant, ExplosionEire
Operator error released vapors to open vessel under maintenance.
1 Fatality, $7,000,000 loss
1974
0 1.3 1.74
South China Sea, Champion 41, Blowout, Fire
Failure of subsea weUhead,jacket severely damaged
04.10.74
Philadelphia, PA, USA, Tanker, ExplosionEire
Incident occurred during unloading of crude oil.
$8,l09,000 loss
06.01.74
Flixborough, UK, Chemical Plant, Explosion
Failure of a temporary pipe installed two months before as a reactor bypass.
28 Fatalities, $1 80,000,000 loss
08.25.74
68
Handbook of Fire and Explosion Protection
Petal, MO, USA, Salt Dome Butane Storage, Explosion
Overfilling of storage well created vapor cloud.
1 1.11.74
Tokyo Bay, Japan, Gas Tanker, Explosion/Fire
Liquefied tanker vessel collided with freighter
33 Fatalities, Tanker sunk.
11.29.74
Beaumont, TX, USA, Chemical Plant, ExplosionFire
Failure of pump expansion joint inlet.
$13,300,000
1975
01.3 1.75
Marcus Hook, PA, USA, Tanker, ExplosiodFire
Tanker was rammed by a chemical tanker vessel which loss control.
$7,837,000 loss
02.10.75
Antwerp, Belgium, Chemical Plant, ExplosionEire
Failure of vent connection on suction side of a compressor.
6 Fatalities, $28,325,000 loss
03.16.75
Avo4 California, USA, Refinery, ImplosionEire
Operators increased pump out rate to vessel creating a vacuum and implosion. Loss of instnunentation caused a second
fire elsewhere in the facility to occur.
$10,374,000 loss
04.05.75
Iford, Essex, UK, Chemical Plant, Explosion
Leakage of a hydrogen into an oxygen drum caused an explosion to occur in an electrolysis plant, resulting in extensive
damage to the facility.
1 Fatality
08.04.75
Texas, USA, Chemical Plant, ExplosionFire
$1,500,000 loss
08.17.75
Philadelphia, PA, USA, Refinery, ExplosiodFire
Storage Tank Explosion
Tank overfilling caused high vapor release, ignition result from contacted with hot surface.
8 Fatalities, $13,000,000 loss
10.14.75
Avon, CA, USA, Refinery, Fire
Lack of inspection of plug on pump caused leakage, lack of ESD valve activation due to instrumentation failure.
$6,307,000 loss.
11.07.75
Beek, Netherlands, Chemical Plant, Explosion
Level controller allowed cold liquid to enter pipe causing metallurgical failure of 1.57 inch pipe connection to a feed
drum released vapors ignited by furnace
14 Fatalities, $22,892,000 loss
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
69
12.30.75
Pacific Ocean, Supertanker, Explosion
224,000 ton vessel loss after explosions occurred and vessel sunk.
30 Fatalities, Insurance claims of $27 million.
1976
05.24.76
Geuismar, LA, USA, Chemical Plant, ExplosiodFire
Loss of instrumentationcause chemical reaction upset and explosion within the reactor occurred.
$8,875,000
07.18.76
Big Spring, TX, USA, Refinery, ExplosiodFire
Tank bending by use of air igmted and spread within the refinery.
$6,715,000 loss
08.12.76
Chalmette, LA, USA, Refinery, Explosion
Explosion in 30 story refining tower
13 Fatalities
08.30.76
Plaquemine LA, USA, Refinery, ExplosiodFire
Internal vessel failure caused explosion in storage tank
$12,000,000 loss
12.17.76
Los Angeles Port, USA, Tanker, Explosion
70,000 d u t tanker refueling at time of incident, cargo tanks not inerted and no vapor recovery system installed. Ignition
believed from pump performing ballasting operation.
9 Fatalities, $12,000,000 loss.
02.24.77
Pacific Ocean, Tanker, ExplosionEire
Tanker structural failure
1 Fatality, 846 foot Tanker was a total loss and 30 million gallons of oil.
03.xx.77
Port Arthur, TX, USA, Refinery, Fire
Texaco, Inc.
03.xs.77
Fort Arthur, TX, USA, Refinery, Explosion/Fire
8 Fatalities
04.03.77
Umm Said, Qatar, Refinery, Fire
Massive metallurgical weld failure of liquid propane tank
$76,350,000 loss
05.11.77
Abqaiq, Saudi Arabia, Pipeline, Fire
Metallurgical failure of buried pipeline that spread into process area, lack of automatic plant process EIVs.
6 Fatalities, $54,000,000 loss and resulted 30% reduction in crude oil sales until facility replaced.
06.04.77
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Handbook of Fire and Explosion Protection
Abqaiq, Saudi Arabia, Pipeline, ExplosionEire
Failure of fuel gas line resulting in a vapor cloud
$10,600,000 loss
07.08.77
Pump station # 8, Alaska, USA, Pumphouse, ExplosionEire
Oil flow from valve not isolated during maintenance, ignited by turbine heat
1 Fatality, $39,610,000 loss
09.24.77
Romeoville, IL, USA, Refinery, ExplosionEire
Cone roof storage tank of diesel struck by lightning resulted in internal explosiodfire which spread to other tanks.
$8,000,000 loss
10.18.77
Palmyra, MO, USA, Chemical Plant, ExplosionlFire
Startup of plant resulted in a detonation occurring in the reactor
$16,100,000 loss
12.08.77
Logan Township,NJ. USA, Storage Tank, ExplosionEire
Rollins Environmental Services
5 Fatalities
12.08.77
Brindisi, Italy, Chemical Plant, ExplosiodFire
Gas released occurred and explosion and fires resulted.
$28.2 80,000
12.16.77
Atlantic Ocean, Cape of Good Hope, Tankers, Fire
Two crude oil supertankers (each 330,000 dwt.) collided and fire occurred
Fires extinguished and vessels salvaged.
1978
7
02.12.78
Waverly, TN, USA, Railroad Tank Car, ExplosionEireball
LPG tank car derailed, explosion occurring during propane transfer operations
12 Fatalities
04.13.78
Calument City, IL, USA, Chemical Plant, Fire
Reactor unit fue.
$12,575,000 loss
04.15.78
Abqaiq, Saudi Arabia, Production Facility, ExplosiodFire
Metallurgical failure of pipeline
$53,700,000 loss
05.30.78
Texas City, TX, USA, Refinery, ExplosionEire
Unidentified release in tank farm lead to storage tank fues and BLEVEs
7 Fatalities, $3 1,079,000 loss
72
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
71
10.03.78
Denver, CO, USA, Chemical Plant, Explosioflire
Following startup reboiler failed and gas released causing explosion to occur.
10.30.78
Piteti, Romania, Refinery, ExplosiodFire
Failure of piping releasing vapors and causing an explosion
1979
01.08.79
Bantry Bay, Ireland, Tanker, Explosioflire
Structural failure of 121,000 dwt. Crude oil tanker during incorrect ballasting led to a release of contents resulting in
explosions and fires.
50 fatalities, $20,566,000 loss
03.05.79
Gulf of Mexico, South Marsh Island, Block 281, Platform C, Blowout, Explosioflire
Unable to close drill stem safety valve or stand pipe valve, relief valve on mud pump released gas.
8 Fatalities, Estimated loss of $2,500,000
03.20.79
Linden, NJ, USA, Refinery, Explosioflire
Failure of a dead leg piping released vapors
$17,500,000
04.19.79
Port Neches, TX, USA, Tanker, Explosioflire
124,000dwt. crude oil tanker struck by lighting after unloading.
$32,000,000
06.03.79
Gulf of Mexico, Ixtoc Well, Wellhead, Blowout/Fire
07.19.79
Caribbean Ocean, Supertanker, Collisioflire
Two fully loaded crude oil supertankers collide
1 fatality, Loss estimated at $150 million
07.21.79
Texas City, TX, USA, Refinery, ExplosionlFire
Failure of piping elbow in process unit.
$24,000,000 loss
08.30.79
Good Hope, LA, USA, Barge, Fire
Cargo ship collided with barge rupturing butane storage that ignited
$10,500,000 loss
09.01.79
Deer Park, TX, USA, Refinery, ExplosionlFire
Lighting storm struck 70,000 dwt. distillate tanker causing internal hold explosions and a 80,000 barrel cone roof ethanol
tank which started on fire.
$68,000,000 loss
11.15.79
Ponce, PR, USA, Refinery, Fire
Pump failure released liquids which ignited.
72
Handbook of Fire and Explosion Protection
$10,000,000 loss
12.11.79
Ponce, PR, USA, Chemical Plant, ExplosionEire
Vessel failed causing explosion and fire., extensive damage to neighboring plant
$15,000,000 loss
12.11.79
Geelong, Australia, Refinery, Fire
Pump bearing failure released crude oil
$1 1,236,000 loss.
1980
01.17.80
Offshore Nigeria, Semi-submersible,Fire
Gas Fire
Estimated 180+ fatalities
01.20.80
Borger, TX, USA, Refinery, ExplosionEire
Pipe or vessel failure released vapor cloud
$36,000,000 loss
02.26.80
Brooks, AK, USA, Pipeline Compressor Station, ExplosionEire
Valve rupture causing rupture and jet fues which were fed fiorn next station 15 miles away.
$40,000,000 loss
03.24.80
Gulf of Mexico, High Island Block A-368, Platform A, Blowout, ExplosionlFire
BOP activated, diverter valve closed and hose ruptured
6 Fatalities, Platform total loss.
05.07.80
Deer Park, TX, USA, Refmery, Fire
Pump seal failure released liquids which ignited.
$29,000,000 loss
06.26.80
Sydney, Australia, Refinery, Explosioflire
hcident OcCuITed during startup of facility after a shutdown
07.23.80
Seadrift, TX, USA, Refinery, ExplosionEire
Instrumentation failure caused process upset initiating internal detonation releasing combustible liquids
$1 1,800,000 loss
08.21.80
Gulf of Mexico, Eugene Island 361A, Fire
20,000 dwt. gasoline tanker collided with unmarked recently installedjacket. Severe damage to vessel and jacket
08.30.80
Gulf of Mexico, Matagorda island, Block 669. Blowout, ExplosiodFire
Annular preventer failed, closed pipe rams, casing pipe failed at 7,200 psi.
5 Fatalities, $30,000,000 loss.
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
73
10.21.80
New Castle, DE, USA, Chemical Plant, ExplosiodFire
Release of flammablevapors from piping due to inadequate isolatiodmaintenance. Explosion impacted fire suppression
system.
$45,750,000 loss
12.20.80
Ft. McMurray, AK, USA, Oil Sands Plant, Fire
Possible hydrate formation in the compressor second stage discharge causing piping rupture due to blockage.
$9,000,000 loss
12.31.80
Corpus Christi, TX, USA, Refmery, Fire
Metallurgical failure of laminated reactor vessel released vapors.
$17,000,000 loss.
1981
02.1 1.81
Chicago Height, IL, USA, Chemical Plant, ExplosionEire
Improper operating procedure cause a chemical process upset resulting in a tank boilover and vapor release. Explosion
impacted fire suppression system capability.
$14,000,0000
08.20.8 1
Shuaiba, Kuwait, Refinery, Fire
Tank caught fire with spread to other tanks, cause unknown.
$50,000,000 loss
1982
01.20.82
Ft. McMurray, AK, USA, Oil Sand Plant, Fire
Lube oil fire at compressor.
$21,000,000 loss.
03.09.82
Philadelphia, PA, USA, Chemical Plant, ExplosionEire
Release of combustible chemical vapors to atmosphere during process upset. Explosion impacted capability of the fue
suppression system.
$25,000,000 loss.
03.3 1.82
Kashima, Japan, Refmery, Fire
Hydrogen embrittlementcaused piping failure
$13,800,000 loss
04.18.82
Edmonton, AK, USA, Chemical Plant, ExplosionEire
Piping failure at compressor due to vibration induced stress. Combustible gas detection system inoperability contributed
to loss.
$2 1,000,000 loss
08.19.82
Osaka, Japan, Chemical Plant, ExplosionEire
Process upset from power intenuption caused reactor explosion addition atmospheric release next day which resulted in
explosion.
$10,000,000 loss
74
Handbook of Fire and Explosion Protection
10.04.82
Freeport, TX, USA, Chemical Plant, ExplosiodFire
Oil filled transformer failed resulting in a fire which spread into the process plant.
$14,700,000 loss.
10.21.82
Gulf of Mexico, Eugene Island, Block 36 1, Platform A, Blowout, ExplosiodFire
Annular preventer leaked.
Drilling rig and quarters destroyed.
01.07.83
Newark, NJ, USA, Bulk Plant, ExplosiodFire
tank overfilled spilling liquid and causing vapor cloud to form. Explosion caused damage to other properties and
adjacent tanks.
$35,000,000 loss.
04.07.83
Avon, CA, USA, Refinery, Fire
Rupture of a sluny line in a FCC unit which ignited.
$48,950,000 loss
04.14.83
Bontang, India, LNG Plant, RuptureRire
Relief header isolation valve left closed during plant startup caused a heat exchanger to rupture.
$50,000,000 loss
08.30.83
Miford Haven, Wales, UK, Refinery, Fire
Floating roof tank seal area ignited from flare carbon particles from 350 foot away
$15,000,000 loss
10.13.83
Gulf of Mexico, East Breaks Block 610, Platform A, Blowout, Fire
Diverter line ruptured.
Extensive damage to two drilling rig and platform
10.20.83
Gulf of Mexico, Eugene Island Block 10, Blowout Fire
Safety valve leaked
Extensive damage to rig.
1984
-
02.25.84
Sa0 Paulo, Brazil, Pipeline, Fire
Pipeline ruptured in the vicinity of a shanty town releasing 700 tons of gasoline.
508 Fatalities
03.08.84
Kerala, India, Refinery, ExplosiodFire
Leakmg heat exchangers released vapors which ignited.
$12,000,000 loss
07.23$4
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
75
Romeoville, IL, USA, Refinery, ExplosiodFireBLEVEs
Circumferencial weld crack leaded propane which ignited resulting in a vapor cloud. Resulting explosion and fires
severely damaged facility.
$127,000,000 loss
08 15.84
Ft. McMurray, Alberta, Canada, Refinery, Fire
Erosion failure of a pipeline released liquids near autoignitiontemperature. Vapors spread and ignited causing severe
damage to the facility
$76,000,000 loss
08.16.84
South Atlantic, Offshore Brazil, Enchova 1, Blowout, ExplosiodFire
Gas release during drilling operations.
42 Fatalities
09.30.84
Basile, LA, USA, Gas Plant, Explosion/Fire
Failure of a drain line connection allowed vapor release and explosion to occur.
$30,000,000 loss
09.14.84
Gulf of Mexico, Green Canyon, Block 69, Blowout, Fire
Reopened BOP and released gas
4 Fatalities, $15,000,000 loss.
11.19.84
Mexico City, Mexico, LPG Plant, Explosion/Fire/BLEVE
8 inch line ruptured releasing contents that ignited and spread to process area. Firewater system was impacted from initial
explosion.
550 Fatalities, $19,900,000 loss
12.13.84
Las Pedras, Venezuela, Refinery, fire
Line failure due to vibration induced metal fatigue released hot oil under high pressure which ignited and spread to other
portions the plant.
$62,076,000 loss
01.23.85
Wood River, IL, USA, Refinery, ExplosiodFire
Dead line containing propane froze rupturing pipe which released hydrocarbons
$29,400,000 loss
05.19.85
Priola, Italy, Petrochemical Plant, FireBLEVE
Flange failure at column released liquids which were immediately igtuted
$65,000,000 loss
11.05.85
Mount Belvieu, TX, USA, NGL Terminal, ExplosiodFire
Contractor cut live liquid propane releasing contents which were feed by salt dome reservoir. Explosion and fire impacted
fire pumps.
$40,000,000 loss
12.21.85
Naples, Italy, Products Terminal, Fire
76
Handbook of Fire and Explosion Protection
Tank overfilled producing a vapor cloud producing an explosion setting other tanks on fire and causing extensive
damage.
$42,000,000 loss
1986
06.15.86
Pascagoula, MS, USA, Chemical Plant, ExplosionEire
Suspected leaking valves released vapors that were ignited
$10,000,000 loss
10.06.86
North Sea, West Vanguard, Blowout, Explosioflire
Drilling rig encountered shallow gas and riser system had leakage, no BOP installed and diverter system could not
withstand blowout forces
1 Fatality, Rig totally destroyed
08.15.87
Ras Tanura, Saudi Arabia, Refinery, Fire
Propane released possibly at flange at relief valve, after facility power failure, Ignition caused by nearby vehicle
$60,000,000 loss
11.14.87
Pampa, TX, USA, Chemical Plant, ExplosionEire
Explosion at reactor severely damage facility and impacted firewater supply system
$215,300,000 loss
12.21.87
Gulf of Mexico, Eugene Island Block 190, Helicopter Crash into Platform, Fire
Helicopter flew into leg of platform and crashed on landing pad
14 Fatalities, Helicopter destroyed, platform damaged
01.02.88.
Floreffe, PA, USA, Bulk Plant, Tank Rupture
48 year old relocated tank ruptured during initial filling operation.
$13,300,000 loss
04.24.88
South Atlantic offshore Brazil, Enchova Central, Blowout, Fire
Workover of a gas injection well gas release occurred, BOP failed, sparks from falling pipe ignited gas.
Platform total loss
05.05.88
Norco, LA, USA, Refinery, ExplosionEire
Corrosion failure of a carbon steel elbow released propane vapors that exploded in the FCC unit that impacted all utilities
and firewater system
$300,000,000 loss
06.08.88
Port Arthur, TX, USA, Refinery, ExplosionEire
Failure of a propane line resulted in vapor cloud release in the tank farm that ignited and impacted other product transfer
lines.
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
77
$16,000,000 loss
07.06.88
North Sea, Block 15/17, Piper Alpha, ExplosionlFire
Condensate leakage caused explosion which impacted safety systems and spread incident
167 Fatalities, total facility loss estimated at $1,000,000,000.
09.08.88
Rafness, Norway, Chemical Plant, Explosioflire
Pump seal leakage released vapor cloud
$11,000,000 loss
09.22.88
North Sea, Ocean Odyssey, Blowout, ExplosionEire
Drilling Rig encountered gas and choke line developed leak causing vapor cloud, explosion and tire
1 Fatality, Rig totally destroyed
09.23.88
Gulf of Mexico, Main Pass Block 133, Fire
Unmanned platform, pump packing leakage
Estimated loss at $5,500,000
10.25.88
Pulua Merlimau, Singapore, Bulk Storage Plant, Fire
Submerged floating roof tank of gasoline caught tire while foam was being applied. Fire spread to 3 other tanks.
$12,000,000 loss
1989
01.xx.89
North Sea, Drilling Rig, Blowout
Treasure Saga
Relief well drilled to control blowout
$250,000,000 loss
03.07.89
Antwerp, Belgium, Chemical Plant, ExplosionEire
A low cycle fatigue crack in a seam weld of a pipe lead to the release of ethylene oxide with ignited completely destroying
the distillation section of the plant.
$77,000,000 loss
03.19.89
Gulf of Mexico, South Pass 60B,, Fire
Maintenance activities cut into line still containing hydrocarbon gases
7 fatalities, $50,000,000 loss.
06.03.89
Ural Mountains, U.S.S.R., Pipeline, Explosion
LPG pipeline leak exploded impacting two passenger trains
500+ Fatalities.
06.07.89
Morris, IL, USA, Refinery; ExplosiodFire
78
Handbook of Fire and Explosion Protection
09.05.89
Marinez, CA, USA, Refinery, Fire
Weld failure on hydrogen line caused high pressurejet fire onto the support of a 100 foot reactor which failed and spread
incident.
$90,000,000 loss.
10.23.89
Pasadena, TX, USA, Chemical Plant, ExplosiodFire
Ethylene leakage from reactor loop ignited causing an explosion severely damaging the facility. Blast estimated to be
equivalent to 10 tons of TNT.
23 Fatalities, Greater than $750,000,000 loss.
12.19.89
Offshore Las Palmas, canary Islands, Tanker, Explosion
Explosion opened tanker hull and spilled 19 million gallons
12.24.89
Baton Rouge, LA, USA, Refinery, ExplosiodFire
Pipeline failure released combustible gases resulting in UCVE which impacted utility services, pipelines, and started
other fires.
Several Fatalities, $43,000,000 loss
1990
04.01.90
Warren, PA, USA, Refinery, Explosioflire
LPG released by operator during water draining operation of debutanizer system
$25,000,000 loss
07.05.90
Channelview, TX, USA, Wastewater Plant, ExplosionEire
Failure of oxygen analyzer for storage tank allowed combustible vapors to accumulate and ignite
17 Fatalities, $12,000,000 loss
07.10.90
Rio de Janeiro, Brazil, Refinery, Explosion
Boiler rupture occurred in the FCC unit.
$10,000,000 loss
07.19.90
Cincinnati, OH, USA, Chemical Plant, Explosion
Rupture disk released combustible vapors from reactor after it overpressured due to cleaning vapor evolution from
residual heat in the vessel. Vapors ignited causing an explosion which severely damaged the facilities.
$23,000,000
11.03.90
Chalmette, IN, USA, Refinery, Explosioflire
Heat exchanger shell failure released gas causing a explosion to occur and process fires to start.
$15,000,000 loss
11.06.90
Naothane, India, Pipeline, Explosion
Leak in a gas pipeline resulted in explosion which damaged a nearby gas treatment and compressor facility
$22,000,000 loss
11.25.90
Denver, CO, USA, Bulk Storage Facility, Fire
fuel leak at fuel pump ignited by motor
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
79
$30,000,000 loss
11.30.90
Ras Tanura, Saudi Arabia, Refinery, Fire
Chemical induced corrosion failure of main crude feedline caused a fire to occw at the fractionation columns for kerosene
and diesel.
1 Fatality, $30,000,000 loss
1991
03.03.91
Lake Charles, LA, USA, Refinery, ExplosionEire
Vessel rupture following turnaround in which a drain valve left open allowing water to enter vessel
$23,000,000 loss
03.11.91
Coatzacoalcos,Mexico, Chemical Plant, Explosioflire
Piping rupture caused explosion and fire.
$150,000,000 loss
03.12.91
Seadrift, TX, USA, Chemical Plant, Explosioflires
Plant explosion spread incident and impacted fue protection systems.
$80,000,000 loss
04.13.9 1
Sweeny, TX, USA, Chemical Plant, Explosion
Reactor explosion
$50,000,000 loss
05.01.91
Sertlngton, LA, USA,, Chemical Plant, FireExplosion
Small fire started explosions destroying the facility
$105,000,000 loss.
06.17.91
Charleston, SC, USA, Chemical Plant, Explosion/Fire
Startup followingmaintenance produced process upset in reactor, water found in process materials, reflux line blocked
resulted in overheating in reactor.
$10,000,000 loss
06.20.9 1
Dhaka, Bangladesh, Chemical Plant, Explosion
Metallurgical failure of pipe weld
$70,000,000 loss
08.21.91
Melbourne, Australia, Chemical Storage, ExplosionEire
Lightning struck storage tank, cause explosion and fire which spread to other tanks. Fire suppression system impacted
during explosion losing its capability.
$24,000,000 loss
09.07.91
Haifa, Israel, Chemical Plant, Fire
Short circuit suspected as cause
$22,000,000 loss
80
Handbook of Fire and Explosion Protection
1992
04.xx.92
Brenham, TX, USA, Gas Storage, Explosion/Fire
Numerous tecbnical and human failures allowed gas to release from a salt dome storage facility. Lack of fail safe devices
contributed to the explosion of the resulting vapor cloud.
3 Fatalities, $9,000,000 loss.
03.25.93
Lake Maracaibo, Venezuela, Offshore Platform, WCE/Fire
Failure of intercoolerduring startup of gas compressor, control room destroyed
10 Fatalities, $100,000,000 loss
OS. 18.93
Bilbao, Spain, Refinery, Explosion
Explosion occurred in chimney connected to a conversion unit
$8,000.000 loss
05.23.93
Munich, Germany, Chemical Plant, ExplosionlFire
Explosion during cleaning of peroxide installation of pilot plant
2 Fatalities, $3,200,000,000 loss
06.03.93
Sicily, Italy, Refinery ExplosionlFire
Pipe fracture in feedline to furnace
7 Fatalities, Plant closed indefinitely.
06.08.93
St. Therese, Canada, Petrochemical Plant, Fire
Plant completely destroyed by fire.
08.02.93
Baton Rouge, LA, USA, Refinery, Explosioflire
Incorrect metallurgicalvalve leaked coke resulting in an explosion under the coker unit.
3 Fatalities
08.27.93
Elyria, Ohio, USA, Chemical Plant, Explosion/Fire
Overheated pump caused explosion in catalyst blending building
$s,ooo,ooo loss
09.28.93
Caracas, Venezuela, Pipeline, Fire
Pipeline punctured during excavation work
51 Fatalities
1994
01.07.94
Mississippi River, USA, Drilling Barge, Ruptured Pipeline
Drill barge spudded into gas pipeline
1 Fatality
04.20.94
Offshore Egypt, Offshore Production Platform, Fire
Ship collided with unmanned platform which ignited.
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
81
Platform total loss, est. 150 days loss production.
05.27.94
Belpre, Ohio, USA, Chemical Plant, ExplosiodFire
Explosion at storage tanks for styrene started major fire.
3 Fatalities, major damages to the facility
06.21.94
Bristol, Pennsylvania, USA, Chemical Plant, ExplosionlFire
Uncontrolled reaction in chemical mixing
$5,000,000 loss
06.26.94
El Tablazo, Lake Maracaibo, Venezuela, Chemical Plant ExplosiodFire
Fuel leak during truck transfer operations caused storagevessels to BLEVE
07.24.94
Milford Haven, UK, Refinery, Fire
power disruption caused plant upset causing liquid overloading
$100,000,000 loss
07.26.94
Inchon, Seoul, South Korea, Chemical Plant, ExplosionlFire
explosion occurred in an overheated furnace
5 Fatalities, Major damages incurred.
Overall it can be demonstrated that the majority of these incidents werer the result of small hydrocarbon
leakages 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 surface
eventually reached by the release. Most fire incidents (estimated at 90%) are extinguished by manual efforts
using portable fire extinguishers. Where the he1 supply is unable to be isolated the incident grows in
proportions becoming uncontrollable.
Offshore Oil Production and Exploration (USA)
The U. S . Minerals Management Service (MMS) periodically publishes a listing of all the incidents occurring
offshore in U.S. waters. This list provides a chronological listing of all the reported incidents from 1958 to
the 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. It
reveals that the worst fire or explosion events within the last ten years have been from blowouts, while the
highest loss of life is from helicopter crashes. Most fires occur from small integrity leakages and are
typically suppressed by human intervention using hand held portable fire extinguishers. The releases are
usually ignited by local equipment containing hot surfaces or from hot exhaust gases off a combustion
engine. 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 fatalities were the result of 29
separate incidents (4%). 43 explosions (8% of the total), were also identified as having occurred during this
period. There was no damage, injuries or environmental pollution in 154 (28%) of the reported incidents.
Worst Fatal Incidents
The five worst fatal incidents in this analysis are stated below. They are mostly associated with
82
Handbook of Fire and Explosion Protection
1. Helicopter struck leg of an offshore rig - 14 fatalities, (Forest Oil - 1987).
2. Cut into Pipeline not hydrocarbon free, 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 suffered catastrophic damage - 5 fatalities, (Cities Service - 1980)
Worst Property Losses
The worst property losses suffered during this period are highlighted below.
associated with blowout incidents.
Almost all are
1. Blowout, total platform destroyed, (Penzoil- 1980).
2. Blowout, Jackup Rig suffered catastrophic damage, (Cities Service -198 1)
3. Blowout, Major damage to rig and submersible barge, (Placid -1981).
4. Blowout, Jackup rig and derrick destroyed, (Shell - 1982).
5 . Blowout, Drilling rig and quarters destroyed, (Chevron - 1982).
6. Blowout, Extensive damage to two rigs and platform (Union - 1993).
7. Blowout, Damage to Drilling rig (Conoco - 1984)
8.Cut into Pipeline not hydrocarbon free, Platform destroyed, (Arc0 - 1989)
Although the ultimate cause of a blowout is human error to control the hydraulic wellbore pressure
with drilling mud, in some cases the failure of the BOP to control the situation also contributed to the
incident. The causes of the BOP failures are analyzed below:
BOP Failures
1. Gas diverter valve improperly set and diverter hose ruptured.
2. Annular preventer failed, pipe rams closed, casing ruptured at 49,642 kPa (7,200 psi.) below the
BOP.
3. Fill up l i e opened to release gas, closed pipe ram, unable to close fill up line, well blew out
through the swivel neck.
4. Kelly hose burst during well control procedure, Kelly cock and in-line safety valve could not be
closed.
5 . Annular preventer leaked, after well "kicked".
6. Diverter line ruptured, aAer 35 minutes of gas diversion.
7. Drilling string safety valve leaked at stem.
8. Diverter line leaked.
Immediate Cause of Death
Sixty fatalities occurred in the Gulf of Mexico related to offshore oil and gas production during 1980
to 1990. The immediate cause of death has been identified in Table 6.
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
Blowout
Explosion
Perforating Gun
Inadvertent Activation
Burns
Drowning
Unknown (during major
fire or explosion incident
30.0%
2
18
5
3
2
1
3
2
2
10
3.3%
3.3%
16.7%
5
5
83
8.4%
5 .O%
,
Table 6
Immediate Cause of Death (Gulf of Mexico, 1980-1990)
Helicopter and blowout incidents account for the major portion of incidents (63%). It could be inferred
these incidents account for a higher loss of life than other incidents due to the higher concentration of
personnel involved in these specific activities.
The helicopter incidents account for the highest amount of fatalities for any single cause of death. They
were the result of two separate incidents in which each helicopter struck a facility. These incidents where
not the result of mechanical failure of the helicopter.
There were 13 blowout incidents recorded during the ten year period. They were generally listed as the
result of equipment failures.
84
Handbook of Fire and Explosion Protection
Cause of Incidents
The major cause of most Gulf of Mexico offshore incidents was the result of hydrocarbon gas or fluid
releases (approixmately 32%). The next major cause was equipment failure (mechnical or electrical 2 1%)
and then hot work activities (12%). A tubulation ofthe a11 the causes is provided in Table 7.
Number of
Cause
Percentage
Incidents
Gas release (leakage, venting, etc.)
Hot work
Mechanical failure
Fluid release (leakage, spillage, etc.)
Electrical short/insulationfailure
Engine or gearbox oil leak
Rupture
Process upset
Blowouts
Exhaust gases inproximity of combustible material
Lightning
Open flame use
Engine or compressor backfire
Vibration induced failure
Improper use of or incorrect type of cleaning fluid
Mechanical impact (friction)
Improper procedure/operation
120
66
53
51
49
20
14
13
13
13
11
10
10
8
7
6
6
22.2%
12.2%
9.8%
Unknown
Total
40
7.4%
100%
539
Table 7
Cause of Incidents, Gulf of Mexico
9.5%
9.1%
3.7%
2.6%
2.4%
2.4%
2.4%
2.0%
1.8%
1.8%
1.5%
1.3%
1.1%
1.1%
Historical Survey of Fire and Explosions in the Hydrocarbon Industries
85
Summarv
The New York Times reports this is one of the deadliest periods for the American petrochemical industry’s
history: “Alarm(ing) company executives, the 12 worst explosions killed 79 people, injured 833, and caused
roughly $2 billion in damage”. In the U.S.A.over 34,500 industrial chemical accidents were reported during
the period of 1988-1992, nearly one every hour. Over 2,000 of these resulted in injuries, evacuations or
fatalities. Some 40 percent occurred concentrated in just two percent of the counties of the U.S.,primarily
in California, Texas and Louisiana, home to most and some of the largest petroleum and chemical facilities in
the 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 or
transportation means are all potential candidates where a minor mishap may result in coniderable life loss.
Where the equipment involved in 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. Ignition
sources generally tend to be associated with local hot surfaces. Large hydrocarbon incidents are the direct
result of the inability to isolate fuel supplies from the subject incipient event. Where large volumes of
hydrocarbons are processed or handled, such as from pipelines ,wellheads or the process arrangments, any
escalation in the incident may result in higher levels of damage or injuries than may have otherwise occurred.
86
Handbook of Fire and Explosion Protection
Bibliography
1.
American Petroleum Institute (API), Summary of Occupational Injuries, Illnesses, and Fatalities in the Petroleum
Industry, (Annual Report), API, Washington, D.C.
2.
Giddens, P. H., Early Davs of Oil, Princeton University Press, Gloucester, MA, 1964
3.
Department of Energy, The Public Inauirv into the Piper Alpha Disaster, HMSO, London, U.K., 1990.
4.
Ferrara, G. M., The Disaster File: The 1970s, Facts on File, New York, NY, 1979.
5.
Institute of Chemical Engineers, "Articles and Case Histories from Process Industries Throughout the World", Loss
Prevention Bulletin, 075, June 1987, Institute of 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 Prevention in the Process Industries, Volume 1, Butterworths, London, U.K., 1980.
8. Marsh & McClennan Protection Consultants (M&M PC), LarPe Property Damaye Losses in the HvdrocarbonChemical Industries. A Thirty Year Review, 14th Edition, M&M PC, 1992.
9.
Minerals Management Service (MMS), Accidents Associated with Oil and Gas Ouerations. Outer Continental Shelf
1956 - 1990, U.S. Department ofthe Interior, Herndon, VA, 1992.
10. National Fire Protection Association (NFPA), "Fire Journal", NFPA, Quincy, MA.
11. Sedgwick Energy, "Loss Control Newsletter", Sedgwick Energy Limited, London, U.K., Issue 1, 1994.
12. Singerman, P., An American Hero. 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 7
Risk Analysis
Everyone in the engineering profession is familiar with Murphy's Law, "If anything can go wrong, it will.". I
also prefer to remember the extended version which states, "If a series of events can go wrong, it will do so
in the worst possible sequence". Risk analysis is a sort of Murphy's Law review in which events are
analyzed to see the destructive nature that they might produce.
Risk analysis is a term that is applied to a number of analytical techniques used to evaluate the level of
hazardous occurrences. Technically, risk analysis is a tool by which the probability and consequences of
accidental events are evaluated for hazard implications. These techniques can be either qualitative or
quantitative.
Risk analysis can be broken down into four main steps:
(1) Identifjl accident occurrences.
( 2 ) Estimate the frequency of the occurrences.
(3) Determine the consequences of each occurrence.
(4) Develop risk estimates associated with the frequency and consequence.
Before safety measures are applied to a facility, it is prudent to identifjl and evaluate the possible hazards
that may evolve before spending considerable amounts on protection that may not be needed or overlooking
requirements for protection measures that are needed. The first step in fire protection engineering should
therefore be to always identifj. the major risks at a facility. When conducting these analyses it is prudent
only to only consider credible events. Farfetched or outlandish event considerations (e.g., a meteor striking
the facility) are not necessary or practical and lead to a less cost effective approach.
Safety Flow Chart
Sometimes it is easiest to prepare a general flowchart that identifies events which may occur at a facility
during an incident. This flowchart can identifjl possible avenues the event may lead to and the protection
measures available to mitigate and protect the facility. It will also highlight deficiencies. The use of a
ffowchart helps the understanding of events by personal unfamiliar with petroleum risk and safety measures.
It portrays a step by step scenarios that is easy to follow or explain. Preparation of in-depth risk probability
analysis can also use the flowchart as the basis of the event trees or failure modes and effects. Figure 3
provides a generic example of a typical hydrocarbon process facility Safety Flowchart. API Recommended
Practice RP 14C provides an example of a Safety Flowchart for an offshore production facility.
87
88
Handbook of Fire and Explosion Protection
"0
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SAFETY FLOW CHART
Figure 3
Risk Analysis
89
Risk Identification and Evaluation
The basic methodology adopted for the formal risk evaluation in the petroleum and
related industries, both for existing facilities and new projects, normally contain the
following steps:
1. Definition of the Facility - A general description of the facility is identified. Input and outputs
to the facility are noted, production, manning, basic process control system (BPCS), ESD, fire
protection philosophy, assumptions, hazardous material compositions, etc.
2. Identification of Hazards - A listing of the processes and storage of combustible materials and
the process chemistry that can precipitate an incident.
3. Development of Accidental Events
4. Frequency Analysis
occur.
- Identified scenarios that can cause an accident to occur.
- An examination of the probabilities or possibilities of and accident to
5. Consequence Modeling - A description of the possible incidents that can occur.
6. Impact Assessment - The development of the severity of the incident in terms of injuries,
damage, environmental impact, business interuption and public reaction.
7. Summation of Risk - The combination of severity and probability estimates an incident to
occur.
8. Effect of Safety Measures An evaluation of the mitigation effects of layers of protective
systems of different integrities, on the effects or prevention of an incident.
9. Review Against Risk Acceptance Criteria - The comparison of an incident risk which is
supplemented by the selected safety measures to achieve the requirements for company safety
levels.
During the process hazards identification and definition phase of a project design, a basic process control
system (BPCS) strategy is normally developed in conjunction with heat and material balances for the
process.
Both qualitative and quantitative evaluation techniques may be used to consider the risk associated with a
facility. The level and magnitude of these reviews should be commensurate with the risk that the facility
represents. High value, critical facilities or employee vulnerability may warrant high review levels. While
unmanned "off-the-shelf', low hazard facilities may suffice with only a checklist review. Specialized studies
are performed when in-depth analysis is needed to determine the cost benefit of a safety feature or to l l l y
demonstrate the intended safety feature has the capability to fully meet prescribed safety requirements.
Generally offshore facilities and major process plants onshore represent considerable capital investment and
have a high number of severe hazards associated with them (blowouts, ship collisions, line and vessel
ruptures, etc.). They normally cannot be easily evaluated with a simple safety checklist approach. Some
level of "quantifiable evaluation" reviews are usually prepared to demonstrate that the risk of these facilities
is 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 for
the entire facility. Where such points are identified special emphasis should be to ensure that events leading
up to such circumstances are prevented or eliminated.
The following brief descriptions are typical analyses undertaken.
90
Handbook of Fire and Explosion Protection
A. Qualitative Reviews
Qualitative reviews are studies base on the generic experience of personnel and do not involve
mathematical estimations. Overall these reviews are essentially checklist reviews in which
questions or process parameters are used to prompt discussions of the process design and
operations and possible accident scenarios.
Checklist or Worksheet - A standardized listing which identifies common protection
features required for typical facilities is 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 causes
and effects. Recommendations or 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 or
components under examination. Risks are normally expressed in a qualitative numerical
series (e.g., 1 to 5).
-
HAZOP A formal systematic critical safety study where deviations of design intent of
each component are formulated and analyzed from a standardized list. Risks are typically
expressed in a qualitative numerical series (e.g., 1 to 5) relative to one another.
Relative Ranking Techniques (DOW and MOND Hazard Indices) - This method
assigns relative penalites and awards points for hazards and protection measures
respectivesly in a checklist accounting form. The penalties and award points are combined
into an index which is an indication of the relative ranking of the plant risk.
B. Quantitative Reviews
Quantitative reviews are mathematical estimations that rely upon historical evidence or estimates of
failures to predict the occurrence of an event. These reviews are sometimes referred to as a
Quantitative Risk Assessment (QRA).
Event Trees (ET) - A mathematical logic model that mathematically and graphically
portrays the combination of events and circumstances in an accident sequence, expressed
in an annual estimation.
Fault Trees (FT) - A mathematical logic model that mathematically and graphically
portrays the combination of failures that can lead to a specific main failure or accident of
interest, expressed in an annual estimation.
Failure Modes and Effects Analysis (FMEA) - A systematic, tabular method of
evaluating the causes and effects of known types of component failures, expressed in an
annual estimation.
C. Specialized Supplemental Studies
Specialized studies are investigations that attempt to veri@ the ability of a facility to perform
effectively during an emergency, generally by mathematical estimates. They are used extensively to
justifl the necessity or deletion of a safety system. The most common studies are listed below
however every facility is unique and may require it’s own investigative requirements (e.g., for an
offshore facility - the potential for ship collisions). For example, for a simple unmanned wellhead
Risk Analysis
91
platforms, located in the warm shallow waters (e.g., Gulf of Mexico), these analyses are relatively
simple to accomplish. Conversly, where manned integrated production and separation platforms
are located in deep cold waters (e.g., the North Sea), these analyses tend to be most extensive.
Leak Estimation - A mathematical model of the probability and amount of potential
hydrocarbon releases that may occur from selected processes or locations.
Depressurization and Blowdown Capabilities - A mathematical calculation of the
system sizing and amount of time needed to obtain gas depressurization or liquid
blowdown according to the company’s philosophy of plant protection and industry
standards (i.e., API RP 521).
Combustible Vapor Dispersion (CVD) - A mathematical estimation of the probability,
location, and distance a release of combustible vapors will exist until dilution will naturally
reduce the concentration to below the LEL or no longer considered ignitable (typically
defined as 50% of the LEL).
Explosion Overpressure - A mathematical estimation of the amount of explosive
overpressure that may be expected from an incident. It is portrayed as overpressure radii
from the point of initiation until the overpressure magnitudes are of no concern, i.e., less
than 0.02 bar (3.0 psio). Evaluations perforned for enclosed areas will also estimate the
amount of overpressure venting capability available.
Survivability of Safety Systems - An estimation of the ability for safety systems to
maintain integrity from the effects of explosions and fires. (Safety systems may include
ESD, depressurization, fire protection - active and passive, communication, emergency
power, evacuation mechanism, etc.).
Firewater Reliability - A mathematical model of the ability of the firewater system to
provide firewater upon demand as required by the design of the system without a
component failure, e.g., a Mean Time Between Failure (MTBF) analysis.
Fire and Smoke Models - A mathematical estimation model depicting the duration and
extent of heat, flame and smoke that may be generated from the ignition of a hydrocarbon
release. 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 time
estimates to complete an effective removal of all personnel from an immediately
endangered location or facility.
Fatality Accident Rates (FAR) or Potential Loss of Life (PLL) - A mathematical
estimation of the level of fatalities that may occur at a location or facility due to the nature
of work being performed and protection measures provided, may be calculated at an
annual rate or for the life of the project.
Human Reliability Analysis (HRA) or Human Error Analysis - A reliability analysis
that estimates the potential for human errors to occur due to the work environment,
human-machine interfaces, and required operational tasks.
These special analyses are prepared from the quantifiable risk analysis and a total risk scenario can be
presented which depicts the estimated incident effects. An example is shown in Table 8.
92
Handbook of Fire and Explosion Protection
Additional specialized studies are sometimes specified for offshore facilities. These may include the
following, depending on the type of facility under review:
Helicopter, ship and underwater vessel collisions.
Possibility of failing objects (from crane or drilling operations).
Extreme weather conditions.
Reliability or vulnerability of stability, buoyancy, and propulsion systems (for floating
installations or vessels).
Survivability of the Temporary Safe Refuge (TSR).
Large Gas Le& A Module
No eacalahon
Escalahon to B Module
AGLO3
I
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I
I
4,7, in, 12
13, 14, 15,
000163
1
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I l9kgis
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I
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on3
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TABLE 8
Example of Quantifiable Accident Scenario Summary
yes
Yes
15-21
15-21
'
,
Risk Analysis
93
Risk Acceptance Criteria
A numerical level of risk acceptance is specified where quantitative evaluation of the probabilities and
consequences of an accidental event have been performed. The documentation may also be used by senior
management as a justification for budgetary decisions. The values of risk for many industries and daily
personal activities have published and are readily available for comparison. This comparison has formed the
basis of risk acceptance levels 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 parameters
The 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). For
purposes of consistency and familiarity all quantifiable risks are normally specified as annually Where value
analysis is applied for cost comparisons of protection options, a lifetime risk figure is normally used.
It has been commonly acknowledged in the hydrocarbon industry the average risk to an individual at a
facility should generally not exceed a value in the order of 1 x
per year. The facility risk is the total
frequency of an accidental event for each main type of incident. Similarly for most oil and gas facilities, the
facility risk should generally not exceed a value in the order of 1 x
per year.
Where risks are higher that normally acceptable and all reasonable mitigation measures have been examined
to find out value and practicality, the principal of risk as low as reasonably practical applies. Where the
available risk protection measures have been exhausted and the risk level is still higher that the accepted
numerical value, the risk would be considered "AsLow As Reasonably Practical" (ALARP).
In the petroleum industry, insurance agents will typically estimate the maximum losses a facility may suffer
by performing a calculation of a potential vapor cloud explosion at the facility (where this is applicable). By
examining the high loss explosion potentials, a maximum risk level can be determined and therefore
insurance coverages that are necessary will be defined.
Relevant and Accurate Data Resources
Risk evaluation methods should use data that is relevant to the facility under examination. Where other data
is used an explanation should be provided to substantiate it's use, otherwise inaccurate assumptions will
prevail in the analysis. Where highly accurate data is available, the findings of a quantitative risk evaluation
will generally only be within an order of magnitude of 10 of the actual risk levels since some uncertainty of
the data to the actual application will always exist.
All quantifiable evaluation documentation should be prepared so that it would conform to the nature of a
facility "Safety Case" format which may be required for submittal to governmental agencies at a later date.
Cost estimates can be prepared to perform any portion or all the risk evaluation for a particular facility or
installation based on the manpower necessary for each portion of the analysis and the size and complexity of
the facility.
94
Handbook of Fire and Explosion Protection
Bibliography
1.
American Petroleum Institute (API), RP 14C. Recommended Practice for Analvsis. Desim. Installation and Testing
of Basic Surface Safetv Svstems for Offshore Production Platforms, Fourth Edition, API, washington, D.C., 1986.
2.
American Petroleum Institute (API), RP 145, Recommended Practice for Hazard Analvsis for Offshore Platforms,
First Edition, API, Washington, D.C., 1994.
3.
American Petroleum Institute (API), RP 75. Recommended Practices for DeveloDment of a Safety and
Environmental Management Promam for Outer Continental Shelf (OCS) Operations and Facilities, API,
Washington, D.C., 1993.
4.
American Petroleum Institute (API), RP 750. Management of Process Hazards, First Edition, API, Washington,
D.C., 1990.
5.
Block, A., Murphy's Law, Book Two, More Reasons Why Things Go Wronp!, Price/Stem/Sloan, Los Angeles, CA,
1980.
6.
Center for Chemical Process Safety, (CCPS), Guidelines for Chemical Process Quantitative Risk Analysis, AIChE,
New York, NY, 1989.
7.
Center for Chemical Process Safety, (CCPS), Guidelines for Hazard Evaluation Procedures, Second Edition, AIChE,
New York, NY, 1992.
8.
Center for Chemical Process Safety, (CCPS), Guidelines for Process Eauiument Reliabilitv Data, AIChE, New
York, NY, 1989.
9.
Des Norske Veritas (DNV), OREDA Offshore Reliabilitv Data, Second Edition, DNV, Hovik, Norway, 1992.
10 Dow Chemical Company, Fire and Exulosion Index Hazard Classification Guide, Sixth Edition, American Institute
of Chemical Engineers (AIChE), New York, NY, 1987.
11 Dupont Chemicals, Dupont Safety and Fire Protection Guideline: Use of Process Risk Calculations in Hazards
Management, Dupont, Wilmington, DL, 1981.
12 Health and Safety Executive (HSE). A Guide to the Offshore Installations (Safety Case) Regulations 1992, HMSO,
London, U.K., 1992.
13. Industrial Risk Insurers, IM.8.0.1.1, Oil and Chemical Prouerties - Loss Potential Estimation Guide, Hartford, CT.
14. Lees, F. P., Loss Prevention the Process Industries, 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 Chemical
Industries, Noyes Publications, Park Ridge, NJ, 1994.
Chapter 8
Segregation, Separation and Arrangement
The most inherent safety feature that can be provided at oil, gas and related facilities is the segregation,
separation and arrangement of equipment. Some publications emphasize that separation is the prime safety
feature that can be employed at any facility. This is true from the viewpoint of preventing exposure to
personnel or facilities outside the area of concern. However this becomes somewhat impractical for the
large 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 high
risk locations. Duplicate process trains, high numbers of vessels, multiple storage tanks and numerous
incoming and outgoing pipelines limit the possibilities of remotely locating every single high hazard process
risk from each other. Additionally operational efficiencies would be affected and construction costs would
increase. The more practical approach is combine the features of segregation, separation and arrangement in
a fashion that leads to more organized and operationally acceptable process facility. This represents the
lowest practical risk but still avoids crowding.
Potential future expansion should be assessed and space provided for known and unknown needs. Logical
and orderly expansion can only be made if provision at the time of original facility installation. The master
plan should be frozen and only altered if a risk analysis of the changes is acceptable.
Surface runoff should be considered coincident with equipment layout. If surface runoff from one area goes
directly to another area the feature of separation has be lost.
Segregation
Segregation is the grouping of similar hydrocarbon processes into the same major area. This allows an
economical approach to achieve the maximum protection to all the high risk units while lessor protection is
given to low risk equipment. The segregated high hazard areas can then also be further separated as far as
necessary from other areas of the facility and the public. Some offshore facilities that do not have the luxury
of large amounts of space, generally have to use segregation as the prime means of protection supplemented
by 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 process
areas. The major segregation areas would be provided with maximum spacing distances while the
subdivided areas are provided with lessor amounts depending on the protection afforded the area and
individual risk of the units. Most petroleum and chemical processes are arranged in a systematic fashion
from reception of raw materials, manufacturing and output to finished products. This arrangement is
complementary to the needs of segregation for the purposes of loss prevention. Layout cost controls for
95
96
Handbook of Fire and Explosion Protection
continuos flow operations also require that the distance personnel, information move is minimized. The
exact technical process selected for a hydrocarbon process will also ultimately influence the general layout.
Some of the latest designs for platforms in the North Sea has segregated the process (i.e., separation, gas
compression, etc.) facilities hrthest from accommodations and utility support. Drilling modules are sited
between the process and utility support modules based on the level of relatively lower risk drilling in a
defined reservoir represents versus possible process incidents.
Safety systems should not be segregated together. Each safety system should be diversified as much as
possible to avoid the possibility of a single point failure. A prime example is the firewater supply which
should be pumped into a facility firemain at several separate and remote locations.
Tank farm areas are usually segregated based on the service and type of tank for economic reasons, besides
segregatingby levels of risk.
Separation
There has much analysis in the petroleum industry as what is the prudent spacing table to use in the layout of
an onshore facility. Attempts have even been made to compare the spacing tables used by individuals
companies. This would provide a consolidated table the entire industry could apply. Although such an idea
is admirable, there are several obstacles in achieving such a goal.
First, the original insurance spacing tables (i.e., OIL, 01.4, IRI,etc.), although commonly used in some
sectors of the industry, have been formulated based on a few selective historical incidents and do not appear
to be scientifically based on the current methods of determining the explosive or fire damage that can be
released. They cannot account for all the possible design quantities of production processes They may
provide too much or too little spacing in some instances for the risk involved. Second, some facilities were
constructed before the spacing tables were widely applied or were modified without too much consideration
to a spacing table. Therefore any relocation of facilities under an "industry" spacing table will be very costly
to retroactively apply or enforce. Some petroleum companies may also consider that the values listed in an
"insurance industry" table are too conservative. On the basis of their own analysis, they may desire to apply
lessor values. A survey of most industry spacing charts indicates they are not all similar. An obvious
disparity exists between the operating company spacing charts and the recommended distances of the
insurance industry, Ref Table 7. Also the mandate for any facility project engineer is to save space and
materials to achieve a less costly and easily built facility. He will therefore always desire to congest or
compress the area for shorter piping runs, fewer pipe racks, etc., and be at odds for the requirements of loss
prevention.
The ideal solution is to perform a risk analysis for each item in a facility to determine the probable maximum
fire and explosive range the location may produce. The calculations and expense to accomplish such a task
today 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 expedient
solution. 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 a
spacing chart requires.
The first task in applying a spacing table to a facility is to ensure it corresponds to the philosophy of
protection adopted by the company. Where limited space is available to provide the required spacing, an
examination of the equivalent fire and explosive barriers or active fire suppression system should be
confirmed. This analysis should be accepted by the company as part of the design risk analysis.
In establishing process spacing philosophy or if used, the ratings of fire and explosion barriers (as may be the
case offshore), fire suppression effectiveness, a number of principle factors should be considered. These
Segregation, Separation and Arrangement
97
include
1 . Fire, explosion, rind toxic health hazards of the processes and of the materials being handled
2 The volume of material contained in the process, how it is isolated or removed during an
emergency.
3. The strength of process vessel to maintain integrity during exposure to a hydrocarbon fire
4. The manning and location of employees in the facility.
5 . The concentration and valve of equipment in a particular area.
6. The criticality of the equipment to continued business operations.
7. Possible fire exposures to the facility from adjacent hazards.
8. The effectiveness of fire protection measures, both passive and active.
9. The possibility of the flare to release liquids or unignited combustible vapors.
To achieve these principals the following features are usually adopted:
1. Individual process units should be spaced so that an incident in one will have minimal impact on
the other.
2. Utilities such as steam, electricity, fire water should be separated protected by the effects of an
incident so that they may be continuously maintained. Where large facilities or critical installations
are present the supply of these services from two or more remote locations should be evaluated.
3. The most critical important single equipment for continued plant operation or highest valued unit
should 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 the
facility.
5 . Consideration should be given to use the general prevailing environmental conditions such as wind
and terrain elevation to best advantage for spill and vapor removal. Facility equipment should not
be located where they would be highly vulnerable to a major spill or vapor release.
6. Consideration should be given to the adjacent exposures or other utilities which may transverse the
site, i.e. pipelines, railroads, highways, power lines, aircraft, shipping routes (if offshore), etc.
7. Adequate arrangements for emergency service access to all portions of the facility for fire fighting,
rescue, evacuation means.
8. Placement of the flare at the most remote downwind location of the facility
Manned Facilities and Locations
The primary design consideration at any oil, gas 01- related facility should be the protection of employees and
the general public from the effects of an explosion or fire. In all cases highly populated occupancies should
be located as far as practical upwind of the process oI storage areas. Where this cannot be practically
98
Handbook of Fire and Explosion Protection
achieve the manned location should be provided with fire and blast resistant features commensurate with the
exposure it faces.
The siting of manned locations should be considered the highest safety priority in the layout of a
hydrocarbon facility. The primary locations where high levels of personnel may be accumulated relatively
close to the hazards of hydrocarbon operations are control rooms and offshore accommodations.
Control rooms and offshore accommodations are also the most vulnerable fixed locations where a high
fatality possibility can occur at hydrocarbon facility. In both of these installations a high number of
employees may be present during most periods. Consequentially, an adequate risk analysis for both
locations should be accomplished as part of any facility design scope. There is really no overwhelming
reason why both need to be near operating processes other than cost impacts and convenience to operating
personnel. Historical evidence has dramatically shown that control rooms, and in the case of offshore
platforms - accommodations, can be highly vulnerable to the effects of explosions, fires, and smoke if not
adequately protected.
The ideal situation for offshore facility is to locate the accommodation on a separate installation jacket that is
spaced 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 increasing
personnel safety and providing a cost benefit.
The latest designs for onshore installations cater for a centralized control room, well distanced from the
operating facility with sub control areas as part of a distributed control system (DCS). The sub-control
areas are closer to the processes but contain fewer personnel and process control systems for the overall
plant, so the overall risk level for the facility from a major incident is lowered. The outlying control
buildings (sometimes referred to as PIBs or SIHs) still need to be sited against impacts from explosions and
fires.
Storage Facilities - Tanks
Tank farm areas require additional consideration for spacing not only between other process hazards but
from other storage tanks. Minimum shell to shell spacings for storage tanks are provided in NFPA 30. It
also includes requirements for minimum spacings from other exposures such as property lines and buildings.
The provisions for spacings are based on the commodity stored, pressure, temperature, and fire protection
measures afforded to each tank. Each parameter adjusts the minimum requirements. For large tanks and
those containing crude oil, heated oil, slop oil or emulsion breading materials additional spacing
requirements should be considered. These include the following:
Where tanks exceed 45.7 meters (150 ft.) in diameter, the spacing between tanks should be a
minimum 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 such
that 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 emulsion
breaking 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. The
slope of the natural topography can be used to assist in the drainage requirements for a diked area and
minimized the accumulation of spilled liquids near a storage tank. Diversion dikes or curbing can be used to
divert spillage so 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
99
they should be arranged so they are perpendicular to the prevailing wind instead of parallel. This allows
smoke and heat from a fire to dissipate with respect to impacts to other storage facilities.
The location of storage tanks to adjoining property or exposures on adjacent exposures should be treated the
same as would be case with exposure to or from a refinery process, however the added consideration of
public exposure should not be overlooked.
Process Units
Units operating at high pressures, at high or low (refrigerated) temperatures,
having a large inventory of flammable fluid above its atmospheric boiling point,
or handling of toxic materials are more hazardous than other process units.
Historical evidence of the petroleum industry indicates that pumps, compressors,
heaters are a common high volume source of leakage and should be as far as
practical from ignition sources and other critical equipment
Flares
The general principles for the location of flares should be governed by the following
0
They should be located as close as practical to the process units being served. This allows the shortest
and most direct route for the disposal gas header and will also avoid passage through other risk areas.
0
Flare should be located as remote from the facility and property line due to their inherent hazardous
features. They should be well away from high hazard areas or public occupied areas. A location
perpendicular to the prevailing wind direction remofe from the major sources of vapor releases and
process or storage facilities is preferred. The chosen location should not allow liquids which may be
ejected from the flare system to expose the facility. This principal should apply even if a liquid knock
out feature is incorporated.
0
Where more than one flare is provided, the location of each should be mainly influenced by operational
requirements, but the need for maintenance and independent operation should also be considered.
Critical Utilities and Support Systems
During a fire or explosion incident the primarily utilities may be effected in not adequately protected. These
utilities may provide critical services to emergency systems that should be preserved. The most common
services are mentioned below:
Firewater Pumps
Several catastrophic fire incidents in the petroleum industry have been the result of the facility
firewater pumps being directly affected by the initial effects of the incident. The cause of these
impacts has been mainly due to the siting of the fire pumps in vulnerable locations without adequate
protection measures from the probable incident and the unavailability or provision of other backup
water sources. A single point failure analysis of firewater distribution systems is an effective
analysis that can be performed to identify where design deficiencies may exist. For all high risk
locations, fire water supplies should be available from several remotely located sources that are
totally independent of each and utility systems which are required for support.
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Handbook of Fire and Explosion Protection
Power Supplies
Power is necessary to operate all emergency control devices. Where facility power sources or
distribution networks are unreliable or vulnerable self contained sources should be provided to
emergency systems and equipment. Unless protected power, control and instrumentation cabling
will 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 possible
fire or explosion exposures, simple and direct backup power supplies are usually provided for
higher reliability factors during an incident. These include spring return fail safe valves, local air
reservoirs, etc. The capacity of the selected backup sources should be based on the WCCE
Communication Facilities
Communications plays a vital role in alerting and notifjing both in facility personnel and outside
emergency agencies that a major incident has occurred. Communication systems should not be
arranged so a single point failure exists. Of primary concern is the provision of a backup source of
power and a remote backup activation and signaling post.
Buoyancv and Propulsion Capability
Floating vessels for offshore operations offer reduced installation costs
but also present additional vulnerability factors. All floating structures
must ensure buoyancy integrity is maintained otherwise the vessel may
sink with catastrophic results. Similarly propulsion are provided at some
installations to provided position stability. All major vessels are required
by insurance requirements and most marine regulations to maintain
buoyancy systems and loss of position stability will impact ongoing
operations. Both of these systems can therefore be considered critical
support systems and must be evaluated for risk and loss control measures
either thorough duplication and protection measures or a combination of
both.
Air Intakes
Air intakes to heating and ventilation systems, air compressors for process, instrument and
breathing air, and to prime movers for gas compressors, power generation and pumps should be
located as far as practical from contamination by dust, toxic and flammable materials release
sources. They should not be located in electrically classified areas. If close to possible vapor
releases (as confirmed by dispersion analyses( they should be fitted with toxic or combustible gas
aktection clevices to' wam bi posslbl'e aii intaltts naiai-as ana snutdowh ana' isolate tne incoming air
ductwork and fans.
Fire Zones
Petroleum facilities located both onshore and offshore can be identified into "fire zones". These are areas
where a fire can be expected to occur and be contained provided all safety and process emergency systems
are operable in addition the arrangement of the facility should be kept to the original design intent for
segregation and spacing factors that would prevent to spread of an incident. They are essentially based on
the area a liquid spillage might encompass or highly probable high pressure gas release fires. In this fashion
they are similar to electrical area classification drawing which outline areas vapors may be present but are
generally smaller.
The fire zone drawings serve as an aid in determining which areas need special protection measures such as
adequate fireproofing, firewater protection systems, drainage facilities, etc.
Segregation, Separation and Arrangement
101
Arrangement
Arrangement means the orientation and assemblage of the equipment in a facility. By far the highest
concern is the arrangement vessels, columns, tanks and process trains containing combustible materials of
large capacity, especially at high pressures or temperatures. To meet the needs of loss control but still
maintain efficient operations high risk plots are arranged so they are never completely enclosed by other
processes or risks. A fire break, usually a road and sometimes pipe racks or open drainage system are
provided for both economical process pipe routings, access convenience and as a convenient method for
separation 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 high
technology process control and instrumentation.
Tanks should be grouped so that no more than two rows of tanks are provided within diked areas separated
by roads to ensure fire fighting access is available. Large tanks within a common diked area should be
provided with intermediate spill dikes or drainage channels between the tanks, as an intermediate level of
protection against spill spread. When a small number of small tanks are located together the level of major
impacts is less and therefor the financial risk is lower. In these cases it is acceptable not to provide full or
intermediate dikes.
A high pressure process or storage vessel should never be "pointed" at manned or critical facilities or other
high inventory systems for concerns of a B L E W of the container with the ends of the vessel rocketing
towards the vulnerable location. As a hrther inherent safety enhancement, spheroid separation vessels may
be used in some instances instead of horizontal pressure vessels (bullets). This reduces the possibility of a
BLEVE incident directed towards other exposures.
Pipe racks normally divide a facility into major areas. For economy and process efficiencies the piping
arrangement is typically a central corridor in any facility. On either side of this pipe corridor or rack the
process units are provided buy its nature divides the facility into units or process areas.
Facility Access and Egress
The main access and egress to a facility preferably should be from the upwind side, with secondary points at
cross wind locations. These locations should also be at a relatively higher elevations that the process areas
so that possible spillages will not hinder supplemental emergency aid measures from outside the facility. As
a minimum two access point should be provided to each facility.
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Handbook of Fire and Explosion Protection
Table 9
Comparison of Industry and Insurance Spacing Tables
*Average of Six Integrated Petroleum Operating Companies
Segregation, Separation and Arrangement
103
Bibliography
1.
American Petroleum Institute (API), Recommended Practice 752. Management of Hazards Associated with
Location of Process Plant Buildings, Draft #6, API, Washington, D.C., 1994.
2.
Bland, W. F. and Davidson, R. L., Petroleum Processinv Handbook, MrGraw-Hill, New York, NY, 1967.
3.
Factory Mutual (FM), FM 7-44. Spacing of Facilities in Outdoor Chemical Plants, FM, Norwood, MA
4.
Factory Mutual (FM), FM 7-458. Process Control Houses and Other Structures Subiect to External Explosion
Damage, FM, Norwood, MA.
5.
Industrial Risk Insures (IRI), IM.2. Section 2.5.2.Plant Lavout and Spacing for Oil and Chemical Plants, Tables 1
and 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.
Government Printing Office, Washington, D.C. 1975.
Chapter 9
Grading, Containment, and Drainage Systems
Drainage and surface liquid containment systems are usually thought of as a supplemental process system
that has little input into the risk analysis of a facility. Without adequate drainage capabilities spilled
hydrocarbon liquids have no avenue of dissipation except to be consumed by any potential fire or explosion.
Liquid disposal systems are also a potential source of hazard because of the possibilities of the formation and
distribution of explosive gas-air mixtures. Liquid drainage systems therefore play a key role in the
avoidance, reduction and prevention of hydrocarbon materials that may result in fire and explosion incidents.
Drainage philosophies and design features should be examined at the beginning of a facility design.
There are several drainage mechanisms are employed at petroleum and related facilities - surface runoff or
grading, spill containment (diking), gravity sewers (oily water and sanitary) and pressurized sewer mains,
and lift station collection sumps.
Drainage Systems
The topography, climatic conditions and arrangements for effluent treatment will influence the design
of drainage systems for the control of oil spills resulting from the failure of equipment, overflows or
operating errors. Additionally the amount, spacing and arrangement of hydrocarbon process
equipment will also influence the features of a drainage system.
An adequate drainage system should be provided for all locations where a large amount of
hydrocarbon liquids has the possibility of release and may accumulate within the terms of the risk
analysis frequency levels. Normal practice is to ensure adequate drainage capability exists at all
pumps, tanks, vessels, columns, etc., supplemented by area surface runoff or general area catch
basins. Sewer systems are normally gravity flow for either sanitary requirements or oily surface
water disposal. Where insuflicient elevation is available for the main header, lift stations are installed
with a forced pressure outlet header to a disposal or treatment system.
Process and Area Drainage
In the process unit areas, drainage arrangements should ensure that spills will not accumulate or pass
under vessels, piping or cable trays. Primary drainage should be provided by an underground oily
water sewer system (OWS) connected to area catch basins. An OWS system normally consist of
surface runoff to collection troughs and area catch basins or process drain collection receptacles
connected to underground header. The system mainly consist of an underground pipe network of
branch lines connected to a main header through sealed connections usually catch basins and
104
Grading, Containment, and Drainage Systems
105
manholes. Fluids from the main header are routed to a central collection point from which they are
transferred to an oil and water separation facility.
A prime safety feature of the OWS is that it does not transmit combustible vapors or liquids from one
process collection area to another area where it may cause a hazard or be
unexpected Since fires, and even explosive flame fronts can spread
inside sewer piping by flaming hydrocarbon vapors on top of firewater or
surface runoff, sewer systems should be designed with sealed (water
traps) to avoid carrying a burning liquid fiom one area to another. The
sealing liquid should always be water, otherwise combustible vapors are
likely to be released both to the atmosphere and in the drain line fiom the
hydrocarbon sealing liquid. Once a drainage receptacle has be used for
hydrocarbon disposal, either from surface drainage or process activities
it should be thoroughly flushed with water to reestablish the water seal.
Line segments that are sealed should be provided with a vent to allow any trapped gases to be
relieved, otherwise hydrostatic vapor lock will occur which will prevent incoming liquids from
draining into the system. Such vents should be located on the high end of the line segment so all the
vapors will be released. Vent outlets should be located where they do not pose a hazard to the
hydrocarbon processes or other utilities. Manhole cover plates in process areas should be sealed. If
the manhole has any openings it may allow gas to escape out of it instead of the sewer vent for
dissipation. Overall the sewer grade should be away fiom shops, or occupied areas, to reduce the
possibility of flammable liquids or vapors emitting from sewer openings located in nonclassified areas.
Many incidents have been recorded of process system leaks entering sanitary sewers resulting in
hydrocarbon vapor emissions from toilets that have ignited. Sanitary sewers should be provided
which are entirely separate from oily water sewer (OWS) systems. Similarly process venting or
blowdown systems should not connect to the sewer systems.
Common practice and a general guide is to prevent combustible vapors from transmitting from one
process area to another process area, generally 15.2 meters (50 ft.) or more away. Usually unsealed
receptacles, such as drain funnels, tundishes, drain boxes, are routed to the nearest local sealed catch
basin and then into the oily water sewer main. The unsealed receptacles are only allowed in the same
process area equipment where if vapors where released from an adjacent unsealed receptacle it would
be "immaterial" due to the proximity to where the liquid is being drained and would normally emit
vapors.
In some cases a closed drainage system can be used which drains process components directly into
the oily water sewer. This has the advantage of avoiding releases of vapors in any instance, but
assurance must be obtained that back pressure from one drainage location will not backfeed liquids
into another drain point when two valves are open simultaneously or other drainage valves can
contain any backpressure on them from other drainage sources.
Surface Drainage
Provision should be made to eliminate the chance of liquid spreading to other processes or offsite
locations, even if failure of the underground gravity drainage network occurs. The design philosophy
employed 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 equipment
as possible. These provisions usually consist of surface grading to perimeter runoff collection points,
impounding areas or oily water separation ponds supplemented by directional curbing or diking. The
typical surface runoff gradient employed is approximately one percent.
Process areas are normally provided with hard wearing surfaces, such as concrete or asphalt, which
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Handbook of Fire and Explosion Protection
provides for surface runoff if a suitable directional grade is established. The surface runoff should be
arranged so that flow from broken lines or equipment is directed away from other facility processes
or critical facilities. Surface drainage can be enhanced with low elevation diversion diking and
drainage channels. Although these enhancements are used assist in diverting surface liquids to a
remote impounding area, slopped paving is the preferred method for spill collection. Paving is
preferred to untreated ground or crushed stone since flammable liquids may drain into a permeable
ground cover and accumulate on the surface of the ground water table. During fire incidents they
might float back to the exposed ground surface, forming additional fire hazards. Permeable ground
cover will also allow ground water pollution to occur if hydrocarbon liquids 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 used
where they will not interfere with the use of the area, i.e., crane access, maintenance activities, etc.
They should be designed to minimize erosion, and if excessive velocities are encountered they should
be paved. No more than 5 d s (1 5 Ws) velocity should be allowed in paved surface runoff channels
or troughs.
Rainfall, firewater flow and process spillage should all be analyzed when design drainage systems.
Process spillage should be the most credible maximum vessel leakage or rupture. A rule of thumb in
estimating the spread of spills can be made by using the approximation that for an unconfined and
level spill, 3.8 liters (1 gal.), of even a vicious liquid, will cover approximately 1.86 sq. meters (20 sq.
fi.). In most cases, firewater flowrates dominate the design capacity of drainage arrangements.
For small facilities (e.g., production separation), the normal practice in the design of surface runoff is
to provide a centerline slope from the process area. This would also include provisions to segregate
vessels and pumps from the impact of liquid spills. The runoff is collected into catch basins or
collected 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 serves as a means to
separate on fire risk fiom another. Catch basins should be located away fiom equipment and critical
structural supports since they may produce pools of liquids during spillage incidents. Drainage
trenches should not be located under pipe racks or other sources where if ignited they would produce
a line of fire under critical equipment. The number of catch basins provided to any process area
should also be limited, typically to two to prevent the number of "collection pools". A typical
approach is to limit drainage areas to a maximum of 232.2 sq. meters (2,500 sq. R.) and size the
catch basins in this area for a maximum flow based on process spillage or fire water flows. All catch
basins should be properly (water) sealed to prevent the spread combustible liquids or vapors to other
areas that are not involved in the incident. Underground piping should also be buried where it can be
accessible should future problems require it to be uncovered. Generally such piping is not routed
under monolithic or slab concrete foundations.
Surface drainage should be adequate to drain the total volume of water that can be used during fire
fighting activities or storm water, whichever is greatest.
Open Channels and Trenches
Surface runoff that is not collected in the oily water sewer, should be routed to perimeter or
intermediate collection channels or trenches that route the fluids to a remote impounding area.
Surface drainage routes, troughs, channels, collection areas should not pass under or be located near
cable trays, pipe racks, vessels, process equipment or close to fire water lines where if ignited would
cause produce impacts to critical equipment or release other hydrocarbon holdup sources. Open
trenches should not be used in a process area. Instead, an underground oily water sewer with surface
catch basins should be provided. Historical evidence indicates may process fires have spread when
surfice 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
107
Typical practice is also to locate open channels or trenches away from process areas containing heavy
vapors, so they cannot collect and spread to other areas.
Spill Containment
Where surface drainage cannot be employed for safe removal of liquids, diking may be employed to
prevent the endangering of property or equipment. Dikes are primarily used to contain tank pumpovers, bottom leakages, piping failures and limit the spread of fluids during a fire incident - both
hydrocarbons and firewater runoff Accumulation of spilled liquids can be limited in quantity or
removed before the retention areas are overflowed through drainage lines with control valves located
outside the diked area. Experience has shown that, under normal conditions, it is unlikely that the
capacity of an entire dike volume will be M y used or needed. Consequentially a dike area drainage
mechanism should normally be kept closed until an incident warrants their opening.
Dikes should be arranged so liquids will flow (with minimum exposure to pipeways) to a low point
within the enclosure remote from the equipment producing the spillage. Accumulated liquid can
them be easily drained or pumped into a liquid removal system.
Pumping units are usually enclosed with a curbing to contain small leakages, in which a catch basin is
provided in the remote corner of the curbing enclosure. The grade within this enclosure is directed
away from the pumping unit and towards the drainage sewer connection. As an added safety feature
an overflow trough from the curbed area is sometimes provided which connects remote drainage
channels, to divert large spillages away 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 connections
to the storage tank and release the contents of /the tank. Any gutter encircling the tank should be
located 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 an
impervious surface that is will collect liquids towards a drainage collection point.
Dike walls should not hinder fire fighting efforts or generally impede the dispersion of vapors from
spilled liquids. Most industry standards require containment dikes to be constructed of an average
interior height of 1.8 meters (6 fi.) or less. Where additional provisions have been made for
emergency access and egress from the diked area allowances to this requirement can be made. It
should be noted that an oil wave may occur in a diked area if the tank fails catastrophically during a
boilover or slopover event. 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 leakages
endangering all the tanks.
108
Handbook of Fire and Explosion Protection
Table 10, Comparison of Dike Design Requirements
Grading, Containment, and Drainage Systems
* Tank/vessel rupture or WCCE estimated leakage rate (may require rainfall provisions)
* * Provided for incidental spillages
Table II
Drainage Requirements and Capacity Analysis
109
110
Handbook of Fire and Explosion Protection
Bibliography
1.
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.
2.
American Society of Mechanical Engineers (ASME), A1 12.1.2. Air Gaps in Plumbing Svstems, ASME, 1991.
3.
American Society of Civil Engineers (ASCE), ASCE Standard 7-93. Minimum Design Loads for Buildings and
Other Structures, ASCE, New York, NY, 1993.
4.
Institute of Electrical and Electronics Engineers, Inc. (IEEE), IEEE 979, Guide for Substation Fire Protection, IEEE,
Piscataway, NJ, 1984.
5. Institute of Electrical and Electronics Engineers, Inc. (IEEE), IEEE 980. Guide for Containment and Control of Oil
Spills in Substations, IEEE, Piscataway, NJ, 1987.
6.
Industrial Risk Insures (IRI), IM.2. Section 2.5.3. Fire Protection Water & Spill Control for Outdoor Oil &
Chemical Plants, IN, Hartford, CT, 1992.
7.
National Fire Protection Association (NFPA), NFPA 15, Water Spray Fixed Svstems for Fire Protection, Appendix
4-6.2, NFPA, Quincy, MA, 1990.
8.
National Fire Protection Association (NFPA), NFPA 30. Flammable and Combustible Liauids Code, NFPA,
Quincy, MA, 1993.
9.
National Fire Protection Association (NFPA), NFPA 328. Recommended Practice for the Control of Flammable and
Combustible Liauids and Gases in Manholes. Sewers and Similar Underground Structures, NFPA, Quincy, MA,
1992.
Chapter 10
Process Controls
Process control plays an important role in how a plant process upset can be controlled and subsequent
emergency actions executed. Without adequate and reliable process controls, an unexpected process
occurrence cannot be monitored, controlled and eliminated. Process controls can range from simple manual
actions to computer logic controllers, remote fiom the required action point, with supplemental
instrumentation feedback systems. These systems should be designed such as to minimize the need to
activate secondary safety devices. The process principles, margins allowed, reliability and the means of
process control are mechanisms of inherent safety that will influence the risk level at a facility.
Human Observation
The most utilized and reliable process control in the petroleum and related industries is human observation
and surveillance. Local pressure and level gages along with control room instrumentation are provided so
that human observation and actions can occur to maintain the proper process conditions. First stage process
alanns are provided to alert operators to conditions that they may not have already noticed. Typically when
secondary alarm stages are reached, computer control systems employed to automatically implement
remedial actions to the process.
Instrumentation and Automation
Automation and control of processing equipment by highly sophisticated computer control systems is
becoming the standard at most hydrocarbon facilities. Automatic control provides for closer control of the
process operating conditions and therefore increased efficiencies. Increased efficiencies allow higher
production outputs. Automation is also thought to reduce operator manpower requirements. However
other personnel are still needed to inspect and maintain the automatic controlling system. All process
control systems should be monitored by operators and have the capability for backup control or override
commands by 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 cover
measurements, displays, alarms, control loops, protective systems, interlocks, special valves (e.g., PSV,
111
112
Handbook of Fire and Explosion Protection
check valves, EIVs, etc.), failure modes, and controller mechanisms (i.e., PLC's). The reliability of the
system should also be specified. If a process feature demonstrates that a major consequence has the
possibility of occurring, (as identified by the risk analysis, i.e., HAZOP, What-If Reviews), additional
independent 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. Some
commonly referred to systems are identified as high integrity protective systems (HIPS) or triple modular
redundant (TMR) .
The alarm systems should have a philosophy that 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 into
consideration, e.g., the distinction between alarms and status signals versus operator action that needs to be
initiated.
Control loops should have a fail safe function as much as practical limits will allow
Most electronic technology systems use digital electronics in conjunction with microcomputer technology to
allow the instrumentation user to calibrate and troubleshoot the instrumentation from either a local or
remote location. This capability is commonly referred to as "Smart" electronic technology.
Electronic Process Control
The state of the art in process control for hydrocarbon process systems is computer microprocessors or
commonly referred to as PLCs (ProgrammableLogic Controllers). A distributed digital instrumentation and
control system supplements the overall process management system (PLC) design. Programmable electronic
systems are commonly used for most control systems, safety functions, supervisory control and data
acquisition systems (SCADA). These systems may consist of a distribute control system (DCS),
programmable logic controllers (PLC), personal computers and remoter terminals, or combinations over a
communication network.
A distributed control system @CS) caters for centralized control but allows sectionalized local control
centers with a clearly defined hierarchy. Operator interaction is provided with real-time video display panels
instead of traditional metering instruments and status lights. The DCS fimctionally and physically segregates
the process controls for systems or areas at separate locations or areas within a building. This segregation
prevents damages or downtime to a portion of a the system affecting the entire facility or operation, just as
the physical components are isolated and segregated for risk protection measures. Typically segregated
DCS 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 be
chosen carefully and similar risk analyses chosen since impacts to their operations are just as critical to the
process as a main control room would be.
When the electronic control is specified the following features should be critically examined:
1. The availability of the system to function upon demand.
2 . The selection of compatible components.
3 . Failure modes of the components in the systems and impact on system control
4. Design and reliability of utility supplies.
5 . Control and integrity of software commands.
6 . Capabilities for remote input, monitoring and control.
Process Controls
113
Changes in display status should signifl changes in functional status rather than simply indicate a control has
been activated, for example, a lighted VALVE CLOSED indicator should signifl that the valve is actually
closed, not that the VALVE CLOSED control has been activated.
There is no standard or specification within the industry which specifies the dual redundancy for PLCs used
for process control functions. The requirement for control system redundancy is primarily a function of the
desired availability or demand of the process control system. Most control sytem availability percentages are
in the range of 99 to 99.9%. Depending on the type of PLC system configuration defined, availability
generally improves in relation to the amount of redundancy added to the various system components, but
does not necessarily improve system reliability.
Most published literature cites the MTBF for a PLC central processor between 10,000 and 20,000 hours
(Le. 1.2 to 2.4 yrs.), the MTBF of Input and Output(V0) interfaces is between 30,000 and 50,000 hours and
the MTBF of Input and Output (VO) hardware is between 70,000 and 150,000 hours. For the worst case
MTBF 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 configuration were provided with
the CPU in a running backup mode, using single VOs, the MTBF would almost double, but the overall
system availability improves only slightly to 99.88%. Completly dual PLCs with dual I/O and CPUs in a
1 0 0 2 or 2 0 0 2 voting arrangement are seldom used for normal process control systems but are instead used
for certain safety systems where availability, failsafe and fault tolerant attributes are desired. Complete dual
PLCs tend to be more complex and maintenance intensive.
Process System Instrumentation and Alarms
Suggested control and instrumentation for the management of process components are shown in API Rp
14C which is still relatively the standard within the industry. All process control systems are usually
reviewed by a Process Hazard Analysis, which will deem if the provided mechanism area is adequate to
prevent a catastrophic incident.
For high risk processes, dual level alarms level instrumentation (e.g., highhigh, low/low, etc.) and automatic
process control (PLC, DCS, etc.) and shutdown, that is backed up by human supervision should always be
considered. Where alarm indications are used they should provided such that an acknowledgment is
required by an operator. Alarm indications should be arranged so their is a hierarchy of information and
alarm status so that control operator do not become inundated with a multitude of alarm indications. If such
an arrangement exists, he may not be able to immediately discriminate critical alarms from non-critical
alarms. Operators sometimes have to make decisions under highly stresshl situations with conflicting
information. It is therefore imperative to keep major alarms for catastrophic emergencies as simple and
direct as possible.
Any critical safety related control function should be protected from impairment from an accidental event
that would render the device unable to fulfill its function.
Transfer and Storage Controls
The highest process concerns for storage locations and transfer operations is the possibility of a tank or
vessel rupture or implosion and overflow,
These usually occur when during dynamic operations are
ongoing.
All tanks should be furnished with level gaging instrumentation. Preferably the optimum design is one that
provides an alarm before high overflow levels are reached and also shut off fill lines when the optimum
fill 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 Protection
the event of line rupture or segmental depressuring. Storage vessels or tanks recieving products from
pipelines or automatic transfer systems are normally required to be fitted with high level alarms which may
trip shutoff devices.
Burner Management Systems
Fired heaters are extensively used in the oil and gas industry to process the raw materials into usable
products 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 fires
due to malfunctions and deterioration of the heat transfer tubes. Microprocessor computers are used to
manage and control the burner system.
Process Controls
115
Bibliography
1.
American Petroleum Institute (API), RP 14F. Recommended Practice for Design and Installation of Electrical
Systems for Offshore Production Platforms, Third Edition, API, Washington, D.C. 1991.
2.
American Petroleum Institute, (API) RP 540, Electrical Installations in Petroleum Processing Plants, Third Edition,
API, Washington, D.C., 1991.
3. American Petroleum Institute (API), RP 55 1. Process Management Instrumentation, First Edition, API, Washington,
D.C. 1993.
4.
Center for Chemical Process Safety (CCPS), Guidelines for Design for Process Safety, American Institute of
Chemical Engineers (AIChE), New York, NY, 1993.
5.
Fisher, T. G., Alarm and Interlock Systems, Instrument Society of America, (ISA), Durham, NC, 1984.
Chapter 11
Emergency Shutdown
Emergency shutdown capability is to be provided all petroleum facilities be it manual, remotely operated
or automatic. Inherent safety practices rely on emergency shutdown capability as a prime facet in achieving
a low risk facility. Without adequate shutdown capabilities a facility cannot be controlled during a major
incident.
Definition and Objective
An Emergency Shutdown (ESD) system is a method to rapidly cease the operation of the process and isolate
it from incoming or going connections or flows to reduce the likelihood of an unwanted event from
occurring, continuing, or escalating. The aim of an ESD system is to protect personnel, afford protection to
the facility, and prevention of an environmental impact from a process event.
Design Philosophy
The ESD system is distinguished from other facility safety systems in that it responds to a hazard situation
which may affect the overall safety of the entire facility. It is therefore considered one of the prime safety
systems that can be provided for any facility. Without an ESD system, an incident at a hydrocarbon facility
may be provided with "unlimited" fuel supplies that can destroy the entire hciiity. Such situations are amply
demonstrated by wellhead blowouts that can be fed from underground reservoirs and destruction of pipeline
connections at offshore installations affecting the availability of further isolation means, e.g., "Piper Alpha".
Facilities that do not have the capability to immediately provide an emergency shutdown should be
considered high risks. Similarly, if the reliability of an ESD system is very poor the facility might be
considered without adequate protection and therefore also a high risk.
Activation Mechanisms
Most ESD systems are designed so that several mechanisms can initiate a facility shutdown. These
mechanisms are provided by both manual and automatic means.
116
Emergency Shutdown
117
Typically they may include the following:
0
0
0
0
Manual activation from a main facility control point.
Manual activation from strategically located initiation stations within the facility.
Automatic activation from fire or gas detection systems.
Automatic activation from process instrumentation set points.
Levels of Shutdown
The activation logic for and ESD system should be kept as simple at possible. Typically most facilities
specifl plateaus or levels of ESD activation. These levels activate emergency measures for increasing
amounts or areas of the facility as the emergency involves a larger and larger area or the degree of hazard
from the initial event. Low hazards or small area involvement would only require a shutdown of individual
equipment while major incidents would require a facility shutdown. The shutdown of one of a facility should
not present a hazard to another portion of the facility otherwise both should be shut down. Typical levels
utilized in the petroleum and related industries are identified in Table 12.
ESD
Criticality
Action
Level
1
2
3
4
5
1 Total Facility Shutdown
I Unit or Plant Shutdown
Equipment Shutdown
Equipment Protective System Shutdown
Non-ESD Process and Control Alarms
I
I
Catastrophic
Severe
Major
Slight
Routine
Table 12
Typical ESD Levels
Reliability and Fail Safe Logic
The 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 safe
features are obtained by ensuring that selected components in an ESD system are such that during a failure
of a component the process reverts to a condition considered "safe". Safe implies that the process or facility
is not vulnerable to a catastrophic destructive event due to the release of hydrocarbons. For most facilities
this implies that pipelines that could supply fuel to the incident (i.e., incoming and outgoing) are shut off and
that high pressure, high volume gas supplies that are located in the incident are relieved to a remote disposal
system.
ESD system performance is measured in terms of reliability and availability. Reliability is the probability a
component or system will perform its logic function under stated operating conditions for a defined time
period. Availability is the probability or mean fraction of total time that a protective component or system is
able to hnction on demand. Increased reliability does not necessarily increase availability.
Reliability is a function the system failure rate or its reciprocal, mean time between failures (MTBF). The
system failure rate in non-redundant systems is numerically equal to the sum of component failure rates.
118
Handbook of Fire and Explosion Protection
Failures can either be fail-safe or fail dangerously. Fail safe incidents may be initiated by spurious trips that
may result in accidental shutdown of equipment or processes. Fail dangerously incidents are initiated by
undetected process design errors or operations, which disable the safety interlock. The fail dangerously
activation may also result in accidental process liquid or gas releases, equipment damage, or fire and
explosions.
ESD systems should be designed to be sufficientlyreliable and fail safe that a (1) accidental initiation of the
ESD is reduced to acceptable low levels or as low as reasonably practical, (2) availability is maximized as a
function of the frequency of system testing and maintenance, and (3) the fractional MTBF of the system is
sufficiently large to reduce the hazard rate to an acceptable level, consistent with the demand rate of the
system.
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 allowing the safety device
to revert to its fail safe mode. The specification of fail safe for valves can be accomplished by failing close
(FC), failing open (FO) or failing steady (FS), i.e., in the last position depending on the service the valve is
intended to perform. Valves that are specified to fail close on air or power failure should be provided with
spring return actuators. The use of accumulators to meet control valve fail safe conditions should be
avoided since these are less reliable fail safe mechanism and are more vulnerable to external impacts of an
incident. 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 operable
during a fire situation.
For ESD isolation valves @e., EIVs) a fail safe mode is normally defined as fail closed in order to prevent
the continued flow of fuel to the incident. Blowdown or depressurization valves would be specified as fail
open to allow inventories to be disposed of during an incident. Special circumstances may require the use of
a fail steady valve for operational or performance reasons. These applications are usually at isolation valves
at components, i.e., individual vessels, pumps, etc., where a backup EIV is provided at the battery limits that
is specified as fail closed. The fail safe mode can be defined by the action that is taken when the ESD system
is activated. Since the function of the ESD system is to place the facility in its safest mode, by definition the
ESD activation mode is the fail safe mode.
The utilization of a fail steady - fail safe mode may allow an undetected failure to occur unless additional
instrumentation is provided on the ESD system components or unless the system is constantly hlly function
tested. The prime feature of a full fail close or fail open failure mode is that it will immediately indicate if the
component is hnctioning properly.
The different safety integrity levels normally applied within the petroleum and related industries are usually
the following:
SLL
AVAILABILITY
0
1
2
3
1
1
1
1
4
1I
BPCS - Inherent
90 - 99%
99 - 99.9%
99.9 - 99.99%
99 99 - 99 999%
RISK REDUCTION FACTOR
(RRF)
I
None
I
10 - 100
100 - 1,000
I
1,000 - 10,000
I
10.000 - 100.000
Table 13
Typical Safety Integrity Levels (SlL)
Emergency Shutdown
119
Generally by increasing the independent layers of protection (IPLs), which are applied to a potential
hazardous event, the SJL number can be reduced. It should be noted that a SIL Level of 4 is seldom used in
the petroleum or related industries but 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 a
typical availability of 0.99. Level two involves a partially redundant logic structure, with redundant
independent paths for elements with lower availability. Overall availability is in the range of 0.999. Level
three is composed of a totally redundant logic structure. Redundant, independent circuits are used for the
total interlock system. Diversity is considered an important factor and used where appropriate. Fault
tolerance is enhanced since a single fault of an ESD system component is unlikely to result in a loss of
process protection.
ESD/DCS Interfaces
Where ESD and DCS systems are provided, they should be hnctionally segregated such that failure of the
DCS does not prevent the ESD from shutting down and isolating the facilities. Alternatively, failure of the
ESD system should not prevent an operator from using the DCS to shut down and isolate the facility. There
should be no executable commands over the ESD-DCS communications links. Communication links should
only be used for bypasses, status information and the transmission of reports. Confirmation of ESD reset
actions can be incorporated into the DCS but actual reset capability should not.
Activation Points
The activation points for ESD systems should be systematically arranged to provide the optimum availability
and afford adequate protection to the facility. The following guidelines provide some features that should be
considered.
The activation points should be located a minimum of 8 meters (25 ft.) away from a high process
hazard location but not more than 5 minutes away from any location within the facility. 5
minutes is taken as the maximum allowable time since historical evidence indicates process vessel
rupture may occur after this time period from flame impingement. If risk analysis calculations
demonstrate longer vessel rupture periods are expected, longer time periods may be acceptable.
The chosen locations should be preferably upwind from the protected hazard. Downwind sites
may be affected by heat, smoke or toxic gases.
They should be located in the path of normal and emergency evacuation routes from the
immediate area. In an panic situation personnel may immediately evacuate and not activate
emergency controls if they are located at inconvenient locations.
Locating sites hrthest from the sources of largest liquid holdups or highly probable leakage
sources (i.e., the relatively higher hazards) is preferred.
They should be located near other emergency devices that may need immediate activation in an
emergency @e., fire water monitors, manual blowdown valves, etc.).
The main access into the affected area should not be not impaired. Location of activation points
120
Handbook of Fire and Explosion Protection
in normal vehicle or maintenance access routes will affect operations and cause the device to be
eventually relocated or damaged.
The activation point should be mounted at a height which is convenient to personnel. The
ergonomics of personnel access to emergency controls should be accommodated.
Manned control rooms should always be provided with hardwired ESD activation points located
on the main control console easily accessible to the operators.
Activation Hardware Features
The hardwired ESD activation means is usually a push in knob or button. Confirmed action of the push
button should be always be required to manually activate the ESD system in order to prevent accidental
activations. Most commonly a protective cover is fitted over any of the push button or manual activation
devices. All devices should only be manually resettable.
Each activation point should be labeled to area of coverage and provided with and identification as to which
valves it operates or equipment it shutdowns. A specific identifier number should be assigned to each
device. The location itself should be highly visible, preferably highlighted in contrasting colors to normal
equipment housings.
In some instances it may be beneficial to maintain process inventories of certain process vessels until the
incident is actually threatening the container. The inventory of the vessel may be crucial to the restart of a
facility or the contents may be highly valuable. Loss of the inventory may be criticized if frequent false trips
of the ESD blowdown system occur. In these cases an automatic fbsible plug blowdown valve could be
installed which would only activate from the heat of a real fire incident. In this way, a false disposal of the
inventory can be avoided.
Isolation Valve Requirements
The failure mode of ESDVs for gas processing areas should always fail in the closed position, since this is
the only mechanism to resolve gas fed fires or prevent explosive vapor buildups. The valves should be
provided with an automatic fail 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 been
confirmed the emergency has passed or has been resolved.
The emergency isolation devices should be arranged so that they can be fully function tested without
affecting the process operation. This entails that a full flow bypass should be installed at each emergency
isolation valve. These bypass installations should be locked closed when not in service for fknctional testing
the ESDV.
Where MOV or AOVs are selected as ESDVs they should as a minimum have a back up activation power
sources and the utility service lines should be highly reliable and protected against an incident. It should be
noted 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 is
considered higher than a self contained MOV or AOV with its own local power source and protection of
cabling. This is because that additional components of a MOV or AOV contribute to additional failure
points and will also have a higher level of vulnerability from external events that the internal spring
mechanism inherently contains.
Emergency Shutdown
121
Emergency Isolation Valves (EIV)
Emergency isolation valves (EIV) should be located based one two principals (1) the amount of isolatable
inventory that is desired and (2) protection of the EIV from the affects of external events. EIV valves are
normally 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 be
located in an area that has potential to experience explosion and fire incidents.
Subsea Isolation Valves (SSIV)
Subsea pipeline emergency isolation valves for offshore facilities are provided where a risk analysis indicated
topside isolation may be considered vulnerable. They should be protected from ship-impacts, anchor
dragging, flammable liquid spills and heavy objects that may be dropped from the offshore facility.
Protection Requirements
ESD system components that are located in areas that would be considered direct fire exposures, i.e. within
or above fire hazardous risk areas should be provided fire protection measures to ensure integrity during
ESD operation and the duration of the major efforts to control the emergency.
Valve Actuating Mechanisms: 15-20 minutes H rating (H15 or H20,plus blast if applicable)
Directly Exposed Valves: 60-120 minutes H rating (H60 or H120, plus blast if applicable)
Actuating mechanisms include control panels, air receivers, valve actuators, instrumentation controls or
tubing, etc.
122
Handbook of Fire and Explosion Protection
Table 14
Firesafe Valve Test Standards
Emergency Shutdown
123
System Interactions
Petroleum facilities exist where the operators are hesitant to activate the ESD system for fear of rupturing
the incoming production pipelines due to their poor construction. This points out the fact that all
mechanisms that introduce a change to the normal operating configuration of the system must be analyzed to
determine what effect the proposed actions will produce. Whenever an ESD isolation valve is closed it will
stop incoming or outgoing flows which may produce instantaneous pressure variations that can detrimentally
affect the process system. An analysis of measures to prevent additional consequences should be undertaken
where such effects are possible, such as slower valve closing times, increased integrity of piping systems, etc.
124
Handbook of Fire and Explosion Protection
Bibliography
1.
American Petroleum Institute (API), Spec 14A. Specification for Subsurface Safetv Valve Eauipment, Eighth
Edition, API, Washington, D.C., 1994.
2.
American Petroleum Institute (API), RP 14B. Recommended Practice for Design. Installation. Repair and Operation
of Subsurface Safety Valve Systems, Third Edition, API, Washington, D.C., 1990.
3.
American Petroleum Institute (API), RP 14C. Recommended Practice for Analvsis, Desisn. Installation and Testing
of Basic Surface Safetv Svstems on Offshore Production Platforms, Fourth Edition, API, Washington, D.C., 1991.
4.
American Petroleum Institute (API), Spec 14D, Specification for Wellhead Surface Safetv Valves and Underwater
Safetv Valves for Offshore Service, Eighth Edition, API, Washington, D.C. 1991.
5.
American Petroleum Institute (API), RP 14H. Recommended Practice for Installation and Repair of Surface Safety
Valves and Underwater Safetv Valves Offshore, Third Edition, API, Washington, D.C. 1991.
6.
American Petroleum Institute (API), Spec 16D. Specification for Control Systems for Drilling Well Control
Eaubment, First Edition, API, Washington, D.C. 1993.
7.
American Petroleum Institute (API), Std 607, Fire Test for Soft-Seated Quarter Turn Valves, Fourth Edition, API,
Washington, D.C., 1993.
8.
Center for Chemical Process Safety (CCPS), Guidelines for Safe Automation of Chemical Processes, AIChE, New
York, NY, 1994.
9.
Kletz, T. A., Immovina Chemical Engineering Practices, Second Edition, Hemisphere Publishing Corp., 1990.
10. International Electrotechnical Commission (IEC), IEC-SC65A. Safetv System Design, Draft Standard, IEC, 1994
11. Instrument Society of America (ISA), draft standard SP-84.01. Application of Safety Instrumented Systems for the
Process Industw, Instrument Society of America, Research Triangle Park, NC, 1994.
12. National Fire Protection Association (NFPA), NFPA 79, Electrical Standard of Industrial Machinery, NFPA,
Quincy, MA, 1991.
Chapter 12
Depressurization, Blowdown and Venting
Hydrocarbon 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 of
hydrocarbon inventory isolation and removal system. These systems are commonly referred to in the
petroleum industry as ESD (emergency shutdown) and depressuring or blowdown. Although most
standards and practices acknowledge the need for depressuring capabilities the exact determination of their
requirement is not wholly defined. NFPA fire codes and standards rarely mention the subject.
Objective
Typically hydrocarbon process vessels are provided with a pressure safety valve (PSV), to relieve internal
vessel pressure that develops above its designed working pressure. The purpose of the PSV is to protect the
vessel from rupturing due to overpressure generated from process conditions or exposure to fire heat loads
that generate additional vaporization pressures inside the vessel. The engineering calculation behind this
application assumes that the process vessel steel strength is unaffected by direct fire exposure causing the
increase in pressure. If the vessel is kept at or near it's design temperature this can be assumed the case,
however when steel is exposed to a high temperature fiom a hydrocarbon fire it's capability to contain
normal operating pressure deteriorates rapidly sometimes within a few minutes. Since the strength of the
material is rapidly deteriorating during this process, regardless of the vessel internal pressure. A rupture of a
vessel can easily occur below the operating pressure of the vessel, within minutes of the vessel being
exposed to a major heat source.
Pressure safety valves (PSV's) are typically sized to activate at 121% of the working pressure for fire
conditions 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 steel
strength below the strength needed to contain its normal operating pressure. In this case the vessel may
rupture before or during activation of the PSV, when its it trying to relieve pressures above operating
pressures.
Two major hazards may occur from hydrocarbon pressure vessel failures. The vessel rupture itself and the
possible formation of a vapor cloud as a result of the rupture. If the vessel ruptures it will produce flying
projectiles and usually release large quantities of flammable vapors. The flying projectiles may contain
sufficient momentum to affect other areas. The projectiles could harm individuals or damage the
hydrocarbon facility, possibly increasing the incident proportions. Secondly, the released gas from a
pressurized vessel may cause a flammable vapor cloud to occur. If some amount of congestion is present or
any amount of turbulence of the cloud occurs, an explosive blast may result if the cloud contains enough
material and finds an ignition source.
125
126
Handbook of Fire and Explosion Protection
Industry literature typically cites concern with open air explosions when 4,536 kgs (10,000 lbs.) or more of
flammable 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 resulting
fire or explosion damage can cripple a hydrocarbon processing facility. Extreme care must be taken to
prevent the release of hydrocarbon fiom 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 are
available. Depressuring, insulation, water cooling or draining are usually employed in some fashion to
prevent of the possibility of a vessel rupture from it's own operating pressures. A generalized method to
qualitatively determine the effect of a hydrocarbon fire on the strength of vessels constructed of steel is
available. With this method one can estimate the time for a vessel to rupture and therefore the need to
provide protective measures.
API conducted open pool hydrocarbon fire exposure tests (mostly naphtha and gasoline fires), on process
vessels during the 1940's and 50's.
This data was plotted using the parameters of
(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 vessels
constructed of ASTM A-515, Grade 70 steel, a steel typically employed for process vessels. If other
materials are used an allowance for their stress characteristics under heat application needs to be made.
Therefore a general determination of the need for protective measures, such as depressurization,can be made
for a particular vessel by comparison to the D-2 chart and selected fire exposure temperatures. It should be
noted that this is the best available fire test exposure data in the public domain. Improved methods and test
data may be available in the kture to refine the calculation methods.
Underwriters Laboratories (UL) high rise (hydrocarbon) fire test UL 1709, has an average fire temperature
of 1093 O C (2,000 OF) after 5 minutes. Therefore unless the an actual fire exposure heat radiation input
calculation has been made, either a worst case fire exposure temperature could be assumed or a standard
temperature to the limits of UL 1709 could be applied.
Fireproofing material is considered to fail if any individual thermocouple reaches 649 OC (1200 OF). The
API recommended practice does not define the surface temperature from a fire exposure to be applied for
the purposes of calculating rupture periods, but provides data from 482 OC (900 OF) to 760 OC (1400 OF) in
38 O C (100 OF) increments to determine rupture times. It should be remembered that fiee burning fires as a
rule do not achieve theoretical combustion temperatures for the fiels involved. Petroleum fires can reach as
high as 1300 O C (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 engineering judgment of the arrangement of the
vessel involved should be applied in selecting the appropriate fire exposure steel temperature. Typically 649
O C (1200 OF) is chosen as a starting point as this correlates well with fireproofing test requirements. A
particular point noticed when using the API chart is that a 100 degree C (212 OF) difference in the fire
exposure temperature can have a dramatic difference in the time till a vessel rupture. Therefore the chosen
exposure temperature has to be chosen carefilly and adequately justified.
Depressurization, Blowdown and Venting
127
The ASME pressure vessel rupture stress formula is applied to calculate a vessel stress is:
S
=
P(R+0.6t)Et
Where:
S
=
Rupture Stress
P
=
Operating Pressure in Psig
R
=
Shell Inside Radius, Inch
t
E
=
=
Shell Wall Thickness, Inch
Weld Joint Efficiency (generally assume 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 historical
evidence and the typical growth of a hydrocarbon fire would indicate that the immediate rupture of a vessel
does not occur. Further investigations may be carried out verity if fire exposure conditions could produce
such 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, but
this depends upon the quality and thickness of the insulation, plus the time for the insulation to raise the
ambient exposure temperature. Typically in sizing relief valves, it is normally assumed that lightweight
concrete insulation (fireproofing) reduces the heat input to approximately one third of it's original value.
Therefore depending on the rating of the fireproofing, the t h e till a vessel rupture from operating pressures
can be increased. The time delay of the fireproofing material can be added to the time it takes to cause the
steel to weaken and rupture. Commercially available hydrocarbon fire rated fireproofing materials are
available in several hours of fire resistance periods. If connecting pipelines are not isolated with an ESD
valve or insulated from fire sources, they could also be a source of hydrocarbon release that have to be taken
into account when making these assumptions.
Similarly if a vessel is provided with a reliable and dependable water cooling (i.e., firewater deluge water
spray), according to recognized standards, (e.g., NFPA 15, Water Spray Systems for Fire Protection), that
would not be affected by an explosion blast pressures or the fire exposure, it may theoretically demonstrate
that a vessel does not need a depressuring system for the prevention of rupture from fire exposures.
Similarly API RP 2000 does not allow credit for water cooling sizing pressure relief valves unless they are
demonstrated to have extremely high integrity during accidental events.
If the area under the vessel is provided with adequate drainage capability credit may also be taken for a
reduced heat input due to the runoff of any flammable liquids producing the fire exposure. Usually drainage
requirements to NFPA 30 (Flammable and Combustible Liquids Code), would have to be met, namely 1
percent to a 15.2 meter (50 ft.) radius. Published literature suggests that an uninsulated vessel rupture time
could be increased 100% for a highly effective drainage system.
Two examples on the technique to calculate vessel rupture periods have been prepared and are shown in
Figures 4 and 5.
128
Handbook of Fire and Explosion Protection
SEPARATOR (Honzontal)
ASSUMPTIONS:
S = P (R + O.Gt)/Et
Size
10'4" 1.0.x 50'-0"
112"
Shell Wall Thickness
Liquid Sp. Gr.
1.a
Material of Construction
Operating Presssure
Design Pressure
Normal Liquid Level
A515 Gr. 70
50 Psig
90 Psig
5'-0" from bottom
S/S
ref.: ASME. DIV. Vlll for circumferential stress)
S = 50 (60+ 0.6 x 0.5)/1 .O x 0.5
Where:
S = 6,030psi
S = Rupture Stress
P = Operating Pressure in Psig
R = Shell inside radius, Inch
t = Shell Wall Thickness, Inch
E = Joint efficiency (assumed 700%)
From Figure 0 2 (API 520, page 55)
Time before rupture at 6,030psi and 1,300 deg. F is approximately 5 HE.
CONCLUSION:
Depressurization system is not required.
HORIZONTAL SEPARATOR
Figure 4
Depressurization, Blowdown and Venting
129
CRUDE STABILIZEil
ASSUMPTIONS:
Size
5 ' 4 " 1.0 x 40'-0" S/S
Shell Wall Thickness
711 6"
Liquid Sp. Gr.
0.a5
A5 15 Gr. 70
Material of Construction
Operating Presssure
150 Psig
Design Pressure
175 Psig
5'-0" from bottom seam
Normal Liquid Level
Vessel is insulated but no credit given for insulation
S = P (R + 0.6t)Et
(Ref. ASME, DIV. Vill FOR CIRCUMFERENTIAL STRESS)
S
= 150 (30 + 0.6 x 0 . 4 3 7 5 ) ~.O x 0.4375
Where:
S = 10,374 Psi
S = Rupture Stress
P = Operating Pressure in Psig
R = Shell inside radius, Inch
t = Shell Wall Thickness, Inch
E = 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 hours
CONCLU.SION:
Depressurization system. is required.
I
I
CRUDE STABILIZER
Figure 5
130
Handbook of Fire and Explosion Protection
Once a time period has been established when a vessel might be expected to rupture, this needs to be
compared against the WCCE for the facility. A very short duration fire exposure would imply that a vessel
depressurization may not be necessary. Typically most hydrocarbon facilities are provided with an ESD
system, which at the very minimum should isolate the incoming and outgoing pipelines. In this fashion the
remaining major fuel inventory at the facility is what remains in vessels, tanks and the piping infrastructure.
I t should also be considered that d e r 2 to 4 hours of a hydrocarbon high temperature fire, usually
equipment or facility salvage value is minimal. So beyond these periods, little value is gained in additional
protection measures. Typically if the rupture period is of a magnitude of several hours, the need for
depressuring (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 a
minimum of 50% of its design operating pressure or preferably completely depressurized, remaining
interconnecting vessels are also depressurized. If vessels are not completely depressurized, there is still a
risk of vapor release from the remaining pressure (ie., &el inventory) in the vessel or piping. An
engineering evaluation of depressurization arrangements and calculation of depressuring periods should be
performed.
Certain conditions and arrangements (process restarts for example) may preclude the provision of an
automatic and immediate depressuring system for all vessels. Some volumes of gaseous products may be
necessary for an adequate process restart. If the facility where to accidentally depressurize, the operation
may suffer an economic business interruption loss if gas supplies have to be obtained from outside the
facility. In these cases alternative protection methods may be employed. Where vessels are not located in
dense processing areas, subject to adjacent impact time delay and local fusible plug activated depressuring
outlet 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. An
engineering analysis should be performed when a fully automatic (ESD) depressuring system is not provided.
Published literature also suggests that explosions and major damage are very unlikely when less than one ton
of material is released. API RP 520 additionally suggest that vessels operated at or below 690 Wa (100 psi)
typically are not provided with depressurization capability.
Depressurization, Blowdown and Venting
131
The following is a general guideline that may be used to generally classifL which process vessels may need
depressurization capabilities:
Vessels Requiring Depressurization Capability:
A vessel operated above 690 Wa (100 psi).
The vessel contains volatile liquids (e.g., butanes, propanes, ethanes, etc.) with vapor pressures
above atmospheric.
Operational requirements exist (e.g., compressor blowdowns).
A fire condition may occur that weakens a vessel to below safe strength levels (as defined by API
RP 520, Part 1, figure D-2), within several hours, which may cause significant exposure losses.
Vessels Which May Not Require Depressuring Capability:
A vessel operated at or less than 690 Wa (1 00 psi).
A vessel containing less than 907 kgs (2,000 Ibs.) of vapors
A vessel whose time to rupture from a fire exposure is more than several hours.
A vessel provided with fireproofing insulation rated to withstand the expected fire exposures until
other protection measures are employed (e.g., effective manual fire fighting is available).
A vessel provided with a firewater deluge system to protect against hydrocarbon fire exposures for
the duration the worst case plausible incident.
A vessel whose time to rupture, insulation, fixed fire water protection or drainage arrangements
would 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, damage
important or critical facilities, cause significant finankial impacts, create an environmental hazard or
create an undesirable reaction from the general public.
The objectives of depressuring are (1) to prevent a vessel from rupturing during a major fire exposure (from
the weakened condition of the vessel steel), (2) to prevent further fire escalation and (3) to minimize the
impacts to the vessel itself. It is therefore incumbent to depressure a vessel so that its stress is less than
the stress to cause a rupture from fire conditions. These stresses and rupture periods can be estimated to
determine the need for depressuring systems for hydrocarbon vessels. These estimates can provide a rough
estimate 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 safely
remove the vapors from the area and dispose of it without impact to the environment. A special concern
when high levels of pressurized gases are released into a piping system is the possibility of auto-refrigeration of the piping material that may cause a brittle fracture. A process engineer should verify which pipe
materials and flow rates, specified for the depressurization system, are suitable for the pressures, flows and
gases contempla?ed
Once calculations are completed on a depressurization system it will become readily apparent high volumes
of gases will be flowing through the header to a flare. In some cases the practicality of simultaneously
depressurizing all of the process equipment and vessels will be difficult to accomplish. In these cases a
sequential blowdown of the vessels should be considered. Providing for the "worst" vessels first or
controlling the system to blowdown the area most affected first are desirable options.
High noise levels may also be generated when high flows are encountered. In these circumstances, special
noise reducing fittings are available to limit noise impacts from the system to the surrounding area.
132
Handbook of Fire and Explosion Protection
i
i
YES
VESSEL OPERATING
PRESSURE > I00 PSI
IS
IS
>
i
VESSEL VOLUME
> 0.5 cu. FT.
t
NO
*
NO
*
YES
NO
A
i
IS WORST CASE flRE
> I O MIN.
*
NO
*
DEPRESSJRIZATION
NOT NEEOEO
*
MS
*
PROWOE MEANS
YES
1s KSSEL LOCATED IN A
OENSE PROCESSING AREA
ro
OEPRESNRE
ESTIMATE MSSEL RUPTURE
TIME PER API 520. FIG. 0-2
i
i
r
IS M S S E L INSULATED
AOO
NO
1
I
nME PERIOO TO RUPTURE
TIME FOR INSULATION
a
OOES M S S E L H A M coo0
ORAINAGE k JET flRE
IMPINGEMENT IS MINIMAL
i
I
A 0 0 TIME OELAY FOR DRAINAGE
L LOW JET FIRE IMPACT
IS M s s a PROWOEO WTH
WATER SPRAY PROTECTION
YES
A00 TIME FOR OURAnON OF
flRE WATER S P R A Y
Figure 6
I
I
IS FIRE DURATICN LONGER
ro
WAN n u €
RUPTURE
*
KS
OEPRESSURINC
NEEOEO
snm
I
J.
No
DEPRESSURIZATION NOT NEEDEO
PROCESS VESSEL DEPRESSURIZATION
FLOW CHART
/
Figure 6
Depressurization, Blowdown and Venting
133
Blowdown
Blowdown is the removal of the liquid content of vessels and equipment to prevent their contribution to a
fire or explosion incident. Blowdown is similar to depressurization but entails liquids instead of gases. A
liquid 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 onto
the process facilities. Ideally liquid blowdowns should be routed to facilities that are specifically designed to
handle 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 entrained
gases may cause the tank to rupture. Similarly disposal to a pit is not desired as it poses the hazard of
exposed combustible liquids that can ignite.
Venting
Direct venting of hydrocarbon or toxic gases to the atmosphere should be avoided for the
following reasons.
(1) It may create a combustible vapor cloud with fire or explosion possibilities
(2) It may be harmfid to personnel.
(3) It may be an environmental pollutant.
(4)
. , It is a waste of the fuel gas.
( 5 ) It represents a poor community or public image to release wastes to the atmosphere.
( 6 ) It may be a violation of the national or local environmental governmental regulations.
(7) Remotely vented gases may not adequately disperse, then drift considerable distances and
ignite.
Whenever possible waste vapors or gases should be disposed of through the facility flare system or
reinjected into the production process for recovery. Non polluting materials such as steam can be freely
vented to atmosphere if they do not pose burn hazards to personnel.
Flares
In most hydrocarbon operations excess gas and vapors have to disposed of safety, quickly without
environmental impact. Where the gas or vapor cannot be converted into usefd energy they are routed to a
remote point for safe incineration, called flaring. Flares are the most economical and customary means of
disposing of excess light hydrocarbon gases in the petroleum and chemical industries. The primary finction
of a flare is to convert flammable, toxic or corrosive vapors to environmentally acceptable gases for release
into the atmosphere. Both elevated or ground flares can be used.
The type of flare used depends on several factors including:
(1)
(2)
(3)
(4)
Available space of onshore or offshore arrangements.
Characteristics of the flare gas - composition, quantity, pressure, etc.
Economics both initial capital costs and periodic maintenance.
Public impression (i.e., if flaring is smoky or noisy the general public will object to its
operation).
The primary features of a flare are safety and reliability, while the primary objective of the flare is to prevent
the release of any unburned gases. In reviewing existing facilities worldwide, from Russia to South America,
onshore and offshore, most installations have admitted either officially or unofficially that on occasion, a
liquid release has occurred from the tip of the flare stack. This has occurred even with the installation of a
flare header liquid knock out drum. In most cases this has caused no apparent problems although in a few
134
Handbook of Fire and Explosion Protection
cases it has been disastrous. It is suspected liquid releases occur much more frequently than is actually
reported. Technically the problem may be because most flare systems are designed for unrestricted gas flow
through the flare header and knock out drum, but which induce liquids to carryover. Therefore the
possibility of liquid releases from vapor disposal flares cannot be entirely ruled out.
During a typical plant design, the flare location is usually examined. Some experts suggest that a flare
should be located downwind and while others propose it should be upwind of the facility. This based on the
assumption that a flare may overflow with liquids and therefore should be downwind so these don’t fall on
the 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. This
avoids both the vapor dispersions from the flare and liquid releases onto the plant. Preferably the flare
should also be at a lower elevation than the rest of the facility. This is in case it releases heavy vapors that
have not been properly combusted in the flare exhaust. Because of the larger spacing distances and risk
factors associated with flares they should be one of the first items sited for a new facility.
Flare safety precautions should include:
(1)
(2)
(3)
Use of a automatic flame monitoring device to warn of flameout conditions.
Provision of a liquid knock out (KO) drum, which is equipped with high level alarms to
warn of an excessive accumulation of liquid.
Prevention of the introduction vapors into the system when it is not operational.
The important safety aspects of flares include the following:
a. The flare is a readily available ignition source to vapors that can reach it or the radiant heat it
produces.
b. Flame-out (flame lift-off or blow-outs), sometimes occurs at a flare, at which time flammable
vapors will be discharged. If heavier than air and wind conditions permit, they will travel along
the ground to other areas until dissipated. Provision of a windshield around the flare tip will
assist in prevent a flame-out from occurring.
c. Flare may emit liquids under certain conditions, which even if a flare is lit it can endanger
processes that are placed to close to it. Provisions to entrap and contain liquids in the flare
header, for worst case conditions should be provided at the flare tower.
Liquid separators or knockout drums are normally used to remove any liquid from gas streams
flowing to flares designed to burn vapors. The drums should be designed not only to collect liquids
running 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 micrometers in diameter or larger should be
removed before flaring the gas. Additionally the knockout drum should be sized to accommodate
the maximum amount of liquid that might be required to be withdrawn during depressurization of
the entire or any portion of the facility as the design of the system may dictate. If large quantities
of propanes and butanes low temperatures may be reached in the flare header and drum due to auto
refrigeration, which must be taken account of.
Depressurization, Blowdown and Venting
Material
Process Vapors
Flammable & Nontoxic&To:
ProcessVa ors
Nonflammable and
Toxic
1 1 I 1
Flare
Vent
Process
x
Sewer
X
Process Va ors
Nonflammable and
Non-toxic
x
Sewer Vapors
Liquids
Process Blowdown
Thermal Relief
Process Drain
I
I
I
I
I
I
I
I
X
X
I x
] x
I x
X
Table 15
General Guidelines for Material Disposal Methods
135
136
Handbook of Fire and Explosion Protection
Bibliography
1.
American Petroleum Institute (API), RP-520. Sizing Selection and Installation of Pressure Relieving Svstems in
Refineries. Part I Design (1993). and Part I1 Installation (19881, API, Washington, D.C.
2.
American Petroleum Institute (API), RP-52 1. Guide for Pressure-Relieviny and Depressuring Systems, Third
Edition, API, Washington, D.C., 1990.
3.
American Petroleum Institute (API), Standard 2000. Venting Atmospheric and Low Pressure Storage Tanks, Third
Edition Reaffirmed, API, Washington, D.C.,
1987.
4.
American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessels Code, ASME, New York, NY,
1992.
5.
Gas Processors Association (GPA), Engineerin9 Data Book, GPA, Tulsa, OK, 1987.
6.
National Fire Protection Association (NFPA), NFPA 15. Water Spray for Fire Protection, NFPA, Quincy, MA,
1993.
7.
National Fire Protection Association (NFPA), NFPA 30. Flammable and Combustible Liquids Code, NFPA,
Quincy, MA, 1990.
8.
Vervalin, Fire Protection Manual for Hvdrocarbon Processing Plants, Gulf Publishing, Houston, TX, 1985.
Chapter 13
Overpressure and Thermal Relief
The term pressure relief refers to the automatic release of fluids or gases from a system or component to a
predetermined level. Pressure relief systems are designed to prevent pressures in equipment or processes
reaching levels where rupture or mechanical failure may occur by automatically releasing the material
contained within.
Almost all portions of a hydrocarbon process or system can conceivably be exposed to conditions that would
result in internal pressures (either positive or negative) exceeding the normal operating pressures of the
system. The most common causes are listed below:
Exposure to Fire: If a vessel is exposed to a heat radiation from a fire, internal pressure may
rise primarily due to the generation of vapor from the internal liquid or from thermal expansion
of the contained commodity.
Excessive Process Heat Input: Most hydrocarbon and chemical processes require or contain
varying amounts of heat exchange. Should a process upset occur, which inputs more heat than
design conditions have allowed an overpressure may result due to expansion of liquid or vapor
contained within the system.
Failure of Flow, Pressure or Temperature Control Valves: Control valves that regulate
process conditions may fail causing a process upset to occur. Once the process upset occurs
pressure regulation will not be effectively controlled and a pressure increase may result.
Unexpected Process Chemical Reactions: Unexpected chemical reactions which result in heat
or vapor evolutions may produce overpressures that have not been planned for.
Failure of the Cooling Water Supply: A reduction in cooling water flow to condense vapors
in a vessel may lead to an increased pressure drop through the condensers resulting in an
increased pressure in the vessel.
Vessel Isolation: If a vessel becomes isolated either filly or partially, from normal process
conditions, 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 pressure
level of the circulating medium and an internal heat exchanging tube ruptures or leaks it will
overpressure the vessel.
Introduction of a Volatile Material: The introduction of a liquid into a vessel where the
137
138
Handbook of Fire and Explosion Protection
temperature is above the boiling point of the commodity will result in the rapid vaporization of
the material causing an increase in vapor output requirements and raising the pressure of the
vessel. Materials with low molecular weight are especially prone to this effect.
Reflux System Failure: The quantity of reflux used in fractionation systems determines the
amount of vapor generation and the consequent pressure differential through the condenser
system. If a reflux system fails, lower pressures through the condensers and the vessel may result
in higher pressure rise in the system as a whole.
Internal Detonations or Explosions: An internal detonation or explosion may occur due to
several 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. These
almost instantaneous events have to be carehlly protected against as many overpressure devices
do not react quickly enough to prevent the vessel from rupturing.
Thermal Expansion: Contained liquids may be subject to heat input that causes them to expand
resulting in a pressure increase. Typical heat sources are direct sunlight and fire exposures.
Non-Condensable Gas Accumulation: If noncondensible gases are not removed, overpressure
can result when a heat exchanger surface becomes blanketed or pressure drop through the
condensers is increased by the presence of the non-condensable gas.
Outflow Rate Exceeds Inflow Rate: If material is being withdrawn from a tank or vessel faster
than the incoming rate to compensate for the removal suction a vacuum will occur. If the vessel
or tank is not strong enough to withstand the negative pressure levels it will collapse in on itself
There are numerous types of pressure relieving devices available,.which include relief valves, safety valves,
rupture or frangible disc and blow out hatches or panels.
Pressure Relief Valves (PSV)
Pressure relief valves are provided to cater to two main conditions of the process -normal conditions and
emergency conditions. Normal conditions relate to the designed operation of the process which emergency
conditions can be caused by either (1) external fire conditions, (2) failure of reflux or cooling, ( 3 ) Failure of
the power supply, (4) failure of steam supply, (5) heat exchanger failure (6) introduction of incompatible
materials, (7) thermal expansion with outlets closed.
Because these causes of overpressures are considered random and infrequent, the pressure relief capability
has to be automatic and constantly available.
Where relief valves are provided on liquid storage tanks or vessels, where there is a possibility of liquid
release, i.e., liquid slug, carehl evaluation of the release disposal system (e.g., flare header) needs to be
undertaken. In some cases, a liquid slug may block a header from releasing pressure and defeat the purpose
of the pressure release system.
Overpressure and Thermal Relief
139
Thermal Relief
Thermal relief is necessary in section of liquid piping when it is expected that the liquid will be isolated when
the piping is also subject to temperature rises from solar radiation, warm ambient air, steam tracing , fire
exposures or other external sources of heat input.
High temperature input to a piping system will cause both the pipes and the fluid contained within it to
expand. Liquids have a high coefficient of expansion compared to metals (e.g., oil will expand
approximately 25 the times of a metal pipe). It therefore can be expected that high pressures can be
developed in piping systems that can be isolated and exposed to heat input. Thermal expansion of the pipe,
expansion of pipe material from internal pressure or compressibility of the liquid may be adequate for relief
of liquid thermal expansion before strength limits are reached for piping , valves or blinds. Research tests
have shown that pressure from thermal expansion of liquid hydrocarbon may increase about 553 kPa to 789
kPa (70 to 100 psi) for each OF temperature increase. The length of the piping has no effect on the pressure
that will result from thermal expansion of a liquid in an isolated section. However the volume of fluid that
must be released to prevent excess pressure build up will be directly proportional to the line length.
Temperature increases in hydrocarbon process lines that are not in circulation but receive heat input can
easily achieve temperature increases that will result in pressure build up that needs to be evaluated for
thermal expansion relief Normal solar radiation in some cases is enough to raise the pressure in lines
containing liquids by as much as 23,685 kPa to 78,950 kPa (3,000 to 10,000 psi). The main reason why
more ruptures have not occurred in lines without thermal pressure relief devices, is that most isolation valves
have some tolerances of leakage and pipe flange gaskets may also leak or fail. Further reliance on quality
isolation means such as double block valves, double seated gate valves, line blinds, etc., produces a greater
chance of line rupture from thermal expansions. Also reliance on flange leaks to relieve trapped piping
pressure is no longer an acceptable environmental alternative. The tighter verification of a leak-free facility
to prevent VOC emissions to environment will require elimination of pressure release points that may have
been unknowing relied upon in the past. Any relief design must assume that the relief effluent is contained
within system piping and properly contained and disposed.
Overpressure from 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 thermal
relief. As pressure is built up in a line, sensors may warn of pressure increases, valves can leak, or the
pressure build up is not a feasible scenario. There are some services where the provision of a thermal relief
valve 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 instituted
to alleviate thermal pressure concerns such as partially draining liquid lines before isolation, continuous
pressure monitoring, etc. These methods are not the preferred method of protection since they are prone to
human error. Relief valves are the preferred method of preventing pressure build up.
Solar Heat
For geographical locations between 60° N and 60° S latitudes solar heat input to pipelines
and the resultant thermal expansion is essentially the same. Orientation will have some
effect to the total amount of heat input, i.e., North-South provides more exposure than
East-West, however the maximum rate of heat input is the same that occurs at the highest
sun position, Le., at noon. This is a rather trivial aspect, as the cost of pipe length and
installation costs generally overrule orientation concerns. Wind effects normally will
dissipate some heat from pipelines. However for the case of thermal expansion concerns, it is common
practice to consider no wind for purposes of heat input (or loss) to a piping system. Pipe color will as have
an impact to heat absorption. Flat black is the highest heat absorber (l.O), while light colors are quite less
(0.2. to 0.3). Reflectivity characteristics also assist in reflecting radiation.
140
Handbook of Fire and Explosion Protection
Thermal Relief Fluid Disposal
There are three main methods to dispose of releases from thermal relief valves. Discharge around a
block valve (isolation circumvention) is widely used in most situations, however where this is not
practical or economical disposal to a sewer or release to surface runoff can be specified in certain
cases.
Isolation Circumvention
Where the fluid is the same on each side of the isolation means, and no contamination will result
this is the optimum choice for thermal relief release. Consideration of the possibility of
backpressure onto the thermal relief valve, rendering the valve ineffective, should be evaluated
before an analysis is finished.
Disposal to the Oily Water Sewer
A process oily water sewer system is a convenient location to direct oily wastes. The oily water
system normally collects into a sump. If several lines connect into a common header, care should
be 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 Runoff
Only when other alternatives are not available should a fluid release to the open environment be
considered a viable disposal method. Additionally it should only be considered when the release is
small and does not create an additional hazard - either from fire safety or environmentally. The
relieved liquid should always be directed to a level surface away from other equipment, for
containment by the facility surface runoff accommodations to mitigate any environmental or fire
hazard. In no cases should discharge to the atmosphere be contemplated as it would create an
immediate explosion or fire hazard and could also be considered an immediate environmental
pollutant.
Pressure Relief Device Locations
Pressure relief capability is generally required at the following locations:
Pressurized Vessels
Unexpected process upsets may produce pressures above normal operating conditions.
Storage Tanks
All storage tanks subject to high flow rates in or out, requiring compensation for the displaced vapor.
Equipment Susceptible to Thermal Expansion
i.
ii.
Vessel or tanks subject to ambient or fire hazard heat inputs.
The cold side of a heat exchanger if blocked off may be subject to excessive heat input from the
hot side.
iii. Circulation lines of heater where they can be blocked off
Discharge of Compressors
Variable speed drivers can increase compressors discharge pressures about desired amounts causing a
Overpressure and Thermal Relief
141
process upset. With the provisions of constant speed drivers, such of electrical motors the possibility
of overspeed is highly remote.
Pumps with Variable Speed Drivers
Variable speed drivers can increase pump discharge pressures about desired amounts causing a
process upset. With the provisions of constant speed drivers, such of electrical motors the possibility
of overspeed is highly remote.
Heat Exchanger
Heat exchangers that can be blocked in or where the shell of the exchanger may be subject to high
pressure if an internal tube leak occurs.
142
Handbook of Fire and Explosion Protection
Bibliography
1.
American Petroleum Institute (API), RP-14J. Design and Hazards Analysis for Offshore Production Facilities, First
Edition, API, Washngton, D.C., 1993.
2.
American Petroleum Institute (AH), RP-520, Design and Installation of Pressure Relieving Systems. Part I Design
(1993) and Part I1 Installation (1988, API, Washington, D.C.
3.
American Petroleum Institute (API), RP-52 1. Guide for Pressure Relieving and Demessuring Systems, Third
Edition, API, Washington, D.C., 1990.
4.
American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessels Code, ASME, New York, NY,
1992.
5.
American Society of Mechanical Engineers (ASME), B3 1.3 Chemical Plant and Petroleum Refmerv Piting, ASME,
New York, NY, 1993.
6.
American Society of Mechanical Engineers (ASME), B3 1.4 Liquid Transportation Svstems for Hvdrocarbons,
Liquid Petroleum Gas. Anhvdrous Ammonia and Alcohols, ASME, New York, NY, 1993.
7.
American Society of Sanitary Engineering, Performance Requirements for Thermal Expansion Relief Valve,
American Society of Sanitary Engineering, Bay Village, OH, 1990.
8.
Industrial Risk Insurers (IN),IM.7.0.5.0, Overpressure Protection, IN,Hartford, CT.
9.
National Fire Protection Association (NFPA), NFPA 30. Flammable and Combustible Liauids Code, NFPA,
Quincy, MA, 1993.
Chapter 14
Control of Ignition Sources
In petroleum operations any leak or spillage may give risk to an explosive atmosphere. To protect both
personnel and the plant, precautions must be taken to ensure that the atmosphere cannot be ignited. It is
generally recognized that there are three main categories of ignition sources in a hydrocarbon facility - open
flames, hot surfaces and sparks. The overall objective protection is to remove or provide a barrier inbetween these ignition sources from materials that can readily ignite if contact is made. The ability of these
sources to ignite a material depend on their available energy and configuration.
Open Flames, Hot Work and Smoking
Open flames in a hydrocarbon facility usually are available'from welding or hot work operations, smoking
and the facility flare. NFPA 51B provides guidance in the conduction of cutting and welding operations.
Additionally all petroleum facilities have limitations on areas allowed for smoking. Both of these sources are
normally controlled through operational measures supplemented by physical separation. Similarly flares are
sited to offer the least possibility to ignite a process vapor release.
Electrical Arrangements
Facility electrical systems and components provide a convenient source of ignition within a hydrocarbon or
ordinary occupancies whenever the design, installation or maintenance is substandard. Electrical systems or
components may short, overheat, operate incorrectly, etc. These failures will present themselves as available
ignition sources for hydrocarbon vapor releases. All electrical installation should be according to recognized
electrical industry standards such as API RP 540 and the NEC (NFPA 70).
Electrical Area Classification
The overall intent of electrical area classification is to provide for safety of personnel and equipment. This is
achieved by the elimination of electrical ignition sources near combustible gases or vapors that could
explode or burn. The specific reasons for classifying facilities into electrical hazardous areas typically are:
1. To ensure that sources of ignition are safety separated from sources of combustible liquids and
gases.
2. To ensure electrical apparatus selected for use near combustible liquids and gases is of adequate
design and construction to prevent ignitions.
3 . To assist in the location of air inlets for ventilation systems and combustion equipment
143
144
Handbook of Fire and Explosion Protection
4. To define the extent of flammable vapor travel from vents, drains and other open hydrocarbon
sources.
5. To assist in the location of combustible gas detectors and fire detection equipment
6 . To permit the location of life saving appliances, flammable liquid stores, radioactive and
emergency control points in safe areas where practical.
7. To achieve an economical electrical installation which will provide an acceptable level of safety at
the lowest possible cost.
It might be argued that if the ignition sources where not all removed, but still present in hydrocarbon
processing areas, hydrocarbon leakages would be immediately ignited preventing the formation of large
vapor clouds. If these leaks are involved in combustion, the he1 is consumed, thus avoiding major fire
damage and the value for explosionproof equipment is unnecessary.
It should be remembered that leakages may be large or small in nature and can be orientated in infinite
directions, 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 removed
from the area. Therefore prevention measures should be employed, to avoid the ignition of a hydrocarbon
liquid or vapors whenever possible.
To enable electrical equipment to be used safely in potential hazardous atmospheres, various, although
essentially similar, hazardous area definition techniques have been developed over the years by several
organizations. Various international and national standards or codes of practice govern each of these
techniques. These methods define how the equipment is to be designed and applied. Certimng bodies
ensure a specified design meets the requirements of the standard or code. The basic premise of these
techniques is to specify a "hazardous area" that a flammable gas or vapor may be likely to be encountered
based on gas or fluid concentration and the configuration of the equipment or facility. The purpose of these
hazardous area classifications is 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 where
flammable 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 Combustible
Liquids Code. Other international codes and specification exist which may alter the requirements of these
codes,.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 and
accept products and systems certified by other members. Other countries work to their own standards based
on IEC-79 (e.g., Australia, Brazil, Japan, Russia), or accept products and systems certified to European or
North American standards. Figure 7 provides a graphic example of the difference various codes may
produce.
Control of Ignition Sources
NFPA 30 ( U S1
l
i
p
l
B C I (West Germany)
[ C I I R o S P A : LPG ( U K )
Health and S a f e t y
Executive CSS:
1
CPP: LPG ( F r a n c e )
Oet Norske V e r i t a s (Norway)
5 5 C2108 20 (Sweden)
-
0
Scale
10 M
Hazardous Area Classification Codes Applied to the Same Pump
(Pump handling LPG)
Figure 7
145
146
Handbook of Fire and Explosion Protection
Some specific internationally recognized electrical hazardous location equipment testing agencies are listed
in Table 16 below.
Table 16
Recognized International Electrical Approval Testing Agencies
Simple 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 the
interconnecting cables may store energy in their capacitance or inductance and release it suddenly if there is
a fault. The certificate for any interface device defines the maximum permitted "cable parameters".
Interface devices are usually designed to tolerate long cables and in practice, although the user should check,
there is very seldom any problem.
Electrical Area Classification
In USA the electrical area classification for petroleum facilities is usually defined by the requirement of NEC
70) , API 500 and NFPA 30 that are similar in content.
("A
Class I: Gases and Vapors
Division 1 : Gases and vapors can normally exist
Division 2: Gases and liquids normally confined
Class I, I1 and 111 are also used by NFPA to define the range of certain materials in categories based mainly
on flash points. Class TI and 111 materials generally do not provide sufficient vapors to require specification
of an electrically classified area, so areas are only defined by Class I flammable materials.
Flammable materials are also differentiated according to the spark energy needed to ignite them.
Group A: Acetylene
Control of Ignition Sources
147
Group B: Hydrogen and fuel gases containing >30% hydrogen, butadiene, ethylene oxide,
proplyene oxide, and acrolein
Group C: Ethyl ether, ethylene or gases of equivalent hazard
Group D: Acetone, ammonia, benzene, butane, cyclopropane, ethanol, gasoline, hexane,
methanol, methane, natural gas, naphtha, propane, or gases or vapors equivalent hazard
Surface Temperature Limits
Hazardous area apparatus is classified according to the maximum surface temperature produced under fault
conditions at an ambient temperature of 40 OC (104 OF) or as otherwise specified. Some desert locations
may produce ambient temperatures higher than 40 OC (104 OF) and suitable adjustments must be made in
these circumstances.
Rating
Degrees C (OF)
T1
T2
T2A
T2B
T2C
T2D
T3
T3A
T3B
T3C
T4
T4A
T5
T6
450
300
280
260
230
215
200
180
165
160
135
120
100
85
(842OF)
(572OF)
(536OF)
(500OF)
(446OF)
(419OF)
(392OF)
(356OF)
(329OF)
(320OF)
(275OF)
(248OF)
(212OF)
(185OF)
Class I1 and Class I11 areas are for Dust and Fibers respectively, and are typically not extensively used in the
hydrocarbon industries.
Classified Locations and Release Sources
Some typically defined classified locations are listed below, (when hydrocarbon materials are present):
Relief Valve Outlets (if discharge is to atmosphere)
Packing glands or seals on pumps and compressors
Pipe flanges, fittings and valve stems
Threaded fittings that are not seal-welded
Sample stations with an air break
Manways and piping connections to vessels
Piping to equipment connections
Vent and drain openings associated with hydrocarbon fluids or gases
Areas associated with hydrocarbon pumps bordered by three walls (where the walls are 1 meter (3
fi) high or >)
Drainage ditches, gulleys, trenches and associated remote impounding basins
Pits, sumps, open trenches and other below grade locations in a hazardous classified area
Laboratory hoods, ducting and storage rooms where hydrocarbon materials are handled
148
Handbook of Fire and Explosion Protection
Oily water gravity and pressure sewer systems
Ship, rail or truck loading facilities
Storage Tanks for flammable liquids
Pipeways at grade bordered by elevated road or dike walls 1 meter (3 ft) high or > on two
sides.
Pipeline scrapper traps stations
Drilling, wireline and workover rigs (including the mud pits)
Underground tanks or closed sumps (for collection of volatile liquids)
Container and portable tank storage
Container and portable tank filling stations
Gasoline dispensing and service stations
Tank vehicles and tank cars for volatile liquids
Emergency or Uninterruptible Power Supply Facilities - Battery room exhaust systems (if unsealed
batteries are present)
Analyzer Houses
Sewage Treatment (Air floatation units and Biological Oxidation units)
Cooling Towers (handling process water)
Protection Measures
Explosionproof Rated Equipment
Electrical devices that are in areas that may produce an ignition source to hydrocarbon vapors are
specified to prevent such occurrences and can be rated as "explosionproof'. Explosionproof rating
means that a device is rated to withstand an explosion of a specific gas or vapor that may occur
within it and prevent the ignition of ignition of a specific gas or vapor surrounding it. It also limits
the operating external temperature that a surrounding atmosphere will not be ignited. Various
enclosures, sealing devices and mechanisms are employed to achieve the desired rating for a
particular piece of equipment.
Intrinsically Safe Rated Equipment
Intrinsic safety is based on the principal of restricting the electrical energy available in hazardous
area circuits such that any sparks or hot surfaces that may occur as a result of electrical faults are
too weak to cause an ignition. The usehl power is about 1 watt, which is sufficient for most
current instrumentation. It also provides a personnel safety factor since the voltages are low and it
can allow field equipment to be maintained and calibrated "live" without the need for a gas free
environment verification. Electrical components or equipment can be manufacturer as intrinsically
safe and there readily usable in areas where combustible gases or vapors may be present.
Hermetically Sealed Electrical Equipment
Specifically designated electrical equipment can be manufactured so that its internal components are
completely sealed. This eliminates the possibility electrical arcing components or circuits can
contact combustible vapors or gases.
Purging
Electrical housings may be purged with an inert gas or air that flows at a sufficient rate to dilute the
atmosphere immediately around an energized circuit so that atmospheric released gases will be
Control of Ignition Sources
149
pushed away and will not be ignited.
Facilities that are required to be provided in hazardous locations but which provision of electrically
classified equipment is economically prohibitive or technically unavailable a pressurization location
is usually provided. The pressurization air is provided from a safe source and fitted with gas
detection devices for alarm and shutdown. Entranceways are fitted with air locks that are
technically still classified locations since they will let in hazardous vapors when opened. The air
locks should be fitted with ventilation to disperse any vapors that accumulate.
For enclosed areas, they can be considered adequately ventilated if they meet one of the following
(1) The ventilation rate provided is at least four times the ventilation rate required to dilute the
anticipated hgitive emissions to below 25 percent LEL as determined by detailed calculations
for the enclosed area.
(2) The enclosed area is provided with six air changes per hour by artificial (mechanical) means.
(3) If natural ventilation is used, 12 air changes per hour are obtained throughout the enclosed
area.
(4) The area is not defined as "enclosed per the definition of API Rp 500, Section 4.6.2.2.4.
Relocation of Devices
Many times it may easier to relocate electrical equipment outside an electrically classified area rather
than occur addition expense to obtain an explosionproof rating. For example most internal
combustion engines are not rated for hazardous atmospheres.
Surface Temperatures
Surface temperature of exposed equipment may pose the most readily available ignition source in
a hydrocarbon facility. Hot surfaces should be insulated, cooled or relocated, when they pose a
threat of ignition, to hydrocarbon release areas. Required equipment should be rated to operate
below the autoignitiion temperature of the gas or vapor that may be encountered.
Static
Static electricity can be formed in various locations in the process, storage and transfer operations
of a hydrocarbon facility. Experimental tests have generally demonstrated that saturated
hydrocarbon vapors and gases (under normal conditions), will ignite when approximately 0.25 millijoule of spark discharge energy is released. Some gases have even lower minimum energies as
indicated below.
Methane
Propane
Cyclopropane
Ethylene
Acetylene
Hydrogen
0.29
0.25
0.18
0.08
0.017
0.017
The essential requirement for protection against the effects of static electricity can be segregated into
three areas:
150
Handbook of Fire and Explosion Protection
(1) Identification of potential static electricity build up areas.
( 2 ) Measures to reduce the rate of static electricity generation.
(3) Provisions to dissipate accumulated static electricity charges.
The major generators of static electricity at hydrocarbon facilities are:
8
Flowing liquids or gases containing impurities or paticulates
Sprayed liquids
Liquid mixing or blending operations
Moving machinery
Personnel
If a gas contains liquid, water vapor or solid particles such as rust particles or dirt, a static charge can
be generated.
Generally static electricity can be overcome or controlled by several basic approaches - bonding,
grounding, and controlled generation.
Bonding tries to achieve a common electrical potential on all equipment so that a charge does not
have the opportunity to accumulate.
Most if not all hydrocarbon facilities are provided with a grounding grid. The primary purpose of the
grounding grid is to limit the effects of corrosion induced by charges but it also serves as a means to
dissipate electrical charges that could be a source of ignition. Grounding is the process of electrically
connecting one or more conducting objects to a ground potential.
Lightning
Lightning is generally considered a form of static electricity that is being
discharged from particles in the atmosphere. Many instances of lightning induced
hydrocarbon fires have been recorded, especially at atmospheric storage tanks.
NFPA requirements state that if equipment or process vessels, columns of tanks
are suitably constructed of substantial steel construction adequately grounded,
and do not give off flammable vapors, no other mechanism of lighting protection
is required. This is also true of flares, vent stacks and metal chimneys by nature
of their construction and grounding facilities.
Since most storage tanks release flammable vapors at seals and vents, they are susceptible to
lightning induced fires. Common European practice is to provide lightning rods on the highest
vessel at a facility to provide a cone of protection for the facility. NFPA 780 provides additional
guidance for the provisions of lightning protection measures.
Direct lightning strikes can ignite flammable contents of cone roof tanks unless the roof is provided
with bonding for the structural members. Floating roof tanks with seal hangers in the vapor space
may be ignited indirectly when changes on the roof are released by a nearby lightning stroke.
Floating roof tanks are commonly protected against lightning ignition by bonding the floating roof to
the seal shoes at not less than 3 meter (10 fi.) intervals, use of insulating section in the hanging
linkages, covering sharp points on hangers with insulating material and installation bonds across each
pinned hanger joint.
Buildings that are more than 15.2 meters (50 ft.) high, contain combustible liquids in large amounts
or store explosive materials should be provided with lightning protection measures according to the
requirements of NFPA 780.
Control of Ignition Sources
151
Ships with steel hulls or masts have suffered little or no damage from lightning and no special
protection measures are considered necessary. During the loading or unloading of vessels it is
common practice to suspend operations and close all openings into tanks during the appearance of
lightning storms.
Internal Combustion Engines
Internal combustion engines contain several features that pose ignition sources for hydrocarbon
vapors. Most obvious is they exhaust hot combustion gases that can ignite vapors, secondary they
have hot surfaces - primarily the exhaust manifold and piping, and finally and most overlooked,
instrumentation and ignition devices may not be rated for use in an area where combustible gases may
be present.
Spark Arrestors
Spark arrestors are provided at those locations where sparks may constitute a hazard to the surrounding
environment. The exhausts of internal combustion engines, incinerator stacks, and chimneys are normal
examples. It usually consists of screening material to prevent the passage of sparks or flying brands to the
outside atmosphere.
Hand Tools
AF'I has investigate the necessity of requiring non-sparking hand tools and the possible ignition risk. They
concluded that non-sparking hand tools would not signifidantly decrease the ignition potential from hand
tools. Hand tool operations in most instances will not produce enough spark energy for ignition plus
simultaneous gas release and sufficient spark generation from a hand tool is considered extremely low.
152
Handbook of Fire and Explosion Protection
Bibliography
1.
American Petroleum Institute (API), RP 14F. Design and Installation of Electrical Svstems for Offshore Production
Platforms, Third Edition, Washington, D.C., 1991.
2.
American Petroleum Institute (API), RP 500. Classification of Locations at Petroleum Facilities, First Edition,
Washington, D.C., 1991.
3.
American Petroleum Institute (API), RP 540. Electrical Installations in Petroleum Processin? Plants, Third Edition,
API, Washington, D.C., 1991.
4.
American Petroleum Institute (API), RP 2003. Protection Against Ignitions Arising out of Stati- Lightin9 and Stray
Currents, Fifth Edition, API, Washington, D.C., 1991.
5.
American Petroleum Institute (API), Publication 2214. Spark Imition of Hand Tools, Third Edition, API,
Washington, D.C., 1989.
6.
American Petroleum Institute (API), Publication 2216. Ignition Risk of Hydrocarbon Vapors by Hot Surfaces in the
Open Air, Second Edition, API, Washington, D.C., 1991.
7.
American Society for Testing of Materials (ASTM), D3284, Standard Test Method for Combustible Gases in the
Gas Space of Electrical Apparatus in the Field, ASTM, Philadelphia, PA, 1990.
8.
Bishop, D. N., Electrical Systems for Oil and Gas Production Facilities, Second Edition, Instrument Society of
America, Research Triangle Park, NC, 1992.
9.
British Standards Institute (BSI), BS 5345 Parts 1. 2. & 4, Code of Practice for the Selection. Installation and
Maintenance of Electrical Auuaratus for Use in Potentiallv Exulosive Atmosuheres, BSI, London, UK, 1983.
10. British Standards Institute (BSI), BS 6651-1992 - Code of Practice for Protection of Structures Against Lirrhting,
BSI, London, UK, 1992.
11. International Electrotechcal Commission IEC 79-4. Electrical Apuaratus for Explosive Gas Atmospheres, Second
Edition, 1975.
12. Institute of Electrical and Electronic Engineers, Inc. (IEEE), IEEE RP 484. Design and Installation of large Lead
Storage Batteries for Generating Stations and Substations, IEEE, New York, NY, 1987.
13. Institute of Petroleum (IP), Area Classification Code for Petroleum Installations, Model Code of Safe Practice, Part
15, IP, London, U.K., 1990.
14. Industrial Risk Insurers (IRI), IM.5.2, Lighting and Surge Protection, Hartford, CT.
15. Instrument Society of America (ISA), Recommended Practice RP 12.6, ISA, Research, Triangle Park, NC, 1987.
Explosion-Prone Areas for the Petroleum. Chemical and Related Industries, Noyes
16. Korver, W. 0. E., Classif
Publications, Park Ridge, NJ, 1995.
17. Magison, E.C., Electrical Instruments in Hazardous Locations, Third Edition, ISA, Research, Triangle Park, NC,
1978.
18. National Fire Protection Association (NFPA), NFPA 30, Flammable and Combustible Liquids Code, NFPA,
Quincy, MA, 1993.
19. National Fire Protection Association (NFPA), NFPA 70, National Electrical Code, NFPA. Quincy, MA, 1993.
20. National Fire Protection Association (NFPA), NFPA 77. Static Electricity, NFPA, Quincy, MA, 1988
Control of Ignition Sources
153
2 1. National Fire Protection Association (NFPA), NFPA 780. Lighting Protection Code, NFPA, Quincy, MA, 1992.
22. National Fire Protection Association (NFPA), NFPA 496, Standard for Purged and Pressurized Enclosures for
Eauipment, NFPA Quincy, MA, 1993.
23. National Fire Protection Association (NFPA), NFPA 497A. Classification of Class I Hazardous Locations for
Electrical Installation in Chemical Process Areas, NFPA, Quincy, MA ,1992.
24. National Fire Protection Association (NFPA), NFPA 497B. Classification of Class I1 Hazardous Locations for
Electrical Installations in Chemical Process 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.
~
Test Procedure for Large
27. Society of Automotive Engineers, (SAE), Recommended Practice J 342, S D X Arrester
Size Engines, 1991.
28. Society of Automotive Engineers, (SAE), Recommended Practice J 350. Spark Arrester Test Procedure for Medium
Size Engines, 1991.
29. Underwriters Laboratories Inc. (UL), UL 674, Safety Electric Motors and Generators for Use in Division 1
Hazardous (Classified) Locations, Third Edition, UL, Northbrook, IL, 1994.
30. Underwriter's Laboratories Inc. (UL),UL 886. Safety Outlet Boxes and Fittings for Use in Hazardous (Classified)
Locations, Tenth Edition, UL, Northbrook, IL, 1994.
31. Underwriter's Laboratories Inc. (UL), UL 894. Safety Switches for Use in Hazardous (Classified) Locations,
Seventh Edition, UL, Northbrook, IL, 1993.
32. Underwriter's Laboratories Inc. (UL), UL 913, Intrinsicallv Safe Apparatus and Associated Apparatus for Use in
Class I. I1 and 111. Division 1. Hazardous (Classified) Locations, Fourth Edition, UL, Northbrook, IL, 1988.
Chapter 15
Elimination of Process Releases
Atmospheric vapor releases or liquid spills within a petroleum or related facilities commonly occur every
day. They are a major source of the origin of catastrophic incidents. In order to provide an inherently safer
facility the common release of process vapors to atmosphere or liquids to grade within the facility should be
prevented or eliminated wherever practical. Not only does this improve the safety of a facility it also
decreases the amount of fugitive emissions or liquids that occur therefore decreasing any potential harm to
the environment. Containment of waste gases and liquids, human surveillance, increased testing, inspection
and maintenance, gas detection and adequate vapor dispersion features are all measures to lesson the
probability of an incident occurring.
The other common source of process releases is leakage. Contained hydrocarbons will not bum unless an
oxidizer is available, but once a leak is present adequate oxygen supplies are immediately available from the
air. To prevent explosions and fires the integrity of the plant must always be kept at its highest and
introduction of air supplies to closed systems must be eliminated.
Typically the following mechanisms can release a combustible vapor into the atmosphere during normal
operations
1 . Open tanks and containers.
2. Vents of storage tanks.
3. Safety valves, pressure relief valves, or vents which release to the flare or an atmospheric vent.
4. Glands of pumps and compressors.
5. Process system, vessel or tank drains.
6 . Oily water sewer (OWS), vents and drain funnels.
7. Pipeline pig traps and filters.
8. Sample points.
Process facilities should be designed so that, where practical, these exposed combustible vapors will not
exist. Methods of achieving this objective are defined below.
Methods of preventing air intrusion are:
Purging,
Inerting,
Flooding
154
Elimination of Process Releases
155
Inventory Reduction
In the event of a process or storage facility failure, immediate large quantities of hazardous
materials may be released before activation of protective detection and mitigation measures. This is
especially a concern where the continued fluid can rapidly vaporize or the material already exists as
a gas. In the petroleum industry these commodities generally include liquefied petroleum gas
O;PG), natural gas liquids (NGL), condensate, liquids with a high vapor pressure at operating
conditions and all combustible gases. Thus limits should be placed on the total isolatable inventory
for such materials in the process and storage systems. Based on historical data that suggest vapor
cloud explosions generally have not occurred for amounts less than 22,000 kgs (10,000 lbs), a limit
in the order of this magnitude should be considered for process areas where congestion is higher. If
highly volatile and hazardous materials in highly congested areas are involved, lower limits should
be considered, (e.g., 4,400 kgs (2,000 lbs.)).
Vents and Relief Valves
All waste hydrocarbon gases (vents, relief valves, and blowdowns) should be routed to a flare or
returned to the process through a closed header system. Release of vapors to atmosphere may
produce a vapor cloud, and even through the release may be remote from the facility it may drift or
the effects of ignition (i.e., blast overpressure) of the cloud will be felt at the facility.
Atmospheric storage tanks are normally fitted with pressure-vacuum relief valves to reduce vapor
emission and evaporation losses to atmosphere.
Sample Points
Sampling techniques should use a closed system. ,Open vessel collection means should be avoided
as spillage may occur due to the container mishandling or inappropriate operation of the sample
valve. Open sampling may also lead to inaccurate results since volatile portions of the sample may
be dispersed during the sampling process. Automatic sampling methods are commonly available
which eliminate the need of manual hand sampling processes.
If open sampling is provided, the sampling point should be located where adequate dispersion of
released vapors will occur. The sampling point should be located so it is easily accessible so human
error factors are reduced.
Drainage Systems
Process equipment liquid drains should be provided with a sealed drainage system where it is
practical and backpressure from the system or containmenation is not a concern. Open drain ports
should be avoided and separate sewage and oil water drains provided. Surface drainage should be
provided to remove liquid spills immediate and effectively from the process area. Vents on
drainage systems should be elevated so as to freely disperse hydrocarbon gases above congested
areas that could be released from the system.
Storage Facilities
With proper safety precautions and operating procedures the occurrence of explosions in the vapor
space of fixed roof storage tanks are a very rare event. A frequency estimate of an explosion once
in every 1,000 years, per tank, has been stated. Explosive mixtures may exist in the vapor space of
a tank unless precautions are taken. Any vapor will seek an ignition source, so prevention of
ignition cannot be guaranteed. This is especially true with liquids that have low conductivity that
156
Handbook of Fire and Explosion Protection
will allow static charges to build up on the liquid. Precautions to safeguard against internal tank
explosions, include insuring air does not enter the vapor space for tanks containing combustible
liquids above their flash points. This is commonly achieved with production gas or with an inert
gas such as nitrogen.. A safer an in the long term more economical approach is to place the liquid
in a floating roof tank.
Floating roof storage tanks are inherently safer than fixed roof tanks as they essentially eliminate
the creation of a vapor space in the tank above the hydrocarbon liquid. Floating roof tanks float on
the stored product and rise and fall as the inventory changes. They limit the area of vapor release
to the circumferencial seal. Low flash point liquids should always be stored in tanks which will not
allow the creation of vapors in sizable quantities. Floating roof tanks are twice as expensive to
construct as fixed roof tanks so there is a trade off of risk against cost. However by reducing
emissions the increased cost can be justified on the basis of reduced product loss through
evaporation (a product savings) and impact to the environment.
Floating roof tanks, both internal and open top are constructed with a circumferencial seal to allow
the roof to rise and fall. A single seal will allow some vapors to escape. However, recent
environmental practice is to provide a secondary seal over the first seal, which provides additional
mitigation against 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 probability
of a tank fire.
Atmospheric fixed roof tanks built according to API requirements will have a weak seam at the
junction of the roof with tank side. If there is internal overpressure, such as an explosion, the seam
will part or the roof blows off, leaving the shell in place to retain its contents. The resulting fire
will therefore only initially involve the exposure surface of the liquids still in the tank.
Pump Seals
Rotating pump shafts require a means to seal the circulating fluid from escaping but still allow the
pump shaft to rotate. As the pump seal wears or more volatile products are handled the more
difficult it is to prevent leakage through the seal. Historically the industry has much evidence of the
problems with pumps seals and fire hazards areas are required on almost all pumps handling
hydrocarbon products. Double seals with alarm indications are provided to mitigate the
consequences of a pump seal failure instead of single-mechanical (rope) seals.
Vibration Stress Failure of Piping
In a review of petroleum industry release incidents, one of the contributing factors is the
metallurgical failure 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 to
the rotation force it generates. Although the equipment itself is restrained, it still induces stress in
the connecting pipework that is normally not observed. Since the small diameter piping is not as
substantial as the main pipework, usually less attention is made to its restraint. However because
of this it is the most vulnerable location for a failure at rotating equipment. The failure point is
usually at the connection point of the small diameter line to the main line, where it has the stress
location from the "loose end" of the small line.
Elimination of Process Releases
157
For existing equipment a vibration measure survey should be undertaken or examination of piping
suspected of being under stress. Critical examination of connection points should be made where
the induced piping vibration stress is the greatest. For new designs a stress analysis can be
prepared on the pipework by specialized consultants.
Rotating Equipment
Turbines, compressors, gearboxes, blowers and alternators may suffer damage from bearing failure,
inadequate lubrication, blade or diffiser failure, vibration or coupling failures. These failures can
lead to the release of lubricants, combustible liquids or gases that can ignite causing an explosion or
fire. Additional monitoring and equipment shutdown capabilities should be provided in these cases.
Consultation with the manufacturer and the selected application results in the prudent
instrumentation and shutdown logic that should be adopted. In cases where large quantities of
volatile hydrocarbons may be released, the provision of gas detection should be considered.
158
Handbook of Fire and Explosion Protection
Bibliography
1.
American Petroleum Institute (API), Manual of Petroleum Measurement Standards, Chapter 8.2, Automatic
Sampling of Petroleum and Petroleum Products, First Edition, API Washington, D.C., 1987.
2.
American Petroleum Institute (API), Standard 620, Desim and Construction of Large. Welded Low Pressure
Storage Tanks, Eighth Edition, API Washington, D.C., 1990.
3.
American Petroleum Institute (API), Standard 650. Welded Steel Tanks for Oil Storage, Ninth Edition, API
Washington, D.C., 1993.
4.
American Petroleum Institute (API), Bulletin 2521, Use of Pressure-Vacuum Vent Valves for AtmosDheric Loss,
API Washington, D.C., 1993.
5.
National Fire Protection Association (NFPA), NFPA 15, Fixed Water Spray Systems, NFPA, Quincy, MA., 1990.
6.
National Fire Protection Association (NFPA), NFPA 30, Flammable and Combustible Liquids Code, NFPA,
Quincy, MA., 1993.
Chapter 16
Fire and Explosion Resistant Systems
The petroleum and related industries deal with tremendous bulk quantities of flammable and combustible
materials 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 complacent
about their destructive natures and the required protective arrangements that must be instituted whenever
they are handled.
Fire and explosion resistant materials and barriers for critical equipment or personnel protection should
always be considered whenever petroleum operations are involved. They prolong or preserve the integrity
of a facility critical features to ensure a safe and orderly evacuation and protection of the plant is
accomplished.
Ideally most oil or gas incidents will be controlled by the process shut down systems (ESD, depressurization,
drainage, etc.) and hopefit1 the 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 explosions
have previously occurred. Before any consideration of fire suppression efforts, explosion effects must first
be analyzed to determine the extent of protection necessary. Most major fire incidents associated with
hydrocarbon process incidents are preceded by explosion incident.
Explosions
Explosions are the most destructive occurrence that can transpire at a hydrocarbon facility. Explosions may
happen too quickly for conventional fire protection systems to be effective. Once an explosion occurs
damage may result from several events:
1. Overpressure - the pressure developed between the expanding gas and it's surrounding
atmosphere.
2. Pulse - the differential pressure across a plant as a pressure wave passes might cause collapse or
movement.
3. Missiles - items thrown by the blast of expanding gases might cause damage or escalation.
Explosion overpressure levels are generally considered the most critical measurement at this time. Estimates
are normally prepared on the amount of overpressure that can be generated at various damaging levels.
159
160
Handbook of Fire and Explosion Protection
These levels are commonly referred to as overpressure circles. Overpressure circles are normally drawn
from the point of ignition that is typically taken for sake of expediency and highest probability as the point of
leakage or release unless other likely ignition points are identified.
Definition of Explosion Potentials
The first step in protection against explosions is to identifir if they have the possibility of occurring at the
facility and to acknowledge that fact. This may be for both internal and open air explosions. Once it is
confirmed an estimate of their probability and severity should be defined by a risk analysis. If the risk level is
indicated as unacceptable additional measures for prevention and mitigation should be implemented.
Typical locations where explosion overpressure potentials should be considered or evaluated are:
Gases stored as liquid due to the application of refrigeration or pressure.
Flammable or combustible liquids existing above atmospheric boiling point and maintained as a
liquid because of the application of pressure.
Gases contained under a pressure of 3,448 kPa (500 psi) or more.
Any combination of vessels and piping that has the potential to release a total volume containing
more than 907 kgs (2,000 lbs.) of hydrocarbon vapors.
Onshore areas that are considered to have confinement (hlly or partially) and may release
commodities meeting the above criteria.
Locations which may have a manned control room less than 46 meters (150 fit.)from a process
area meeting the above criteria.
Gas compressor buildings that may be hlly or partially enclosed.
Enclosed buildings handling fluids that have the potential to accumulate flammable gases (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 to
experience the hazardous effects of an explosion and, if so, to mitigate the results of these explosions. The
calculations can also serve to demonstrate where mitigating measures are not needed due to the lack of a
potential to produce damaging overpressures either because low explosion effects or distance from the
explosion for the facility under evaluation.
As an aid in determining the severity of vapor cloud explosions, overpressure radius circles are normally
plotted on a plot plan from the source of leakage or ignition. These overpressure circles can be determined
the levels at which destructive damage may occur to the facility from the worst case credible event (WCCE).
Facilities that are deemed critical or highly manned should be relocated out of the overpressure circles from
which 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 explosive
protective design arrangements. Figure 8 shows an example of a typical plot of overpressure circles for a
hydrocarbon processing facility.
Fire and Explosion Resistant Systems
161
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Handbook of Fire and Explosion Protection
Explosion Protective Design Arrangements
Explosion suppression systems are being offered on the commercial market for small enclosures, based on
powder and Halon extinguishing agents. These systems have some disadvantages that must be considered
before being applied at any facility. A leak may continue for some time and the ignition source is usually not
likely to dissipate. Re-ignition of the gas cloud is a high risk with "one shot" systems. For large enclosures,
a tremendous volume of the suppression agent is necessary and therefore there is point of diminishing return
for the protection system (Le., cost versus benefit).
Research on water explosion inhibiting systems is providing an avenue of future protection possibilities
against vapor cloud explosions. British Gas experimentation on the mitigation of explosions by water
sprays, shows that flame speeds of an explosion may be reduced by this method. The British Gas research
indicates that small droplet spray systems can act to reduce the rate of flame speed acceleration and
therefore the consequential damage that could be produced. Normal water deluge systems appear to
produce too large a droplet size to be effective in explosion flame speed retardation and may increase the air
turbulence in the areas.
The following are typical design practices that are employed to prevent vapor cloud explosions.
a. All hydrocarbon areas should be provided with maximum ventilation capability. Specific
examinations should be undertaken at all areas where the hazardous area classification is defined
as Class 1 Division 1 or Class 1 Division 2. These are areas where hydrocarbon vapors are
expected to be present, so verification that adequate ventilation is provided to aid in the
dispersion of combustible vapors is a necessity.
The following practices are preferred:
Enclosed spaces are avoided.
Enclosed locations will not receive adequate ventilation and could allow the build-up
of combustible vapors or gases. Vapors with heavy densities can be particularly
cumbersome as they will seek the low areas that are normally not provided with fresh
air circulation.
Installation of walls and roofs are used only where necessary (including firewalls)
Walls or roofs tend to block vision and access, trap sand, debris, and reduce
ventilation so that flammable vapors are not as quickly dispersed. They may also
collapse if there is an explosion or deflagration. They can therefore contribute to
secondary effects by falling onto pipes an equipment that may substantially exceed
damage from the original explosion or deflagration. They can also lead to a false
sense of 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 or
explosion barrier, otherwise ventilation requirements will prevail.
b. Area congestion should be kept to a minimum.
Vessels should be orientated to allow maximum ventilation or explosion venting.
Bulky equipment should not block air circulation or dispersion capability.
Fire and Explosion Resistant Systems
163
c. Release or exposure of flammable vapors to the atmosphere should be avoided.
Waste hydrocarbon gases (process vents, relief valves, and blowdowns) should be
routed to the flare or returned to the process through a closed header where practical.
Sampling techniques should use a closed system.
Process equipment liquid drains should use a sealed drainage system.
Open drain ports should be avoided and separate sewage and an oily water drain
system should be provided.
Surface drainage should be provided to remove spills immediately and effectively from
the process area.
d. Gas Detection is provided, particularly to areas handling low flash point materials with a
negative or neutral buoyancy (i.e., vapor density is 1.0 or less), since these have the highest
probability to collect or resistance to 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 of
work. Inclusion of air inside a process will as some time for a flammable atmosphere that will
explode once an ignition source is available.
f. Protective devices are located outside hazardous areas or behind protective barriers.
g. Semi or permanently occupied buildings required in or adjacent process areas are constructed to
withstand expected explosion overpressures. Nonessential personnel or facilities are relocated
areas which are not vulnerable to explosions.
Vapor Dispersion Enhancements
Water Sprays
Water spray systems have been demonstrated to assist in the dispersion of vapor releases. The sprays
assist in the dilution of the vapors with the induced air currents created by the velocity of the
projected water particles. They cannot guarantee that a gas will reach an ignition source but do
improve that probabilities that dispersion mechanisms will be enhanced.
Air Cooler Fans
Large updraft air cooler fans create induced air currents to provide cooling for process requirements.
These air coolers create a considerable updraft that ingests the surrounding atmosphere and disperses
it upwards. Judicious placement of fans during the initial plant design can also serve a secondary
purpose of aiding the dilution of combustible vapors during an accidental release.
Location Optimization Based on Prevailing Winds
Equipment that normally handles large amounts of highly volatile products should be placed so that
the prevailing wind direction will disperse releases to locations that would not endanger other
equipment or provide for an ignition source for the released material.
Supplemental Ventilation Systems
Enclosed locations that may be susceptible to build up of combustible gases are typically provided
with ventilation systems that will disperse the gases or provide sufficient air changes to the enclosures
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Handbook of Fire and Explosion Protection
such that gas leakages will not accumulate. Typical examples are battery rooms, gas turbine
enclosures, offshore enclosed modules, etc.
Damage Limiting Construction
Various methods are available to limit the damage from the effects of an explosion. The best options
are to provide some pre-installed or engineered features into the design of the facility or equipment
that 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 the
risk analysis estimates of the WCCE incident.
Where enclosed spaces may produce overpressures blow out panels or walls are provided to relieve
the pressure forces. The connections of the panel are specified at a lower strength that normal panels
so it will fail at the lower level and relieve the pressures. Similarly, combustible or flammable liquid
storage tanks are provided with weak roof to shell seams so that in case of an internal explosion, the
built-up pressure is relieved by blowing off the roof and the entire tank does not collapse.
For exposed buildings at onshore facilities, heavy monlithic concrete construction is used.
Entranceways are provided with heavy blast resistance doors. that do not face the exposed area.
Fireproofing
Following an explosion incident, local fires develop which it left uncontrolled, result in a
conflagration of the entire facility and its destruction. Fire protection measures are provided as
required to control these occurrences. The ideal fire protection measure is one that does not require
addition action to implement and is always in place. These methods are considered passive
protection measures and the most familiar is fireproofing.
It has been demonstrated that steel strength decreases rapidly with temperature increases above 260
OC (500 OF). At 538 OC (1000 OF), its strength both in tension and compression is approximately
half, at 649 OC (1200 OF) its strength decreases to less than one quarter. Bare steel exposed to
hydrocarbon fires may absorb heat at rates from 10,000 to 30,000 Btu/hr/sq. A.,depending on the
configuration of the exposure. Due to the high heat conduction properties of steel, it is readily
possible for normally loaded steel members or vessels to lose their strength to the point of failure
within ten minutes or less of a hydrocarbon fire exposure.
In a strict sense, fireproofing is a misnomer, as nothing is entirely “fireproof”. In the petroleum and
related industries the term fireproofing is commonly used to refer to material that is resistive to a
certain set of fire conditions for a specified time. The basic objective of fireproofing is to provide a
passive means of protection against the effects of fire to structure components, fixed property or to
maintain the integrity of emergency control systems or mechanisms. Personnel shelters or rehges
should not be considered adequately protected with fireproofing unless measures to provide fresh air
and protection against smoke and toxic vapor inhalation is also provided. In itself fireproofing should
also not be considered protection against the effects of explosions, in fact quite the opposite may be
true, fireproofing may be just as susceptible to the effects of an explosion, unless specific
arrangements have be stipulated to protect it from the effects of explosion overpressures.
Fireproofing for the petroleum and related industries follow the same concept as other industries
except that the possible fire exposures are more severe in nature. The primary destructive effects of
fire in the petroleum industry is very high heat, very rapidly, in the form of radiation, conduction and
convection. 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
165
purposes of fireproofing applications. Fireproofing is not tested to prevent the passage of toxic
vapors or smoke, other barriers must be installed to prevent the passage of these. The collapse of
structural components in itself is not of high concern, as these can usually be easily replaced. The
concern of structural collapse is the destruction of the items being supported and the impact damage
and spread of large quantities of combustible fluids or gases they might release to other portions of
the facility. Where either of these features might occur that would have high capital impact, either in
immediate physical damage or a business interruption aspect, the application of fireproofing should be
considered. Usually where essentially only piping is involved, which would not release enormous
amounts of combustible materials, fireproofing for pipe racks is not economically justified. Common
piping and structural steel normally can be easily and quickly replaced. It is usually limited to
locations where equipment that requires a long replacement time might be damaged if the rack
collapsed or are supportive of emergency incident control function, such as depressuring and
blowdown headers that are routed to the flare.
The primary value of fireproofing is obtained in the very early stages of a fire when efforts are
primarily directed at shutting down processes, isolating fie1 supplies to the fire, actuating fixed or
portable fire suppression equipment and conducting personnel evacuation. If equipment is not
protected, then it is likely to collapse during this initial period. This will cause firther impact damage
and 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 containing hydrocarbon inventories, can rupture or collapse causing a conflagration of the entire
facility.
It is theoretically possible, based on the assumption of the type of fire exposure (i.e., pool, jet, etc.)
to calculate the heat effects from the predicted fire on every portion of petroleum facility. As of yet
this extremely costly and cannot be performed economically for an entire facility.
What is typically applied, is the standard effects of a petroleum fire (i.e., a risk exposure area is
defined) for a basic set of conditions that is used for most locations in a facility. If necessary
examinations of critical portions of a facility for precise fire conditions are then undertaken by
theoretical calculations. In general the need for fireproofing is typically defined by identifying areas
where equipment or processes can release liquid or gaseous he1 that can burn with sufficient intensity
and duration to result in substantial property damage. In the petroleum industries these locations are
normally characterized by locations with a high liquid holdups or pressures historically having a
probability of release and high pressure gas release sources.
Typical locations where fire risk exposures are consider prevalent are:
(1)
(2)
(3)
(4)
(5)
Fired heaters
Pumps handling hydrocarbon materials
Reactors
Compressors
Large hydrocarbon inventory vessels, columns, and drums
Additionally whenever equipment is elevated, which could be source of liquid spillage, long down
time for replacement, or supports flare or blowdown headers in a fire exposure risk area, fireproofing
of the supports is normally applied. API Publication 2218 provides firther guidance on the exact
nature of items and conditions that the industry considers prudent for protection.
A standard fire duration (e.g., 2 hours) is applied and a high temperature fire (Le., UL 1709) is
normally assumed from the hydrocarbon release sources.
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Handbook of Fire and Explosion Protection
The following material aspects should be considered which application of fireproofing is
contemplated:
- Fire performance data (fire exposure and duration)
- Costs (material, installation labor and maintenance)
- Weight
- Explosion resistance
- Mechanical strength (resistance to accidental impacts)
- Smoke or toxic vapor generation (when life safety is associated with protection)
- Water absorption
- Degradation with age
- Application method
- Surface preparation
- Curing time and temperature requirements
- Inspection method for coated surface
- Thickness control method
- Weather resistance
- Corrosivity
- Ease of repair
Fireproofing Specifications
Typically fireproofing materials are specified for either cellulosic (ordinary) or hydrocarbon
(petroleum) fire exposures at various durations. The essential feature of the fireproofing is that it
does not allow the passage of flame or heat and therefore can protect against structural collapse for
certain conditions. Because fireproofing is nomially not tested to prevent the passage of smoke or
toxic vapors it's use to provide protection for human habitation should be carefully examined, in
particular the effects of the passage of smoke and lack of oxygen in the environment. It should be
bore in mind that fireproofing is tested to a set of basic standards. These standards cannot be
expected to correlate to every fire condition that can be produced in a petroleum facility. The
spacing, configuration, and arrangement of any hydrocarbon process can render the application of
fireproofing inadequate for the fire duration if the fire intensity is higher than the rating of the
fireproofing. Fire resistance enclosures should not only be rated for protection against the predicted
fire exposure but to ensure the continued operation of the equipment being protected. For example if
the maximum operating temperature of a valve actuator is only 100 OC (212 OF), ambient
temperature limits inside the enclosure should be allowed to rise above, even though the fireproofed
enclosure has met the requirements of a standard fire test. The operating requirements for emergency
systems must always be bore in mind.
There are a number of fire test laboratories in the world that can conduct fire tests according to
defined standards and on occasion specialized tests. Table 17 provides a list of the test agencies
recognized by the petroleum and related industries.
Fire and Explosion Resistant Systems
167
Table 17
Recognized Fire Testing Laboratories
Structural steel begins to soften at 316 OC (600 OF) and at 538 OC (1,000 OF) it loses 50% of its
strength. Therefore the minimum accepted steel temperature for structural tolerance is normally set
to 400 OC (752 OF) for a period of 2 hours, exposed to a high temperature hydrocarbon (;.e.,
petroleum) fire (Ref. UL Standard 1709).
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Handbook of Fire and Explosion Protection
1200
1000
800
Temperature
600
(Degree C)
I
400
+Hydrocarbon
+Cellulosic
Fire
Fire
I
200
0
0 Hrs. 0.17
0.34
0.5
0.67
0.84
1.0
Hm.
1.17
1.34
1.5
1.67
1.84
Time
Figure 9
Time Temperature Curves for Petroleum versus Cellulosic Fires
(Degrees Celsius versus Time in Minutes)
2.0
HE.
Fire and Explosion Resistant Systems
169
Recent experiential work suggests that heat flux is a more realistic method of determine the heat
transmission into fire barriers. Typical heat flux values of 30-50 kwhq. m (9,375 - 15,625
Btu/sq./fi.) for pool fires and 200-300 kw/sq./m (62,500 - 93,750 Btu/sq. ft.) for jet fires is normally
the basis of heat flux exposure calculations.
Fireproofing Materials
There are numerous fireproofing materials available on the marketplace and the selection of the
material involved is based on the application and advantages versus disadvantages of each over an
economic factor. Usually no single material is ideally suited for a particular application, and an
evaluation of the cost, durability, weatherability, and combination of factors is necessary.
Cementitious Materials
Cementitious materials use a hydraulically setting cement such as Portland cement as a binder with
a filler material of good insulation properties, e.g., verminculite, perlite, etc. Concrete us frequently
used for fireproofing because it is easily installed, readily available, is quite durable and generally
economical compared to other methods. It is heavy compared to other materials and requires more
steel to support that other methods.
Pre-formed Masonry and Inorganic Panels
Brick, concrete blocks, or pre-cast cement aggregate panels have been commonly used in the past.
These materials tend to be labor intensive to install and are less economical than other methods.
Metallic Enclosures
Stainless steel hollow panels filled with mineral wool are fabricated in precise dimensions to
withstand the specified fire exposure. Typically electrical equipment must operate within a
specified level for a period of time when a fire exposure occurs and is protected by such enclosures.
Thermal Insulation
These can be inorganic materials such as calcium silicate, mineral wool, diatomaceous earth or
perlite 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 to
tire barrier for the blockage of heat transfer.
Intumenscent Coatings
Intumenstent coatings have an organic base that, when subjected to a fire, will expand and produce
a char and underlying insulating layer.
Refractorv Fibers
Fibrous materials with a high melting point are used to form fire resistant boards and blankets. The
fibers are derived from glass minerals or ceramics. They may be woven into cloths and are used as
blankets around the object to be protected.
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Table 18
Passive Fire Protective Systems
The principle features of passive protection are summarized below:
Advantapes
- No initiation required.
- Immediate protection with low conductivity materials, reactive materials respond when threshold
temperature is reached.
- No power required.
- Meet regulatory requirements.
- Low maintenance.
- Can be upgraded.
- Certain materials can provide anti-corrosion benefits.
-
No periodic testing required.
Disadvantages
- Provide only short duration protection when compared to active systems.
- Not renewable during or after a fire.
- Inspection of substrate for permanent materials for corrosion can be difficult.
-
Choice Determined bv:
- Application.
- Protection required
- Performance.
- Physical properties.
- Costs.
Fire and Explosion Resistant Systems
171
Composite Materials
Lightweight Composite proprietary materials, typically of glass fiber and polyester resins, are
available as sheet boards which can be arranged into protective walls or enclosures. They offer
light weight, inherent insulation, and can be configured to achieve blast protection. These materials
are corrosion free, and wear resistant.
Radiation Shields
In some cases radiation shields are provided to protect against heat effects from fire incidents and operation
requirements. The shields usually are of two styles either a dual layer wire mesh screen or a plexy-glass see
through barrier. The shields provide a barrier from the effects of radiant heat for specific levels. They are
most often used for protection against flare heat and for bamers at fixed firewater monitor devices, most
notably at the helidecks of offshore facilities.
Water Cooling Sprays
Water sprays are sometimes used instead of fireproofing where the fireproofing application may be
considered detrimental to the situation or uneconomical to achieve. Typical examples are the surface of
pressure vessels or piping where metal thickness checks are necessary, structural facilities that cannot
accept additional loads of fireproofing materials due to dead weight or wind loads, inaccessibly of the
surface for application of fireproofing, or impracticability of fireproofing application.
Normally where it is necessary, fireproofing is preferred over water spray for several reasons. The
fireproofing is a passive inherent safety feature, while the water spray is a vulnerable active system that
requires auxiliary control to be activated. Additionally the water spray relies on supplemental support
systems that may be vulnerable to failures, Le., pumps, distribution network, etc. The integrity of
fireproofing systems is generally considered superior to explosion incidents compared to water spray piping
systems. The typical application of water sprays in place of fireproofing is for vessel protection.
The water spray protects the exposure by:
(1.) Cooling the surface of the exposure.
(2.) Cooling the atmosphere surrounding the exposure and from the source.
(3.) Limiting the travel of radiant heat from flames to adjacent exposures.
Vapor Dispersion Water Sprays
Fire water sprays are sometimes employed as an aid to vapor dispersions. Some literature on the subject
suggests two mechanisms are involved that assist in vapor dispersions with water sprays. First, a water spray
arrangement will start a current of air in the direction of the water spray. The force of the water spray
engulfs air and dispenses it hrther from its normal circulating pattern. In this fashion released gases will also
be engulfed and directed in the direction of nozzles. Normal arrangement is to point the water spray upward
to direct ground and neutral buoyancy vapors upwards for enhanced dispersion by natural means at higher
levels. Second, a water spray will warm a vapor to neutral or higher buoyancy to also aid in its natural
atmospheric dispersion.
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Handbook of Fire and Explosion Protection
Locations Requiring Consideration of Fire Resistant Measures
The application of fire resistant materials is commonly afforded to locations where large hydrocarbon
spillages or high pressure high volume gas releases may occur with a high probability (ie. fire hazardous
zones). These locations commonly are associated with rotating equipment and locations where high
erosiordcorrosion effects could occur. Alternatively fireproofing materials are used to provide a fire barrier
where adequate spacing distances are unavailable (Le., offshore installations, escape measures, etc.). A P I
Publication 2218 provides hrther guidance in the application and materials used in the industry.
0
Onshore
Vessel, tank and piping supports in fire hazardous zones.
Critical services (ESD valves, control and instrumentation).
Pumps and high volume or pressure gas compressors.
0
Offshore
Hydrocarbon processing compartments.
Floors, walls, roofs for accommodations.
Structural support located in fire hazardous zones.
Room doors and windows.
Pump and high volume or pressure gas compressors
0
Common Petroleum Industry Fireproofing Material Applications
Vessel and Pipe Supports:
Onshore: 2 inches of Concrete; UL 1709,2 hour rating
Offshore: Ablative or intumensent materials, UL 1709, 2 hour rating
Cable Trays: Stainless steel cabinets or fire rated mats, UL 1709, 20 minute rating
ESD Control Panels: Stainless steel cabinets or fire rated mats, UL 1709,20 min. rating
EIVs: (If directly exposed) -Stainless steel cabinets or fire rated mats UL 1709, 60 min.
EIV actuators: Stainless steel cabinets or fire rated mats UL 1709, 20 minute rating
Firewalls:
Onshore: Concrete or masonry construction, UL 1709, 2 hour rating
Offshore: Ablative, composite or intumensent, UL 1709, 2 hour rating
Flame Resistance
Interior Surfaces
Most building fire codes set fire resistive standards for interior wall and ceiling finishes and overall
requirements for building construction fire resistance features. Based on fire statistics, the lack of
proper control over an interior finish is second only to the vertical spread of fire through openings
in floors as the cause of loss of life in buildings. The dangers of unregulated interior finish materials
are mainly: (1) The rapid spread of fire presents a threat to the occupants of the building by either
limiting or delaying their use of exitways within and out of a building. The produciton of dense
black smoke also obscures the exit path and exit signs. ( 2 ) The contribution of additional fuel to a
fire. Unregulated finish materials have the potiential for adding fuel to the fire, thereby increasing
its intensity and shortening the time available for occupants to escape. The intent of most building
fire codes is to regulate only the interior finish of materials on walls and ceilings and not to regulate
floor coverings since experience tells that traditional type of interior finish materials such as wood,
vinyl tile, linoleum, and other resilient floor covering materials do not contribute to the early spread
of fire.
Fire and Explosion Resistant Systems
173
Electrical Cables
Electrical conductors are normally insulated for protection and avoidance of electrical shorting.
Typical insulating materials are plastics that can readily burn with toxic vapors. The NEC specifies
certain fire resistant rating to electrical cables to lessen the possibility of cable insulation ignitability
and fire spread.
Optical fiber cables
The increasing use of fiber optics for electronic communications poses critical communications
risks. The fire resistant requirements of fiber optical cables are currently similar to the requirements
of fire resistant ratings applied to electrical cables within the specifications of the NEC.
Fire Dampers
Fire dampers are an assembly of louvers that are arranged to close to prevent the passage of flame
and heat. Dampers are installed in ventilation openings or shafts to provide a fire rated barrier
equal to the surrounding barrier. They are activated by spring release by the melting of a fbsible
link. or by remote control signals.
Acceptance testing of fusible link fire dampers should always include a random sample actual
fusible link (melting) test of the installed assembly that causes the damper to close. Many times an
improperly installed damper will not close correctly and the shutter louvers become hung up or
twisted. An alternative sometimes available is a link assembly that can be temporary installed that is
easily cut by a pair of clippers. The fbsible link melting temperature can then be tested separately at
a convenient location without subjecting the installation heat or flames for testing purposes.
Smoke Dampers
Smoke dampers are used to prevent the spread of products of combustion within ventilation
systems. They are usually activated by the fire alarm and detection system. Smoke dampers are
specified on the leakage class, maximum pressure, maximum velocity, installation mode (horizontal
or vertical) and degradation test temperature of the fire.
Flame and Spark Arrestors
Flame arrestors stop the flame propagation from entering through the opening. The device
contains an assembly of perforated plates, slots, screens, etc., enclosed in a case or frame that
absorb the heat of flame entering and thereby extinguish it before can pass. When burning occurs
within a pipe, some of the heat of combustion is absorbed by the pipe wall. As the pipe diameter
decreases, an increasing percentage of the total heat is absorbed by the pipe wall and the flame
speed in the pipe decreases. By using very small diameter (one or two millimeters), it is possible to
completely prevent the passage of flame, regardless of flame speed. A typical flame arrestor is a
bundle of small tubes, which achieves the required venting capacity but prevents the passage of
flame. The "Davy" miners lamp was the first use of flame arrestor in which a fine mesh screen of
high heat absorption properties was placed in front of the flame of the miner lamp to prevent
ignition of methane gas in coal mines.
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Handbook of Fire and Explosion Protection
Research has shown that pressure-vacuum vents are just as effective as flame arrestors for storage
tanks against internal ignitions.
Spark arrestors are provided on the exhaust of source or fire where a hot particulate might be
released (Le., internal combustion engines, chimneys, incinerator stacks, etc.). The spark arrestor
consist of a fine metal screen to prevent the particulate matter from being released from the exhaust
mechanism.
Piping Detonation Arrestors
Pipe detonation arrestors are provided where there is a possibility of highly accelerating flame fronts within
piping systems due to poor piping designs to prevent such occurrences.
Fire and Explosion Resistant Systems
175
Bibliography
1.
A. D. Little, Inc., Evaluation of LNG Vauor Control Methods, American Gas Association (AGA), Arlington, VA,
1974
2.
American Institute of Chemical Engineers (AIChE), Guidelines for Vapor Release Mitigation, AIChE, New York,
NY, 1988.
3.
American Institute of Chemical Engineers (AIChE), Guidelines for Use of Vapor Cloud Dispersion Models, AIChE,
New York, NY, 1987.
4.
American Iron and Steel Institute (AISI), Fire Safe Structural Steel, AISI, Washington, D.C., 1979.
5.
American Petroleum Institute (API), RP-521. Guide for Pressure-Relieving and Depressuring Svstems, Third
Edition, API, Washington, D.C., 1990.
6.
American Petroleum Institute (API), Publication 22 18, Fireproofin? Practices in Petroleum and Petrochemical
Processing Plants, First Edition, API, Washington, D.C., 1988.
7.
American Petroleum Institute (API), Standard 2508. Design and Construction of Ethane and Ethvlene Installations
at Marine and uiueline Terminals. Natural Gas Processing Plants. Refineries, Petrochemical Plants and Tank Farms,
Second Edition, API, Washington, D.C. 1985.
8.
American Petroleum Institute (API), Standard 2510 Design and Construction of Liquefied Petroleum Gas
Installations. (LPG), Sixth Edition, API, Washington, D. C., 1989.
9.
American Petroleum Institute (API), Publication 25 10A Fire Protection Considerations for the Design and
Operation of Liquefied Petroleum Gas (LPG) Storaye Facilities, First Edition, API, Washington, D. C., 1989.
10. American Society of Civil Engineers (ASCE), ASCE 78-92. Structural Fire Protection, ASCE, New York, NY,
1992.
11 American Society of Testing Materials (ASTM), E- 119, Method of Fire Tests of Building Construction and
Materials, ASTM, Philadelphia, PA.
12 British Standards Institute, BS 7244. Flame Arrestors for General Use, BSI, London, U.K.
13 Bodurtha, F.T., Industrial Explosion Prevention and Protection, McGraw-Hill, New York, NY, 1980.
14 Industrial Risk Insurers (IRI), IM.2.5.1. Fireuroofing for Oil and Chemical Properties, IRI, Hartford, CT.
15. Industrial Risk Insurers (IN), IM.2.2.1. Firewalls, IRI, Hartford, CT.
16 National Fire Protection Association (NFPA), Standard 221. Construction of Fire Walls and Barriers, Proposed
Standard, NFPA, Quincy, MA, 1993.
17 Sheet Metal and Air Conditioning Contractors' National Association, Inc., (SMACNA), Fire. Smoke and Radiation
Damuer Installation Guide for HVAC Systems, Fourth Edition, SMACNA, Chantilly, VA, 1993.
18 Tunkel, S. J., "Methods for Calculation of Fire and Explosion Hazards", AIChE Today Series, AIChE, New York,
NY, 1984.
19 Underwriters Laboratories Inc. (UL), UL 263, Safety Fire Tests of Building Construction and Materials, Eleventh
Edition, UL, Northbrook, IL, 1992.
20 Underwriters Laboratories Inc. (UL), UL 525, Safetv Flame Arrestor for Use on Vents of Storage Tanks for
Petroleum Oil and Gasoline, Fifth Edition, UL, Northbrook, IL, 1992.
176
Handbook of Fire and Explosion Protection
2 1. Underwriters Laboratories Inc. (UL), UL 555. Safety Fire Dampers, Fifth Edition, UL, Northbrook, IL, 1994.
22. Underwriters Laboratories Inc. (UL), UL 5553. Safely Leakage Rated Damuers for Use in Smoke Control Systems,
Second Edition, UL, Northbrook, IL, 1994.
23. Underwriters Laboratories Inc. (UL), UL 1709. Safety Rapid Rise Fire Tests of Protective Materials for Structural
First Edition, UL, Northbrook, IL, 1991.
w,
Also see Appendix B. 1
Chapter 17
Fire & Gas Detection and Alarm Systems
Various simple and sophisticated fire and gas detection systems are available to provide early detection and
warnings of a hydrocarbon release which supplement process instrumentation and alarms. The overall
objective of fire and gas detection systems are to warn of possible impending events that may be threatening
to life, property of continued business operations. that are external to the process operation.
Process controls and instrumentation only provide feedback for conditions within the process system. They
do not report or control conditions outside the assumed process integrity limits. Fire and gas detection
systems supplement process information systems with instrumentation that is located external to the process
to 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 report
conditions that process instrumentation may not adequately report or be unable to report (i.e., minor
process releases).
Fire and Smoke Detection Methods
Hydrocarbon vapors immediately burn with flame temperatures that are considerably higher than that of
ordinary combustibles. For this reason damage from a hydrocarbon fire is much more severe than an
ordinary combustible fire. The objective of a fire detection for the petroleum industry is to rapidly detect a
fire where personnel, high value, and critical equipment may be involved. Once detected executive action is
initiated to alert personnel for evacuation and while simultaneously controlling and suppressing the fire
incident.
Human Surveillance
Human beings provide the first line of observation and defense for any facility. Periodic or constant first
hand operator on site surveillance of the process provides carehl observation and reporting of all activities
within the facility. Humans have keen senses that have yet to be expertly duplicated by instrumentation
devices or sophisticated technical surveillance mechanisms. In this fashion they are more valuable in the
observation of system performance than ordinary process control systems may be.
It should be remembered that humans are also prone to panic and conhsion at the time of an emergency and
so may also be unreliable in some instances. Where proper training and selection of personnel occurs
situations of panic and confbsion may be overcome.
177
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Handbook of Fire and Explosion Protection
Manual Activation Callpoint (MAC)/Manual Pull Station (MPS)
Simple switches that can be manually activated can be considered a fire alarm device. Models are used
which normally require the use of positive force, i.e., to avoid accident and fraudulent trips. Fire alarm
switches normally can only be reset by special tools in order to trace the source of the alarm, however
sophisticated data reporting systems with addressable data collection may make this requirement obsolete.
Manual activation devices are normally placed in the main egress routes from the facility or location.
Usually placement in the immediate high hazard location egress route and at the periphery evacuation routes
or muster location of the installation is accomplished.
Telephone Reporting
All telephone points can be considered a method of notification. Telephones can be easily placed in a facility
but may be susceptible to ambient noise impacts and the effects of a fire or explosion. Additionally
information from verbal sources can be easily misunderstood of spoken during an emergency. Simultaneous
use of the phone system during emergency situations may also cause it to be overloaded and connections
difficult to achieve.
Portable Radios
Operations personnel are normally provided with portable radios in large facilities. They have similar
deficiencies to telephones but offer the advantage on onsite portability with continuous communication
access.
Smoke Detectors
Smoke detectors are employed where the type of fire anticipated and equipment protection needs a faster
response time than heat detectors. A smoke detector will detect the generation of the invisible and visible
products of combustion before temperature changes are sufficient to activate heat detectors. The ability of a
smoke detector to sense a fire is dependent on the rise, spread, rate-of-burn, coagulation and air movement
of the smoke itself. Where the safety of personnel is a concern, it is crucial to detect a fire incident at its
early stages because of the toxic gases, lack of oxygen that may develop, and obscuration of escape routes.
Smoke detection systems should be considered when these factors are present.
Ionization
Ionization and condensation nuclei detectors alarm at the presence of invisible combustion products.
Most industrial ionization smoke detectors are of the dual chamber type. One chamber is a sample
chamber the other is a reference chamber. Combustion products enter an outer chamber of an
ionization detector and disturb the balance between the ionization chambers and trigger a highly
sensitive cold cathode tube that causes the alarm. The ionization of the air in the chambers is caused
by a radioactive source. Smoke particles impede the ionization process and trigger the alarm.
Condensation nuclei detectors operate on the cloud chamber principle, which allows invisible
particles to be detected by optical techniques. They are most effective on Class A fires (ordinary
combustibles) and Class C fires (electrical).
Photoelectric
Photoelectric detectors are of the spot type or light-scattering type. In each, visible products of
combustion partially obscure or reflect a beam of light between its source and a photoelectric
receiving element. The disruption of the light source is detected by the receiving unit and as a result
Fire and Gas Detection and Alarm Systems
179
an alarm is actuated. Photoelectric detectors are best used where it is expected that visible smoke
products will be produced. They are sometimes used where other types of smoke detection is too
sensitive to the invisible products of combustion that are produced in the area as part of normal
operations such as garages, fitrnace rooms, welding operations, etc.
Dual Chamber
Combinations of photoelectric and ionization detectors are available that operate as describe above.
They are used to detect either smoldering or rapidly spreading fires.
Very Early Smoke Detection and Alarm (VESDA)
High sensitivity sampling smoke detector systems provide the best form of rapid smoke detection for
highly critical equipment or in high air flow situations. The VESDA system is basically a suction
pump with collection tubes or pipes that use an optical smoke detection device to test for evidence of
smoke particles. Since it gathers air samples from the desired protected area they are much faster in
detection than ordinary detection that has to wait for the smoke to arrive to it. Care must be taken
that 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 or
electronic cabinets or racks that control critical oil or gas processing activities.
Thermal or Heat Detectors
Thermal or heat detectors respond to the energy emission from a fire in the form or heat. The normal means
by which the detector is activated is by convention currents of heated air or combustion products or by
radiation effects. Because this means of activation takes some time to achieve thermal detectors are slower
to 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 of
a fire incident to activate a signal device. Fixed temperature detectors signal when the detection element is
heated to a predetermined temperature point. Rate of rise detectors signal when the temperature rises at a
rate exceeding a pre-determined amount. Rate of rise devices can be set to operate rapidly, are effective
across a wide range of ambient temperatures, usually recycle rapidly and can tolerate a slow increase in
ambient temperatures without providing an alarm. Combination fixed temperature detectors and rate of rise
will respond directly to a rapid rise in ambient temperatures caused by fire, will tolerate a slow increase in
ambient temperatures without effecting an alarm, and recycle automatically on a drop in ambient
temperature.
Heat detectors normally have a higher reliability factor than other types of fire detectors. This tends
to lead to fewer false alarms. OveraII they are slower to activate than other detecting devices. They
should be considered for installation only where speed of activation is not considered critical or as a
backup fire detection device to other fire detection devices. They have an advantage of suitability for
outdoor applications but the disadvantage of not sensing smoke particles or visible flame from a fire.
Some of the systems can be strung as a line device and offers detection over a long path alternatively
they be used as spot detectors. A common deficiency after installation is they tend to become painted
over, susceptible to damage, or the fitsible element may suffer a change in activation temperature
over a long installation period.
Heat detectors are activated by either melting a hsible material, changes in electrical current induced
by heat loads on bi-metallic metaIs, destruction of the device itself by the heat, or by sensing a rate of
ambient temperature rise.
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Handbook of Fire and Explosion Protection
The following are some of the most common heat detection devices that are commercially available
and used in the hydrocarbon industries.
Flexible plastic tubing (pneumatic)
Fusible optical fiber
Bi-metallic wire or strip
Fusible plug (pneumatic pressure release)
Quartzoid bulb (pneumatic pressure release)
Fusible link (under spring tension)
Fixed temperature detector
Rate of rise detector
Rate compensated
Combination rate of rise and fixed temperature
(On a rare occasion a tensioned string tied to pressure switch has been provided as detection over
the vapor seal area of a floating roof crude storage tank. Although this method may be considered
primitive and cheap, it is effective and beneficial versus the option of no detection).
Optical (Flame) Detectors
Flame detectors alarm at the presence of light from flames usually in the ultraviolet or infared range. The
detectors are set to detect the typical light flicker of a flame. They may be equipped with a time delay
features to eliminate false alarms from transient flickering light sources.
There are six types of optical detector commonly used in the oil and gas industry.
1.
2.
3.
4.
5.
6.
Ultraviolet (W).
Single frequency infrared (IR).
Dual frequency idtared (IR/TR).
Ultraviolet/infrared - simple voting (W/IR).
Ultraviolet/infrared - ratio measurement (UVAR).
Multi-band.
Each of the five types of detectors listed has advantages and limitations, making each more or less suitable
for an application or a specific risk. There is not a uniform performance standard for flame detectors such as
their is with smoke detectors. Flame detection for a particular model has to be analyzed by evaluation of its
technical specification to expected fire development.
Ultraviolet (UV) Detector
Responds to the relatively low energy levels produced at wavelengths between 0.185 and
0.245 microns. This wavelength is outside the range of normal human visibility and
outside that of sunlight.
Advantages
The ultraviolet detector is general all purpose detector. It responds to most burning
materials but at different rates. The detector can be extremely fast, i.e., less than 12 milliseconds for special applications (e.g., explosive handling). It is generally indifferent to the
physical characteristics of flames and does not require a "flicker" to meet signal input
functions. It is not greatly affected by deposits of ice on the lens. Special modules are
available that can be used in high temperature applications up to 125 O C (257 OF). Hot
black body sources, (stationary or vibrating) are not normally a problem. It is blind to
Fire and Gas Detection and Alarm Systems
181
solar radiation and most forms of artificial light. An automatic self testing facility can be
specified or it can be tested with a hand held source at distances more than 10 meters (3
ft.) from the detector. Most models can be field adjusted for either the flame sensitivity or
the time delay hnction.
Limitations
It responds to electric arcs from welding operations. It can be affected by deposits of
grease and oil on the lens. This reduces it's ability to "see" a fire. Lightning with long
duration strikes can cause false alarm problems. Some vapors typically those with
unsaturated bonds may cause signal attenuation. Smoke will cause a reduction in signal
level seen during a fire. It may produce a false alarm response when subject to other
forms of radiation such as from NDT operations.
Single Frequency Infared (IR) Detectors
This detector responds to infrared emissions from the narrow C02 band at 4.4. microns.
It requires the satisfaction of a flicker frequency discrimination at between 2 and 10 Hz.
Advantages
It responds well to a wide range of hydrocarbon fires and is blind to welding arcs except
when very close to the detector. It can see through smoke and other contaminates that
could blind a W detector. It generally ignores lightning, electrical arcs and other forms
of radiation. It is blind to solar radiation and resistant to most forms of artificial lighting.
Limitations
There are few models with automatic test capability. Testing is usually limited to hand
held devices only 2 meters (7 fi.) from the detector or directly on the lens test unit. It can
be ineffective if ice forms on the lens. It is sensitive to modulated emissions from hot
black body sources. Most of the detectors have fixed sensitivities. The standard being
under five seconds to a petroleum fire 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 be
used in locations where the ambient temperatures could reach up to 75 OC (167 OF). It is
resistant to contaminants that could affect a UV detector. Its response is dependent on
fires possessing a flicker characteristic so that detection of high pressure gas flames may
be difficult.
Dual or Multiple Frequency Infrared (IR/IR) Detectors
This detector responds to infrared emissions in at least two wavelengths. Typically a C 0 2
reference at 4.45 microns is established and a second reference channel that is away from
the C02 and H 2 0 wavelengths is made. It requires that the two signals received are
confirmed as are synchronous and that the ratio between both signals is correct.
Advantages
It responds well to a wide range of hydrocarbon fires and is blind to welding arcs. It can
detect fires through smoke and other contaminates, although the signal pickup will be
reduced. It generally ignores lighting and electrical arcs. It has minimal problems with
solar radiation and artificial radiation. It is also insensitive to steady or modulated black
body radiation. There is a high level of false alarm rejection with this model of detector.
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Handbook of Fire and Explosion Protection
Limitations
Detectors with complete black body rejection capability are usually less sensitive to fires
than a single frequency infrared optical detector. Because it's discrimination of fire and
non-fire sources depend upon an analysis of the ratio between fire and reference
frequencies, there is a variation in the amount of black body rejection achieved. A
detector's degree of black body radiation rejection is in inversely proportion to its ability
to sense a fire. The detectors are limited to applications that involve hydrocarbon
materials.
Ultraviolet/Infrared (UV/IR) Detectors
There are two types of detectors under UV/IR classifications. Both of the types respond
to frequencies in the UV wavelength and IR in the C 0 2 wavelength. In both types
simultaneous presence of the W and IR signals must be available for alarm conditions. In
the simple voting device an alarm is generated once both conditions are met. In the ratio
device, satisfaction of the ratio between the level of UV signal received and IR signal
received must also be achieved before an alarm condition is confirmed.
Advantages
These detectors respond well to a wide range of hydrocarbon fires and are indifferent to
arc 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 fast
as a W detector. The simple voting type will respond to fire in the presence of an arc
welding operation. It is not desensitized by the presence of a high background IR source.
The flame sensitivities of the simple voting detector can be field adjusted.
Limitations
The sensitivity to a flame can be affected by deposits of IR and UV absorbing materials on
the lens if not frequently maintained. The IR channel can be blinded by ice particles on the
lens. While the W channel can be blinded by oil and grease on the lens. Smoke and some
chemical vapors will cause reduced sensitivity to flames. UVAR detectors require a
flickering flame to achieve an IR signal input. The ratio type will lock out when an intense
signal 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 is
negligible effect. The detectors are limited to applications involving hydrocarbon
materials.
Multi-band Detectors
Multi-band fire detector monitors monitor several wavelengths of predominate fire
radiation frequencies by photocells. They compare these measurements to normal
ambient frequencies through micro processing. Where these are found be above certain
levels an alarm is indicated. False alarms may even be "recognized"
Advantages
These detectors have a very high sensitivity and very encouraging stability.
microprocessor has the capability to be programmed to recognize certain fire types.
The
Fire and Gas Detection and Alarm Systems
Disadvantages
May be inadvertently mis-programmed. The detector is relatively new on the market and
needs Grther industry experience for wide acceptance.
Table 19
Comparison of Fire Detectors
183
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Handbook of Fire and Explosion Protection
Table 20
Application of Fixed Fire Detection Devices
Fire and Gas Detection and Alarm Systems
185
Gas Detection
Gas detection is provided in the petroleum industry to warn of and possibly prevent the formation of a
combustible gas 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 is
the catalytic detector. More recently, infared (IR) beam detectors have been employed for special "line of
sight" 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 protective
devices to 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 for
detection must be chosen carellly. The most prudent approach in such cases to chose to detect the gas that
is considered the highest risk for the area under examination.
The basis of the highest risk should account for:
(1.)
(2.)
(3.)
(4.)
(5.)
The gas with the widest flammable range of the gasses that are present.
The largest percent volume of a particular gas in the stream.
The gas with the lowest ignition temperature.
The gas with the highest vapor density.
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 each
material should be examined when deciding upon the optimum gas detection philosophy for a particular area.
The following table is a brief comparison of the characteristics of the most common gases that may be
encountered in a hydrocarbon facility.
Material
LEL/UEL %
AIT (OC)
VD
Group
Hydrogen
Ethane
Methane
Propane
Butane
Pentane
Hexane
Heptane
4.0 to 75.6
3.0 to 15.5
5.0 to 15.0
500
472
537
450
287
260
225
204
0.07
1.04
0.55
1.56
2.01
2.48
2.97
3.45
B
D
D
D
D
D
D
D
2.0 to 9.5
1.5 to 8.5
1.4 to 8.0
1.7 to 7.4
1.1 to 6.7
Table 21
Comparison of Common Hydrocarbon Vapor Hazards
By an analysis of the composition of gas or liquid stream and the arrangement or conditions at the particular
facility one can prudently arrive at the optimum detection philosophy.
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Application
Assuming the main objective of combustible gas detection is to warn of the formation of vapor
clouds that if ignited would produce h a d l explosion aftereffects, then the threshold of 5.5 meters
(18 ft.), as proposed by the Christian Michelsen Institute, Norway, should be the limiting case for
the spacing of combustible gas detectors. A three dimensional triangular spatial arrangement of 5
meters (16.4 e.), 10Y0 for adjustment and contingency factor, would provide a satisfactory
arrangement for area gas detection in confined areas. The first step is to define all possible leakage
sources and then narrow the possibilities by selecting equipment that has the highest probability of
leakage. This can be accomplished by first refemng to the electrical hazardous area classification
drawings for each facility. Equipment that handles low flash point materials should be given the
highest priority, with materials of a high vapor density of most concern, since these vapors are
easiest to collect and less likely to disperse.
Pump and compressor seal areas are by far the most common areas where vapor releases may
occur. This is followed by instrumentation sources, valve seals, gaskets and sample points and the
most rare but usually catastrophic erosion and corrosion failures of process piping.
The nature of the release needs to be analyzed to determine the path of the vapors, i.e., high or low.
This will determine whether the detectors need to be sited above or below the risk. Detectors
should also be sited with due regard to the normal natural air flow patterns. High and low points
where gas may settle should also be considered.
Enclosed spaces that may subject to a gas leak that have intrinsic production valve or are high
capital items should be provided with gas detection. Typically these locations are compressor and
metering 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., near
process areas handling gases and vapor. The facility air intakes themselves should be positioned to
prevent the intake of combustible gases fiom these areas, even during accident scenarios.
Normally point source detectors are positioned with their detector head downwards for better
capture of the ambient gases.
No gas detector should be located where it would be constantly affected by ambient conditions
such as surface drainage runoff, sand, ice, or snow accumulation. Special consideration should be
given near open sewer grates and oily water drain hnnels were frequent alarms may appear due to
vapor emissions.
Where overall large area coverage is necessary or desired , such as the monitoring of facility
borders, pump alleys, entire onshore units or offshore modules, "line of sight" IR beam detectors
are used, otherwise "point source", catalytic detectors are provided. The point source locations
should be at least on either side of the leak point, which at least one of the detectors downstream
ventilation pattern.
Fire and Gas Detection and Alarm Systems
187
Typical Hydrocarbon Facility Applications
The following locations are typical applications where combustible gas detection devices are provided or
should be considered in the hydrocarbon industry:
All hydrocarbon process areas containing materials with gaseous materials that are not
adequately ventilated (i.e., would not achieve a minimum of six air changes per hour or
would allow the build up of flammable gas due to noncirculating air space). Typically
applications include compressor enclosures, process modules in offshore platforms and
enclosed arctic facilities.
For enclosed areas, they can be considered adequately ventilated if they.meet one of the
following. Where artificial mechanisms are employed for ventilation assistance high
reliability must be assured.
(1) The ventilation rate provided is at least four times the ventilation rate required to
dilute the anticipated hgitive emissions to below 25 percent LEL as determined by
detailed calculations for 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 the
enclosed area.
(4) The area is not defined as "enclosed" per the definition of API RP 500, Section
4.6.2.2.4.
All gas compressors should be provided with point gas detection at sealage points and
especially if enclosed in a packaged module - interior area detection and at the air intake
and exhaust of the driver and compressor.
Pumps handling high vapor pressure hydrocarbon liquids (detector sited close to the
pump seals).
At all intakes for fresh air or W A C systems to buildings in an electrically classified area
according to the National Electrical Code (NEC) or subject to ingestion of combustible
vapors. Especially if they are considered inhabited, critical or of a high value. Typically
control rooms, critical electrical switchgear, or main process area power sources are
provided with gas detection.
At all critical internal combustion prime movers subject to the possible ingestion of
combustible vapors.
In all battery or U P S rooms in which hydrogen vapors may be vented or released from
battery charging operations.
Entrances and air intakes to the accommodation module or continuously manned
enclosed locations located offshore.
Drilling areas such as the mud room, drilling platform, and areas around enclosed
wellheads.
Possible hydrocarbon leaks points at process cooling towers.
Sensitive (critical or high value) processing areas where immediate activation of incident
and vapor mitigation mechanisms are vital to prevent the occurrence of a vapor cloud
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Handbook of Fire and Explosion Protection
explosion.
0
0
0
Enclosed water treating facilities that can release entrained combustible gases or vapors,
especially a concern at produced water treating operations.
Monitoring the purge gas from cold boxes and double walled insulated cryogenic storage
tanks.
Process locations containing large volumes or high pressure hydrocarbon gases which
might be susceptible to extreme effects of erosion or corrosion from the process activity.
Catalytic Detectors
Description
The catalytic gas detector was originally developed in 1958 for the mining industry. It has become
the standard means of detection worldwide in virtually all oil and gas operations. It is also used
extensively in coal extraction and the chemical process industry.
Catalytic gas detection is based on the principal that oxidation of a combustible gas in air is
promoted at the surface of a heated catalyst such as a precious metal. The oxidation reaction
results in the generation of heat that provides a direct measure of the concentration of the gas that
has been reacted. The sensing element embodying the catalyst is a small bead that is supported
with the sensor.
They are sensitive to all flammable gases, and they give approximately the same response to the
presence of the lower explosive limit (LEL) concentrations of all the common hydrocarbon gases
and vapors. However it should be remembered that gas detectors do not respond equally to
different combustible gases. The milli-volt signal output of a typical catalytic detector for hexane
or 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 single
point. If the position of the sensor is unfavorable in relation to the origin of the flammable gas
release and the pattern of air flow and ventilation in the hazardous area, then the gas detector will
not detect a dangerous release of gas until it is too late to take effective action. Generally point gas
detectors can only provide adequate protection at a facility if deployed in large numbers.
Secondly small quantities of airborne pollutants may poison the catalyst in the detector. This
severely reduces its sensitivity. The detector becomes less reliable and often makes duplication,
voting logic and frequent maintenance necessary.
The following substances have been known to poison catalytic gas sensors:
.
..
Tetraethyllead (at present being phased out as ;I gasoline additive in most count1 ics).
Sulfir compounds (particularly hydrogen sulfide in oil production refining
operations).
Phosphate esters ( used in corrosion inhibitors in lubricating oils and hydraulic fluids).
Carbon tetrachloride and trichlorelhylenc (found in degreasing agents and diy cleaning
fluids).
Flame inhibitors in plastic materials.
Thermal decomposition products of neoprene and PVC plastics.
Glycols.
Dirt or fiber particles
Fire and Gas Detection and Alarm Systems
189
Silicon vapors.
Infra-Red (IR) Beam Gas Detection
Conventional gas detectors are only capable of detecting gas at point locations. If the position of
the detector is unfavorable in relation to the origin of a gas release, it may not detect the gas release
before 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 anywhere
along an open path of several hundred meters in length. These devices have been available to the
industry for approximately ten years and their quality has improved as field experience was gained.
The sensor is based on the differential absorption technique and has a reasonably even response to a
range of light hydrocarbons. A microprocessor controller is commonly used for signal processing
that produces the alarm and trouble indications.
Many frequency lines of infared radiation are absorbed by hydrocarbon gases. By selection of a
particular frequency, a detector can be made which is either specific to a particular gas or if the
frequency is common to several gases, a particular group of gases may be detected.
Application (IR Beam)
IR beams are typically provided as a special gas detection applications. They offer a direct view
and surveillance over a large area rather than a point source origination of gas. The most frequent
use of these is verifymg whether a gas release would be carried offsite from the facility. Other
possible applications would be overall monitoring in area of several possible leak sources but within
a line of sight arrangement such as a pump alley or an offshore module.
Pump Alleys - Where a number of pumps are used, they are usually arranged in parallel to
each other facilitating the use of an IR beam over the line of pumps.
Perimeter Monitoring - The perimeter of a hazardous area or process unit can be
effectively monitored for vapor release by IR beam arrangements on the edges.
Theoretically they could be used to warn of open air combustible vapors approaching
ignition sources in a reverse role, e.g., to the flare from the process area.
Boundary and Offsite - Especially critical for locations near to public exposures, an IR
beam detector can be used to signal if vapors or gases may be released to offsite locations.
Alarm Setting
To achieve early and reliable warnings of leakages, the sensitivity of detectors should be at the
highest level commensurate with 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 second
alarm 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 2550% LEL as the second alarm point at which executive action should occur. Alternatively API RP
14C, Section C 1.4 (b), suggest settings no 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 level
of alarm the greater the possibility of false alarms and disruption to operations. On the other hand
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Handbook of Fire and Explosion Protection
some practical experience has shown that with the lower levels of sensitivity, more minor leakages
are at first detected. As these leakage sources are corrected, less and less real alarms are received
than if the gas detectors were set at the higher LEL levels (Le., 25 and 60% LEL). It should also
be realized that for immediate leaks the concentration of the vapor in an area will immediately rise
directly into the LEL range (or past it) so the relative settings below the LEL may not be
significant. The most important feature is to have detection capability for the gases that may be
encountered at the installation.
In general practice, the gas detection alarm set points are the settings recommended by the
manufacturer of the equipment or by requirements of an operating company to effect an acceptable
compromise on any given field of operation. The lower the set points the higher the sensitivity to
possible leakage emissions.
Calibration
Operation of detectors with their associated alarm panels should be checked and calibrated after
installation. Detector performance can be impaired in a hostile environment by blockages to the
detector (i.e., ice, salt crystals, wind blown particles, water or even fire fighting foam, or by
inhibition 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 a
routine basis.
It is also possible for detectors to be calibrated using one gas (e.g., methane) for use thereafter in
detecting a second gas (e.g., propane or butane) provided the relative sensitivity of the detector to
each of the gases is known. A procedure for calibration of the detector for a different gas than that
which is being used is normally available from the manufacturer of the detector.
Detectors should be calibrated after installation as recommended by the manufacture, typically this
is every 90 days. However if experience indicates that the detectors are either in calibration or out
of calibration the period of re-examination should be lengthen or shorten accordingly.
Hazardous Area Classification Rating
Since detectors are by definition exposed to combustible gases they should be rated for electrically
classified areas, such as Class I, Division I or 2, the specific gas groups (normally groups C and D),
and temperature ratings. It should be noted the UL presently does not specifically test combustible
gas detector sensor heads for use in classified areas, although they do tests enclosures for control
and data acquisition circuits. Several other international standards do evaluate combustible gas
detectors for use in classified areas (e.g., BS 6020).
Fire and Gas Detection Control Panels
Stand alone fire or gas detection and alarm panels are normally provided in the main control facility
for the installation. Recent trends also incorporate the transmittal of fire and gas alarms through
the DCS into the main process alarm real time control panel. When alarm panels are located within
a protected building, they should be located for easy access for emergency response personnel and
proximity to manual electrical power shut off facilities.
Fire and Gas Detection and Alarm Systems
191
Graphic Annunciation
Alarms should be displayed on a conventional dedicated window annuciator panel or if control
room based on a dedicated CRT display for fire and gas detection systems. Each detector location
should be highlighted with indications for trouble, alarm low, and alarm high. Where annuciator
panel window alarms the alarm indication lights should be provided with specific labels indicating
the exact alarm locations.
Power Supplies
Commercially available combustible gas detection systems generally use 24 VDC as the power
supply for field devices. 24 VDC is inherently safer and corresponds the voltages increasing used
by most instrument systems in process areas. A main supply voltage converter can be used to step
down or convert from AC to DC power supplies.
Emergency Backup Power
The power for combustible gas detection system should be supplied from the facility's U P S or if
this is unavailable normal power with a reliable battery backup source of a minimum of 30 minute
duration.
Time Delay
Where instantaneous reaction is not imperative, susceptibility to false alarms can be reduced by
requiring the fire signal to be present for a predetermined period of time. However, the time delay
reduces the advantages of high speed early detection. In most applications, the tradeoffs between
false alarms and the damage incurred in the first few seconds of a fire have been inconsequential.
Voting Logic
Activation of a single fire or gas detectors should not be trusted to provide executive action for
hydrocarbon 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 the
requirement for more than one sensor to detect a fire or gas presence before the confirmation of the
alarm. This method would prevent a false alarm cause by a single spurious source or by electronic
failure of a single component. Usually a one out or two or a two out of three (2003) voting
network of detectors is used to offer a confirmed alarm reception.
Cross Zoning
The use of two separate electrical or mechanical zones of detectors, both of which must be
actuated before the confirmation of a fire or gas detection. For example, the detectors in one zone
could all be placed on the north side of a protected area, and positioned to view the protected area
looking south, while the detectors in the second zone would be located on the south side and
positioned to view the northern area. Requiring both zones to be actuated reduces the probability
of a false alarm activated by a false alarm source such as welding operations, from either the north
or the south outside the protected area. However this method is not effective if the zone facing
away from the source, sees the radiation. Another method of cross zoning is to have one set of
detectors cover the area to be protected and another set located to face away from the protected
area to intercept external sources of nuisance U V . If welding or lighting should occur outside the
protected area, activation of the alarm for the protected area would be inhibited by second
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Handbook of Fire and Explosion Protection
detection activation. Although this method is quite effective a fire outside the protected area would
inhibit the activation for the protected area.
Executive Action
Once an alarm has been confirmed, actions should be taken to prevent or reduce the impact from
the event. Depending on the priority of the alarms the following actions should be taken at the
point of activation:
1 The facility evacuation and warning alarms should be activated, and personnel evacuation
or muster should commence.
2. Activate fixed fire extinguishing systems or vapor dispersion mechanisms (i.e., water
sprays).
3.
Start fire water and foam solution (if applicable) pumps.
4.
Close HVAC fire and smoke dampers. Close fire doors.
5. Shutdown HVAC fans (unless arranged for automatic smoke control and management).
6 . Activate the process ESD systems (i.e., Isolation, Power Shutdowns, Blowdown and
Depressurization).
7. On confiied gas detection sources of ignition such as welding or small power circuits
should be immediately shut down in the affected area (immediately shut down is applied
to equipment not rated for use where hazardous gases are present).
8.
Messages should be sent alerting outside agencies of the event and current situation.
Circuit Supervision
The detection and alarm circuits of fire and gas detection systems should be continuously
supervised to determine if the system is operable. Normal mechanisms provide for a limited current
flow through the circuits for normal operation. During alarm conditions current flow is increased
while during failure modes the current level is nonexistence. By measuring levels at a control point
the health of the circuit or monitoring devices can be continuously determined. End-of-lineresistors (EOLR) are commonly provided in each circuit to provide supervisory signal levels to the
control location.
Fire and Gas Detection and Alarm Systems
Table 22
Comparison of Gas Detection Systems
193
194
Handbook of Fire and Explosion Protection
Bibliography
Fire Detection
1.
BHR Group Ltd, Management and Engineering of Fire Safetv and Loss Prevention. Onshore and Offshore, Elsevier
Applied Science, London, U.K., 1991.
2.
Bishop, D. N., Electrical Svstems for Oil and Gas Production Facilities, Second Edition, Instrument Society of
America (ISA), Durham, NC, 1992.
3.
Coon, W., Fire Protection Design. Criteria. ODtions. Selection, R. S. Means, Kingston, MA. 1991.
4.
Institute of Electrical and Electronic Engineers. Inc. (IEEE), IEEE 979-84. Guide to Substation Fire Protection,
IEEE, New York, NY, 1988.
5. National Fire Protection Association (NFPA), NFPA 72. National Fire Alarm Code (NFAC), NFPA, Quincy, MA,
1994.
6.
National Fire Protection Association (NFPA), NFPA 90A. Heating and Ventilation Systems, NFPA, Quincy, MA,
7.
National Fire Protection Association (NFPA), NFPA 850, Fire Protection for Electric Generating Plants, NFPA,
Quincy, MA, 1992.
Gas Detection
1.
American Petroleum Institute (API), API RP 14C. Recommended Practice for Analysis. Design. Installation and
Testing of Basic Surface Safetv Svstems for Offshore Production Platforms, Fourth Edition, API Washington D.C.
1986.
2.
American Petroleum Institute (API), API Publication 203 1. Combustible Gas Detector Svstems and Environmental
and ODerational Factors Influencing Their Performance, First Edition, API Washington D.C., 1991.
3.
BHR Group Ltd., Fire Safetv Engineering, "Modem Methods of Designing Fire and Gas Detection Systems",
BHRA, Cranfield, U.K., 1989.
4.
British Standards Institution (BSI), BS 6020. Part 1.4. and 5, Instruments for the Detection of Combustible Gases,
Parts I,4, & 5.,BSI, London, U.K., 1981.
5. British Standards Institution, (BSI), British Standard 6959, Selection Installation, Maintenance and Use of
Apparatus for the Detection and Measurement of Combustible Gases, BSI, London, U.K., 1988.
6.
Canadian Standards Association (CSA), Standard C22.2 No. 152 M1984. Combustible Gas Detection Instruments,
CSA, Rexdale, Ontario, Canada, 1984.
7.
Department of Energy (U.K.), Guidance on Fire Fightin? Equipment. Section 4. Flammable Gas Detection and
Measuring Eaubment (Regulation 6) Her Majesty Stationary Office (HMSO) London, U.K., 1977.
8.
Factory Mutual (FM), FM Class No. 63 10-6330, Combustible Gas Detection Instruments,
9.
Instrument Society of America (ISA), ISA-S 12.13, Part I-Performance Reauirements. Combustible Gas Detectors,
ISA, Research Triangle Park, NC, 1986.
10 Instrument Society of America (ISA), RP 12.13, Part 11-1987 Installation. Operation. and Maintenance of
Combustible Gas Detection Instruments, ISA, Research, Triangle Park, NC, 1987.
11 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
195
12. Lloyd's 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 Fire
Protection, Appendix A, NFPA, Quincy, MA, 1990.
14. National Fire Protection Association (NFPA), NFPA 30, Flammable and Combustible Liquids Code, Section A-8-4
NFPA, Quincy, MA, 1990.
15. Schaeffer, M. J., "The Use of Combustible Detectors in Protecting Facilities from Flammable Hazards", ISA
Transactions, Vol. 20, No. 2, Instrument Society of America, Research Triangle Park, NJ, 198 1
16. United States Coast Guard (USCG), 46 CFR 154.1345 and 1350. USCG Regulations for Gas Detection Systems on
Self-propelledVessels C&g
Bulk Liquefied Gases, USGPO, Washington, D.C.
Chapter 18
Evacuation
The primary safety feature for any installation should be its evacuation mechanisms for its personnel. If
personnel cannot escape from an incident they may be affected from it. Personnel must first be aware that an
incident has occurred, and then have an available means to escape or evacuate from it. An adequate means
of escape should be provided from all buildings, process areas, elevated structures, and offshore installations.
Provision of an adequate means of escape is listed in most national safety regulations for the industry as a
whole as well as local building code ordinances.
The population density for any process area is usually quite low. Initial glances at an operating unit would
indicate that the facility is unmanned. The highest concentrations of personnel are typically found in control
rooms, transportation mechanisms, drilling or maintenance activities and accommodations. These locations
offer the highest probability of large life loss within the petroleum and chemical industries. Historical
evidence of hydrocarbon and chemical facilities demonstrate that for the majority of incidents, a relatively
low level of fatalities occur. When a large life loss does occur, it is usually due to the congregation of
personnel in a single area without the ability to escape, or to avoid or protect themselves from the impending
hazard.
When and emergency egress route is provided it should be protected from the effects of fire and smoke or
the personnel equipped with a means to protect themselves when transversing it. It has been shown that
people are reluctant to enter into smoke that reduces visibility to less than 10 meters (33 ft.), even when it is
not hazardous to do so. Where the effects of fire, smoke and explosions are likely to preclude the use of an
emergency egress route, it is the same as not providing an egress route.
Alarms and Notifications
Alarms should be able to be noticed at all areas of the facility, whether manned or
considered technically unmanned. The basic theory for deterrkning the number and
location of audible alarm devices is that strategically placed and distributed devices
will provide an efficient distributed level of sound, than one large centrally located
device.
\
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 of
alarm. If unobstructed areas from 61 to 305 meters (200 to 1,000 ft,) are encountered, a large plant wide
siren or horn may be suitable in some cases, depending on background noise and orientation of the device(s).
196
Evacuation
197
Where several different alarm signals are necessary they should be easily distinguishable from one another
for the purposes they are intending to provide, i.e., fire alarm, evacuation, etc. Different signals can range
from 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 different
emergency sounds.
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 noise
levels are higher, flashing beacons should be used. Beacon colors should be consistent with the alarm color
coding philosophy adopted for the entire facility.
Panel alarms and indications should not be mounted lower than approximately 0.76 meters (2' 6" ft,) or
higher than 1.83 meters (6' 0" ft.). Outside these limits the alarm's alarm indicators are less noticeable and
awkward for maintenance personnel activities.
Alarm Initiation
Alarms should be initialed by the local or main control facility for the location. Manual activation means
should be provided for all emergency, fire, and toxic vapor alarm signals. Activation of fire suppression
systems by automatic means should also indicate a facility alarm. Most fire and gas detection systems are
also set to automatically activate alarms after contimation and set points have been reached. Manual
activation of field or plant alarm stations should activate the process or facility alarms.
Alarm activation points should be clearly highlight and marked. Their operation should be simple, direct and
consistent throughout the facility or company, especially if personnel may be transferred or rotated from
one location to another.
Evacuation Routes
Evacuation routes are of prime importance for the safety of plant workers during an emergency. They
should contain the following features:
Two evacuation routes, situated as far apart as practical, should be provided from all hydrocarbon
processes or normally occupied work areas. Areas that are considered low hazard (no
hydrocarbons, chemicals or other flammables are in the immediate area) may be allowed one escape
route. The exception to tlus is rooms located on an offshore installation in proximity to
hydrocarbon processes.
Should not be affected by the effects of fire or explosions (i.e., blast overpressure, heat, toxic
vapors and smoke).
Evacuation routes should be generally straight and direct to points of safety or embarkation
A minimum width of 1.O meter (39 inches) should be maintained on all main evacuation routes.
Passage from one level to another level should be by stairways, where impractical, vertical ladders
are normally provided. Preferably stairways and ladders should be located on the exterior faces of
structures that face away from the plant. Stairways designs that require evacuation to be through
other process equipment or areas should be avoided. On fired units where the towers may be very
close to the furnace, providing an additional walkway bridge link to an adjacent tower or structure
may 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 conditions. If the route is not obvious, adequate demarcation (i.e., signs and arrows) should be
Handbook of Fire and Explosion Protection
198
provided of the route and exit points
An emergency muster location is provided. This affords a means to account for personnel and
issue hrther evacuation instructions.
0
Egress arrangements should not be exposed to drainage provisions provided at a facility.
Emergency Doors, Exits, and Escape Hatches
Exit 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 are provided in offshore facilities near process areas,
a secondary emergency escape hatch is provided as an alternative means of escape in addition to the normal
means of egress.
The design of stairways of two or more risers is critical for safe evacuation. Stair widths, rise and run are
arranged and balanced for an effective and orderly evacuation. Studies of people travelling on stairways
have shown that the probabilty of the greatest hazard is the user. Inattention has been shown to be the
single most factor producing the greatest misteps, accidents or injuries. Life safety codes for the installation
of stairs place limitations on the use of winding, circular and spiral stairways to ensure adequate egress
routes are provided €or emergency periods.
Incidental combustible liquid storage (e.g., lube oil reservoirs, fuel day tanks, etc.) should normally not be
installed within 1.8 meters (6 e.)of an emergency exit route, especially if it is the only means of egress fiom
an enclosure.
Marking and Identification
Where practical routes between exit points should be defined by lines painted on the
floor or facility pavement in reflective oil resistant paint. All exit doors should be
plainly marked. Direction arrows and wordings should be positioned along escape
routes where necessary to guide personnel to exit points or the perimeter of the facility.
The arrows should be preferably self illuminating (Le., luminescent).
Emergency Illumination
A 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 emergency
evacuation period, but not less than 90 minutes.
Offshore Evacuation
The methods of evacuation offshore are dependent on the ambient environmental conditions that may
develop in the area and relative distance to the mainland. Regions that experience colder ambient
conditions inhibit immersion opportunities and remote offshore locations retard onshore assistance
capabilities. The preferred and most expedient evacuation means from an offshore installation is by
helicopter. Because of the nature of fire and explosions to affect the vertical atmosphere surrounding an
offshore installation, helicopter evacuation means cannot always be accommodated and should be considered
of low probability where the accommodation quarters are located on the same structure as a hydrocarbon
process.
Evacuation
199
North/South Atlantic and North/South Pacific Environments
Areas of the North and South Atlantic, and North and South Pacific present continual extreme and
hostile ambient conditions that make survival exposed to such conditions a very limited probability
with adequate protection measures. In these locations the probability of survival is increased with the
provision of a fixed safe refuge rather than the provision of an immediate means of escape. For
offshore facilities historical evidence indicates that both helicopter and lifeboat mechanism may be
unavailable in some catastrophic incidents. Remote onshore facilities may also experience severe
winter conditions that also render this philosophy applicable.
Temperate and Tropic Environments
Less severe locations, where supplemental exposure protection for the normal ambient conditions is
not necessary. These location however may contain other threats that need to be accounted for, such
as, sharks, hurricanes, volcanic and tsunami activity.
Means of Egress
In general at least two means of accesses should be provided from all "facility evacuation muster
areas" to the sea . These means are usually selected from the following:
i. Stairway or ladder.
ii. Lifeboat and davit launched life rafts.
iii. Abseiling devices.
iv. Scramble nets or knotted ropes.
v. Slide tube.
Where other semi-occupied areas exist, they are usually provided sufficient and properly arranged
evacuation means to the sea by way of two remote locations. These include the following:
i. Abseiling devices
ii. Scramble nets or knotted ropes
iii. Ladder or stairway.
Flotation Assistnnce
Two methods of flotation assistance in the open sea are usually provided for
the number of personnel on board @OB) the installation. They may consist of
the following:
i. Lifejacket or inflatable survival suit.
ii. Lifeboats and life rafts.
iii. Flotation device (life buoy or ring)
6
,,
1
i!
/
.
2
>?4flr
__
..~.
..__2
..,.i.
A prime consideration in the provision of lifeboats for offshore installations is that they can be readily
maneuvered away from the structure of the installation. Recent trends have been for the orientation
of lifeboats to point outwards so that egress away from the structure is improved and the fear of
being swept into the platform by the waves and current is lessened. Positioning in an outward
orientation also improves the evacuation time for the boat to "get away" from the incident.
200
Handbook of Fire and Explosion Protection
APPROX. CUM.
TIME
TIME
ACTIVITY
I
ALARM & NOTIFICATION
SEEK
REFUGE
OR
EVACUATE
YES
I
IS MUSTER AREA OR ACCESS
AFFECTED BY INCIDENT?
I
I
I
I 0.05 ,
1
0.10
I
0.15
I
I
v
I 0.05
DON LIFEJACKET
1
I
CHECK ROSTER
P
I
I
t
STANDYBY OR
HELICOPTER
EVACUATION
I
I
I
!
YES
CONDITION
SURVIVABLE?
I
SEEK OTHER PROTECTED SHELTER
OR HELICOPTER EVAC.
* WCCE
OFFSHORE EVACUATION FLOWCHART
FIGURE 10
Evacuation
Bibliography
1.
American Society of Testing Materials (ASTM), F 1166. Standard Practice for Human Enheering Design for
Marine Systems. Eauipment and Facilities, ASTM, Philadelphia, PA, 1988.
2.
Acoustical Society of America (ASA), S3.41, Audible Emergency Evacuation Signal, (ASA 96), ASA, New York,
NY, 1990.
3.
British Standards Institute (BSI), BS 5395: Part 3: 1985. Stairs ladders and walkways, Part 3 Code of Practice for
the design of industrial type stairs, permanent ladders and walkways, BSI, London, UK. 1985
4.
Department of Energy (U.K.), Offshore Installations: Guidance on Life Saving Aodiances, HMSO, London, U.K.,
1978.
5.
Department of Energy (U.K.), SI 1977 No. 486. Offshore Installations. The Offshore Installations Life Saving
Appliances Regulations, 1978, HMSO, London, U.K., 1978.
6.
International Maritime Organization (IMO), International Convention for the Safety of Life at Sea, IMO, London,
U.K., 1986.
7.
International Organization for Standardization (ISO), IS0 773 1: 1986 Danger Signals for Work Places - Auditory
Danger Signals, ISO, Geneva, Switzerland, 1986.
8.
International Organization for Standardization (ISO), IS0 820 1 :1987 Acoustics - Audible Emergencv Evacuation
ISO, Geneva, Switzerland, 1987.
&gal,
9.
National Fire Protection Association (NFPA), NFPA 101. Life Safetv Code, NFPA, Quincy, MA, 1994.
10. Occupational Safety and Health Administration (OSHA), 29 CFR 1910.037, U.S. Department of Labor,
Washington, D.C.
1 1 . Occupational Safety and Health Administration (OSHA), 29 CFR 1910.165, U.S. Department of Labor,
Washington, D.C.
201
Chapter 19
Methods of Fire Suppression
The objectives of fire suppression systems are to provide cooling, control the fire (i.e., prevent it from
spreading) and provide extinguishment of the fire incident. A variety of fire suppression methods are
available to protect a facility. Both portable and fixed systems can be used. The effectiveness of all fire
extinguishing measures can be determined by the rate of flow of the extinguishing agent and the method or
arrangements of delivery.
Before the need of fire protection measures is defined, the type of hydrocarbon fire exposure should be
identified. By determining the type of fire expected, the adequacy of the fire protection measures based on
the philosophy of protection for the facility, can be assessed. The easiest method to arrive at the protection
requirements is to identi@ the materials and pressures involved in the process. Once this is accomplished,
the most appropriate fire control or suppression mechanism can be identified from NFPA 325M. Tables 3
and 4 provides examples of a tabular format that can be used to document the fire control mechanisms that
have been chosen.
Portable Fire Extinguishers
Historical evidence indicates that portable (i.e., manually manipulated an operated) fire extinguishers are the
most common method of extinguishing hydrocarbon fires for the petroleum industry in the incipient stage.
Human surveillance combined with the ability to quickly and effectively react to the beginning of an incipient
fire have prevented countless petroleum incidents from developing into large scale disasters. The objective
for providing portable fire extinguishers is to have an available supply of plentihl extinguishers that can be
easily used in the early stages of a fire growth. When these extinguishing means are exhausted or the
incipient fire has grown to the point of uncontrollability by manual methods, fixed fire suppression systems
and process incident control systems should be activated (e.g., ESD activation). Only personnel trained in
their use should be expected to use a portable fire extinguisher.
202
Methods of Fire Suppression
203
A portable Fire Extinguisher is a device used to put out fires of limited size. Portable extinguishers are
classified by expected application on a specific type of fire (i.e., A, B, C, or D) and the expected area of
suppression. The four types of fires are grouped according to the type of material that is burning. Class A
fires include those in which ordinary combustibles such as wood, cloth, and paper are burning. CIass B fires
are those in which flammable liquids, oils, and grease are burning. Class C fires are those involving live
electrical 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 testing
laboratories for the amount of average fire area that can be extinguished according to methods established by
"A.
The rating does not equate to the amount in square feet that can be expected to be extinguished by
an individual.
The classes of portable fire extinguishers manufactured and used in the USA are defined below. Other
countries have similar classifications (although these may not be exactly the same).
Extinguishers for Class A Fires
Class A fire extinguishers are usually water based. Water provides a heat-absorbing (cooling) effect
on the burning material to extinguish the fire. Pressurized water extinguishers use air under pressure
to expel the water.
Extinguishers for Class B Fires
Class B fires are put out by excluding air, by slowing down the release of flammable vapors, or by
interrupting the chain reaction of the combustion. Three types of extinguishing agents carbon
dioxide, dry chemical, and foamwater are used for fires involving flammable liquids, greases, and oils.
Carbon dioxide is a compressed gas agent that prevents combustion by displacing the oxygen in the
air surrounding the fire. The two types of dry chemical extinguishers include one that contains
ordinary sodium or potassium bicarbonate, urea potassium bicarbonate, and potassium chloride base
agents. The second, multipurpose type contains an ammonium phosphate base. The multipurpose
extinguisher can be used on class A, B, and C fires. Most dry chemical extinguishers use stored
pressure to discharge the agent, and the fire is extinguished mainly by the interruption of the
combustion chain reaction, Foam extinguishers use an aqueous film forming foam (AFFF) agent that
expels a layer of foam when it is discharged through a nozzle. It acts as a barrier to exclude oxygen
fiom the fire.
Extinguishers for Class C Fires
The extinguishing agent in a class C fire extinguisher must be electrically non-conductive. Both
carbon dioxide and dry chemicals can be used in electrical fires. An advantage of carbon dioxide is
that it leaves no residue after the fire is extinguished. When electrical equipment is not energized,
extinguishers for class A or B fires may be used.
204
Handbook of Fire and Explosion Protection
Extinguishers for Class D Fires
A heat-absorbing extinguishing medium is needed for fires in combustible metals. Also, the
extinguishing medium must not react with the burning metal. The extinguishing agents, known as dry
powders, cover the burning metal and provide a smothering blanket.
The extinguisher label gives operating instructions and identifies the class, or classes, of fire on which the
extinguisher may be used safely. Approved extinguishers also carry the labels of the laboratories at which
they were tested.
Portable fire extinguishers should be positioned in all hydrocarbon processing areas so that the travel
distance to any extinguisher is 15 meters (50 ft.) or less. They are generally sited on the main walkways or
exits from an area, near the high hazard itself and near other emergency devices. They are mounted at
approximately one meter fiom the walking surface with red background highlighting.
Water Suppression Systems
Water is the most useful and vital fire suppression medium, whether used for fixed systems or manual fire
fighting efforts for petroleum facilities. It is relatively inexpensive and normally plentiful. It has enormous
heat absorption properties. Approximately 3.8 liters (1.0 gal.) of water absorbs about 1,512 k cal (6,000
Btu), when vaporized to steam. Steam created by water evaporation expands to about 17,000 times its
volume 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 water
suppression system consists of a supply source, distribution system, and the end using equipment such as
fixed spray systems, monitors, hose reels and hydrants. The objective of water suppression systems is to
provide exposure cooling, fire control, suppression of fire incidents and may assist in the dispersion of
flammable or toxic vapors.
When water suppression systems are provided, due concern should be made for the disposal of the released
water. Of primary importance are the capacity and location of surface drainage systems. Fire water usage
usually places greater demands on a facility gravity sewer system than rainfall or incidental petroleum
spillage effects.
Water Supplies
Firewater supply sources can be the city public water main, a dedicated storage tank and pumps, or the most
convenient lake, river or if an offshore installation the open sea. Brackish or salt water supplies can be used
if suitable corrosion protection measures are applied to the entire firewater system if it is planned to be used
for an extended life (i.e., grater than five years). If a short life span of the facility is expected, short
corrosion resistant materials may be used (i.e., carbon steel, galvanized steel, etc.), provided periodic testing
indicates their integrity is still adequate and scale or corrosion particles do not affect operational efficiency.
Methods of Fire Suppression
205
Most hydrocarbon facility process areas and high volume storage areas have standardized on a minimum
supply or availability of four hours of firewater for the WCCE. The performance of risk analysis may reveal
the level of fire water protection may be more or less than this requirement. Once a detailed design is
completed on a facility or if a verification of existing water demands is needed, a simple tabular calculation
of 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 to
document such information.
Fire Pumps
Fire protection pumping systems are almost universally required to be according to NFPA 20. Pump sizes
depend on the water delivery requirements to protect the hazard. When fire pumps are designated to
provide fixed fire protection water supplies two sources are provided - a main and a backup. The preferred
driver for fire punips at most hydrocarbon facilities, when there is a reliable and non-vulnerable power grid is
available, is by an electric motor that receives energy from two different power sources (i.e., generator
stations). Alternatively, at least one electric and one prime mover standby (diesel, gas or steam engine is
provided) unit is provided. Where the electric power grid is unreliable or fiom a single source, fire pumps
powered by prime movers should be provided.
Nowadays the power grids of industrialized countries and commercially available high horsepower electrical
motors are highly reliable, so the need of independent prime mover, as may have been the case several
decades ago, is not highly demonstrated. The maintenance, failure points, fuel inventories, instrumentation
and controls needed for an internal combustion engine versus an electrical motor all demonstrate it is not as
a cost effective option as compared to an electrical motor. Of course adequate integrity and reliability of
electrical motor power sources and infrastructure must be assured. Where several tire pumps are necessary
it is still good common sense practice to provide a prime mover source to accompany electrical motor
drives. Offshore installations are particularly attractive for this option where a prime mover adjacent to
generator provides power for an electrically submersible pump or hydraulic drive unit, thereby eliminating
the need for long line shaft turbine pumps needing specialized alignments for correct operation. Petroleum
operations in third world locations are generally dependent on their own power generation, so shelf
contained prime mover option for fire pumps are selected to decrease sizing and costs of the production
power generators.
206
Handbook of Fire and Explosion Protection
m
h
)
4
Methods of Fire Suppression
207
To avoid common failure incidents prime and backup fire pumps preferably should not be located
immediately next to each other and ideally should be housed at separate locations at the facility. They
should 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 a
single firewater storage tank, requiring the siting of all firewater pumps close to it. Even in these
circumstances it may be wise to segregate the main and backup fire pumps from each other with separate tie
in points to the firewater distribution loops. This mostly depends on the hazard level of the facility and the
distance of the firewater pump location from the process. Fire water pumps should be located as remote
from the process area as feasible, preferably at a higher elevation and in the upwind direction. In a review of
one hundred major petroleum industry fires, the failure of the firewater pumps was a major contributor of
the ensuing large scale destruction of the facility for twelve of the incidents.
The metallurgy selected for construction of a firewater pump is dependent on the properties of the water
source to be used. For fresh water sources (i.e., public water mains), cast iron is normally adequate
although bronze internals may be optional. Brackish or sea water utilization will require the use of highly
corrosion 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 or
specialized coating.
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 is
a horizontal centrifugal type with a relatively flat performance curve (Le., pressure versus quantity). The
discharge pressure is determined by the minimum residual pressure required at the most remote location of
the facility flowing its highest practical demand with allowances added for piping friction losses.
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 been
used extensively offshore, but recent reliability improvement with electrical submersible pumps and hydraulic
drive units have been eagerly accepted as they eliminate alignment problems, topsides weight and in some
instances are less complex than the right angle engine driven vertical turbine units. Hydraulic calculations
for offshore pump installations must remember to account for tide and wave fluctuations.
Especially critical in fire pump installations from open bodies of water is the activity of underwater diver
operations in proximity of the underwater fire pump suction bell or opening. Underwater diving operations
routinely occur at the structural support (i.e., the jacket) for offshore installations for corrosion monitoring,
modifications, inspections, etc. The high water current at the intake to the submerged pump poses a safety
hazard to the divers. During the operation of the ill fated Piper Alpha offshore platform it was common
practice to switch the fire pump to manual startup mode (requiring an individual visit to the fire pump
location) to start it up, during diving operations. This was the case on the night when the installation was
destroyed. A simple solution is to provide a large protective grid far enough away and around the pump
intake so that it will limit water velocities below that which would cause concern to the divers. The
International Association of Underwater Engineering Contractors has issued a notice (AODC 055)
describing these requirements.
When more than one pump is installed, they should be coordinated to start in sequence, since immediate
start up of all pumps may not be necessary and could cause damage to the system. Depending on the
number of pumps available, they can be set to startup on sequentially decreasing fire main set points. All fire
water pumps should be able to be started from remote activation switches located in manned control rooms.
Small capacity pumps commonly referred to as "jockey" pumps are provided on a firewater system to
compensate for small leakages and incidental usage without the main pump(s) startup. They are set to start
0.70 to 1.05 kg/sq. cm. (10 to 15 psi) above the start up pressure of main firewater pumps. In some cases a
cross-over fioni the utility water system can be used in place of a jockey pump, however a check valve is
installed to prevent drain down of the firewater by the utility water system. Jockey pumps do not require the
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same reliability of firewater water pumps and should not be credited for fire water supply when calculating
fire water supplies available.
Fire pumps should be solely-dedicated to fire protection. They may be used to feed into a backup system for
emergency process cooling but not as the primary supply. If such backup is allowed is should be tightly
controlled and easily accessible for prompt shutdown in case of a real emergency.
A method of testing fire pumps should be provided to verify adequate performance will be available during
an emergency. Additionally most fire protection audits, insurance surveys and local maintenance
requirements would require fire pumps to be routinely tested for performance verification. In fact,
predictive maintenance can be performed before fire pumps reach reduced flow performance levels requiring
removal. Pressure gages on the suction and discharge should be provided and a method to verify the
flowing water quantity at each test point. The sizing of flow test piping should account for the maximum
flowrate of the unit, not just its rated capacity.
The latest trend is to install a solid state electromagnet flowmeter with precise digital readout, however
orifice 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 circumstances
where flow measuring devices are not directly available at the fire pump, plant hydrants or hose reel outlets
may be used (refer to Appendix A. l), even portable clamp-on electromagnetic and uitrasonic flowmeters are
available. The ideal situation is design so flow test water is re-circulated back into the storage reservoir
from 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 topside
structure may affect personnel who periodically work at the lower or sea surface levels.
Fire Pump Standards and Tests
Purchase or specification of a fire pump to support hydrocarbon operations should be in compliance with
recognized international standards for such equipment. The most commonly referenced standards are listed
below. All of these standards require a factory acceptance test of the unit.
0
0
0
API 610 Centrifbgal Pumps for General Refinery Service.
BS 5316 Part 1:1976, (IS0 2548) Acceptance Tests for Centrifugal, Mixed Flow and Axial
Pumps.
NFPA 20 Standard on the Installation of Centrifbgal Fire Pumps.
UL 448 Standard for Safety, Pumps for Fire Protection Service.
Table 24
Fire Pump Standards
Firewater Distribution Systems
The distribution system is arrangement of piping configured to ensure a delivery of water to the desired area,
even if a portion of the system is isolated for repairs. This is accomplished by a looped network of pipes and
isolation valves at strategic locations. A loop network should be provided around each process area. For
orisliore facilities, firewater piping is normally buried. Offshore it should be routed against and behind
structural members for protection against damage from fires and particularly explosions. If the piping needs
to be exposed, it should be secured in both horizontal and vertical directions against potential blast
overpressure loads. Flanged connections should be avoided since they may prove to be the weakest point or
Methods of Fire Suppression
209
leakage, however they are much favored for offshore construction efforts as they eliminate specialized
welder 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 and
flow requirement at the most remote hydrocarbon process or storage location from the supply source
dictates the sizing for the remaining system. Nornial reliability requirements usually suggest that minimum
of two sources of supply be available that are in themselves remote from each other. Therefore two remote
flow calculations must be performed to determine the minimum pipe distribution size. NFPA 24 requires
that the minimum residual pressure available in a fire main not be less than 6.9 bars (100 psi.). Velocity
calculations should be performed which verify flows are not more than the limits of the material that is
employed.
Normally firewater mains are of metal (e.g., Carbon Steel, Kunifer, etc.) construction. Some recent
installations 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 weight
of earth covering will deform the plastic piping to an oval shape. Eventually leaks will develop at fitting
connections, which are usually a higher pressure rating that the piping and can withstand the weight of the
overburden. Distribution piping should not be routed under monolithic foundations, buildings, tanks,
equipment, structural foundations, etc. Both for needs of future accessibility and additional loads the
foundations may 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 an
emergency.
A hydraulically designed system is preferred over standardized approach for optimization of the firewater
flows, water storage requirements and piping materials. In any case, the main header should not be less than
203 mm (8 in.) in diameter. Piping routed to hydrants, monitors, hose reels and other protective systems
should be at least 152 mm (6 in.) in diameter.
Firewater Control and Isolation Valves
All fixed fire suppression system control valves should be located out of the fire hazard area but still within
reach of manual activation. For high hazard areas (such as offshore facilities), dual feeds to fire suppression
systems should be considered from opposite areas. For onshore facilities, firewater isolation valve handles
should not be contained within a valve pit or a below grade enclosure within the vicinity of hydrocarbon
process facilities, since heavy 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 available on the immediate
portion of the system needing work, a unique solution is to use a liquid nitrogen low temperature coil line
freezing apparatus. This mechanism causes an ice plug to form in the line, effectively sealing the line from
leakage, during the period the temporary isolation is needed.
Firewater control valves are usually required to be tested to a recognized standard. The most common
listing is by UL which is shown in Table 25.
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Valve Type
Test Standard
Gate Valve
Check Valve
Sprinkler Valve
Deluge Valve
F o a M a t e r Valve
Preaction Valve
Buttertly Valve
UL 262
UL. 312
UL 193
UL 260
UL 260
UL 260
UL 1091
Table 25
Test Standards for Fire Protection Valves
Sprinkler Systems
Wet and dry pipe sprinkler systems are commonly provided to indoor occupancies, such as warehouses,
offices, etc. They are considered essentially 100% effective for fire suppression if properly maintained and
the hazard has not changed since the original design. Sprinkler systems are normally activated by the heat of
the fire melting a tension loaded cap at the sprinkler head. The cap melts or falls away releasing water from
the pipe distribution network. Thus they do not activate until a fire condition is absolutely real. Due to the
removal of Halon gaseous fire suppression systems because of environmental concerns, sprinklers have been
suggested as an alternative for electrical and electronic enclosures. An often overlooked fact when
considering maintaining gaseous systems over a sprinkler system is that considerable fire damage will already
have occurred once a sprinkler system activates.
Water Deluge Systems
Deluge systems should generally be activated by automatic means. Activation by manual means defeats the
objective of instailing a deluge system, and fire water monitors should be provided instead as they are more
cost effective where manual means is relied upon. Most systems provided at petroleum facilities are
typically activated by a heat detection. Usually a hsible plug pneumatic loop detection system or W A R
detectors are placed around the equipment. This insures activation when operators are not present and only
when a real fire situation is present.
For vessels protected by deluge systems the most important points are the vessel ends, the portion of the
vessel that contains a vapor space (ie., the unwetted portion), flange connections that can leak and if the
vessel is located close to the ground without good surface drainage, the immediate underneath surface of the
vessel that would exposed to the flames.
Water Spray Systems
Water spray systems for hydrocarbon facilities are routinely specified because of the rapid application means
the system can provide and the excellent heat absorption a water based system represents. Water sprays are
also used when passive fire protection measures (i.e., fireproofing, spacing, etc.) cannot practically be
utilized. The key to providing an effective system is to ensure the surfaces to be protected receive adequate
water densities and that the arrangements to activate the system are equally fast acting. By far the highest
Methods of Fire Suppression
211
application is the utilization for cooling process vessels. The important surfaces for process vessels to
protected are the vapor spaces and hemispherical ends. Electrical transformers are provided with water
spray coverage where their value or criticality is considered high.
Water Flooding
Water flooding is the principle to inject water into the interior of a storage tank for the purposes of
preventing flammable or combustible liquids from being released from a leakage point or to extinguish a fire.
The principle involves fill a vessel or tank so that the lighter density hydrocarbon fluids float on the water
and only water is released from the container. In practice the logistics of pedorming such and operation
while also conducting prevention or fire fighting efforts for the immediate hydrocarbon spillage makes this
avenue of protection generally unviable although for large volume containers it might be useful.
Steam Smothering
The use of steam smothering in the hydrocarbon industries is typically limited to fires that might occur as a
result of a tube leak in a fbrnace or heater. The steam is most effective in smothering fires when they are
located in relatively small confined areas. Steam extinguishes fire by the exclusion of free air and the
reduction 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 available
supplies of steam generation. Snuffing steam also presents a personal burn hazard from superheated water
vapor exposure if directed onto or near unprotected skin. Use of other fire extinguishing agents is generally
preferred over the use of snuffing steam. A standard on the use of snuffing steam has never been published
but Appendix F of NFPA 86 provides some limited information on the general requirements in designing a
system.
Water Curtains
Fire water sprays are sometimes employed as an aid to vapor dispersions and can also mitigate available
ignition sources. Literature on the subject suggests two mechanisms are involved that enhance protection
when using water sprays for vapor dispersion. First, a water spray arrangement will start a current of air in
the direction of the water spray. The force of the water spray engulfs air and dispenses it further from its
normal circulating pattern. In this fashion released gases will also be engulfed and directed in the direction
of nozzles. Normal arrangement is to point the water spray upward to direct ground and neutral buoyancy
vapors upwards for enhanced dispersion by natural means at higher levels. Second, a water spray will warm
a vapor to neutral or higher buoyancy to aid in its natural atmospheric dispersion characteristics. One spray
head operating at 276 kPa (40 psi) will move 7,835 liters per second (16,600 CFM) of air at a 3 meters (10
ft.) elevation. This air movement can reduce flammable vapor concentrations within a relatively short
period.
Water curtains can also cool or eliminate available ignition source to a released vapor cloud. In this fashion
they can also be a mitigating feature to prevent vapor cloud explosions. Hot surfaces, sparking devices and
open flames in the immediate area of a vapor release can all be eliminated as a result of a directed water
curtain where these sources exist.
For water curtains to be highly effective they should be automatically activated upon confirmed gas
detection for the area of concern.
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Blow Out Water Injection System
A patented water injection system has been devised for extinguishing oil and gas well fires in case of a
blowout. The "Blowout Suppression System" (BOSS) consist of finely atomized water injected to the fluid
stream of a gas and oil mixture before it exits a release point. The added water lowers the flame temperature
and flame velocities thereby reducing the flame stability. In the case where the flame cannot be completely
dissipated, the fire intensity is noticeably deceased, preserving structural integrity and allowing manual
intervention activities. A precaution in the use of such a device is that, if a gas release fire is suppressed but
the flow is not immediately isolated, a gas cloud may develop and exploded that would be more destructive
that the pre-existing fire condition.
Hydrants, Monitors and Hose Reels
Monitors are considered the primary manual water delivery device for hydrocarbon facilities, while hydrants
and hose reels are considered secondary. Monitors are an initial manual fire suppression device that can be
activated by operators with limited fire fighting training or experience. Use of hydrants and hoses usually
require additional manpower and previous training. The use of a fire hose however, provides for more
flexibility in the application of water sprays and where it may be needed when it is impractical to install a
monitor. 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 hose
connections.
Hydrants should be considered as a backup water supply source to monitors and fixed fire suppression
systems. Hydrants should be located on the ring main at intervals to suitably direct water on the fire hazard
with a fire hose. Hydrants monitors and hose reels should be placed a minimum of 15 meters (50 ft.) from
the hazard they protect for onshore facilities. Hydrants in process areas should be located so that any
portion of a process unit can be reached from at least two opposite directions with the use of 76 meters (250
f?), hose lines if the approach is made from the upwind side of the fire. Offshore hydrants are located at the
main accessways at the edge of the platform for each module. Normal access into a location should not be
impeded by the placement of monitors or hydrants. This is especially important for heavy crane access
during maintenance and turnaround activities.
For offshore installations, the placement of fire protection devices are more rigidly regulated. Monitors are
normally required by regulations for the helideck and on open decks, such as the drilling or pipe deck where
the reach and area of coverage can be effective without blockages that would be encountered in an enclosed
module. They can be effectively used on open decks when positioned at the edge of the deck. Heiideck
monitors should be arranged so they are normally below the helideck level, and should be provided with heat
radiation screens due to the proximity to the aircraft hazard. The helideck monitors are normally at the
highest point in the system, requiring the highest pressure to the fire pumps and the source where trapped air
will accumulate. NFPA and HSE provide guidance in the placement of helideck firewater requirements.
Monitors should be provide at all rotating equipment and large liquid holdup vessels. They should also be
located to provide cooling water spray to the process equipment preferably from an upwind location. A
minimum of two remotely located firewater monitors are usually provided at sources of potential large
hydrocarbon release, i.e., rotating equipment such as pumps, compressors, storage vessels and tanks. These
monitors are typically placed to provide a water spray in-between the selected equipment besides providing
general 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 in
close proximity to a hazard, such as offshore helidecks, 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 distance a water stream can reach, verification should be made that an obstruction does not exist which can block
the water stream. Typical practice is to draw "coverage circles" from the monitor on a plot plan. Where
Methods of Fire Suppression
213
these circles intersect pipe racks, large vessels or process columns, the water coverage will be blocked and
the coverage circle should be modified accordingly. Generally where extreme congestion exist, such as in
offshore facilities monitor coverage would be ineffective due to major obstructions and congestion.
Exposure to personnel activating the device due to it's 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 routed
under or through the rack.
Monitors can be set and locked in place, while the operator evacuates or attends to other duties. A residual
pressure of 690 kPa (100 psi) is required for most monitors to effectively provide suppression and cooling
water (ref. NFPA 14, Section 5.7) and should be verified when several are flowing simultaneously.
Oncoming or cross wind effects may reduce the performance of water monitors. When winds of 8 k d h r (5
mph) are present they may reduce the range of water spray by as much as 50%. Consideration should be
given to the placement of monitors when the normd wind speed is such to cause performance effects.
Hard rubber hose is preferred over collapsible fabric hose for process area hose reels and for preference of
immediate availability. The rubber hose should not be allowed to be stored or exposed to direct sunlight for
any considerable time period.
The surface slope at the placement of all hydrants, monitors and hose reels should be slightly away from the
device itself so water will drain away and prevent corrosion effects. Where automobile traffic may be
prevalent, protective post or railing should be provided to prevent impacts to the devices. The protective
barriers should not affect the hose connection, use of hoses or obscure the spray from monitors. The posts
should be provided with highly visible markings or reflective paint.
Nozzles
There are a variety of nozzles that can be provided to hoses and monitors. They are capable of projecting a
solid, spray or fog stream of water depending on the requirements and at varying flow rates. Straight
stream nozzles have a greater reach and penetration, while fog and water sprays will absorb more heat
because the water droplets absorb more heat due to greater surface area availability. Fog and water spray
nozzles are sometimes used to assist in the dispersion of vapor releases.
A 32 liters per second (500 gpm) nozzle with an adjustable combination straight stream and fog tip are
normally provided for fixed installations. Nozzles up to 63 V s (1,000 gpm) may be used at high hazard
locations. Higher capacity nozzles generally do not increase the reach of the water spray only the amount of
water delivered. Where higher capacity nozzles are retrofitted to existing systems both the firewater
capacity and the drainage system capacity should be reviewed for adequacy. Where foam agents are
available the nozzles should have the capability to aspirate the foam solution if it is desired.
Foamwater Suppression Systems
Foamwater systems are provided wherever there are large quantities of liquid hydrocarbons that pose a high
fire risk. Foam is an aggregate of water, chemical compounds and air filled bubbles that float on the surface
of combustible liquids. They are used primarily to provide a cohesive floating blanket on the liquid surface
of the liquid material it is protecting. It extinguishes a fire by smothering and cooling the fuel, Le., liquid
surface, and prevents re-ignition by preventing the formation of combustible mixtures of vapor and air over
the liquid surface. Foam will also cool the fuel and surrounding equipment involved in the fire. Foams are
supplied in concentrates that are appropriately proportioned into water supply systems. They are then
aspirated with air to produce the foam bubbles.
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Handbook of Fire and Explosion Protection
Foam is a homogenous blanket of a mixture of liquid chemical and air or a nonflammable gas.
Foam fire suppression systems are classified as high or low expansion. High expansion foam
is an aggregation of bubbles resulting from the mechanical expansion of foam solution by air
or other nonflammable gases. Expansion ratios range from 100:1 to 1,000:1 . Foams with an
expansion ratio significantly less than 100:1, are produced from air foam, protein foam,
fluoro-protein foam, or synthetic foam concentrates. They are inserted as a definite portion in
a liquid stream that is later aspirated just before or at a distribution nozzle. High expansion
type foams are generated in a high expansion generator by blowing air through a wet screen
with a continuous spray of water producing additive. High expansion foam is very light. It
can be applied to completely and quickly fill an enclosure or room. The various types of foam
provide similar protection. They are principally selected on the basis of compatibility of foam
equipment provided, materials involved and use with other agents. All foams are electrically
conductive and should not be used on fires involving energized electrical equipment.
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 enclosed
areas where high winds would not affect the foam usefulness and where interior locations are
hard 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 the
commonly used foams. Commercially available foam products are now available that can be
used on both alcohols and hydrocarbons, only alcohols or only hydrocarbons. It is therefore
imperative to design foam systems in a cost effective fashion if several products are in use that
may require special foam application requirements.
Chemical foams were widely used in the industry before the availability of liquid concentrates,
and now they considered to be obsolete.
Concentrations
Foam concentrations currently on the market range from 1 to 6 mixing or proportioning
percent with water. The advantage in the lower percentage mixing means less foam
concentrate is needed for a particular hazard. This is economical both in amount of agent
needed and in storage facilities necessary, and is particular usefir1 offshore where a weight
saving can also be realized. Foam systems of very low percentages necessarily require a
“cleaner”system to perform adequately.
Systems
In the oil. and gas industry there are generally five foam fire protection systems commonly
encountered. :
(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 confined
spaces.
Methods of Fire Suppression
215
General Area Coverage
General area coverage is generally provided where there is hlly or partially enclosed
areas, e.g. offshore modules, truck loading racks, liquid storage warehouses, etc. where
liquid spills can easily spray, spread or drain over a large area. Where the protected areas
are critical or high value immediate detection and release mechanisms are chosen (i.e.,
deluge systems). Aspirating or non-aspirating nozzles may be used. Aspirating nozzles
generally produce foams with a longer life span after discharge. Aspirating nozzles also
produce a foam with a higher expansion ratio than non-aspirating nozzles.
Foam Water Deluge Systems
Deluge systems are generally used in areas requiring an immediate application of foam
over a large area, such as process areas, truck loading racks, etc. The system employs
nozzles connected to a pipe distribution network which are in turn connected to an
automatic control valve referred to as deluge valve. Automatic detection in the hazard
area or manual activation opens the deluge valve. Guidance for designing foam water
deluge systems is provided in NFPA 16.
Overhead Foam Injection
These systems are typically provided for the protection of atmospheric or low pressure
storage tanks. They consist of one or more foam chambers installed on the shell of a tank
just below the roof joint. A foam solution pipe is extended from the proportioning
source, which is located in a safe location, to a foam aspirating mechanism just upstream
of the foam chamber or pourer. A deflector is usually positioned on the inside tank wall
at the foam chamber. It is used to deflect the foam against the tank wall and onto the
surface of the tank or the tank and shell seal area.
Two types of designs are commonly applied. For cone top tanks or internal floating roof
tanks with other than pontoon decks multiple foam makers are mounted on the upper
edge of the tank shell. These systems are designed to deliver and protect the entire
surface area of the liquid of the tank. For open and covered floating roof tanks with
pontoon decks the foam system is designed to protect the seal area. Foam makers are
mounted on the outside of the tank shell near the rim and foam is run down inside to the
seal area that is encapsulated with a foam dam. This method tends to cause the
movement of cooler product to the surface to aid in extinguishment of the fire and the
amount of water delivered to the heat layer in heavier products can be controlled to
prevent excessive frothing and slopover.
Subsurface Foam Injection
Subsurface foam injection is another method to protect atmospheric or low pressure
storage 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 existing
product line or a dedicated subsurface foam injection line. Due to its buoyancy and
entrainment of air, the foam travels up through the tank contents to form a vapor tight
blanket on the surface of the liquid. It can be applied to any of the various types of
atmospheric pressure storage tanks but is generally not recommended for application to
storage tanks with a floating roof since distribution of the foam to the seal area fiom the
internal dispersion is difficult.
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Handbook of Fire and Explosion Protection
High Expansion Foam
High expansion foam is generally applied to ordinary combustible (Le., Class A) fires that
occur in relatively confined areas that would be inaccessible or a hazard for fire fighting
personnel'to enter. The system controls fires by cooling, smothering an reducing oxygen
content by steam dilution. The system uses high forced air aspirating devices, typically
large fans, to produce foams with an expansion ratio of 100 - 1,000 to 1. Proportioning
of 1 112% percent is normally used providing large quantities of foam from relatively
small amounts of concentrates. Use in the oil and gas is normally reserved to manual fire
fighting efforts.
Gaseous Systems
Carbon Dioxide Systems
Carbon 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 systems
will extinguish fires in practically all combustibles except those which have their own oxygen supply
and certain metals that cause decomposition of the carbon dioxide. C 0 2 does not conduct
electricity and can be used on energized electrical equipment. It will not freeze or deteriorate with
age. Carbon dioxide is a dangerous gas to human life since it displaces oxygen. Concentrations
above 9 percent are considered hazardous, while 30 percent or more are needed for fire
extinguishing systems. Carbon dioxide systems are generally ineffective in outdoor applications
since wind effects and dissipate the vapors rapidly. It has a vapor density of 1.529 and therefore
will settle to low points of an enclosure.
For fire extinguishment or inerting purposes C02 is stored in liquid form that provides for its own
pressurized discharge.
Application
Carbon dioxide may be applied for fire extinguishment through three different mechanisms:
(1) Hand hoses from portable storage cylinders.
(2) Total flooding fixed systems.
(3) Local application fixed 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 equipment
or leave a residue. Some cooling effect is realized upon agent discharge, but a thermal shock
to equipment should not occur if the system is 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 are
normally 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 for
specific hazards. As a guide, 0.45 kgs (1 lb.) of C02 liquid may be considered to produce
0.23 cubic meters (8 cu. ft.) of free gas at atmospheric pressure.
Fixed C 0 2 systems are almost used extensively for protecting highly valuable or critical where
an electrically non-conductive, non-residue forming agent is desired and where the location is
unmanned. In the hydrocarbon industries C 0 2 systems are usually provided to protect
Methods of Fire Suppression
217
unmanned critical areas or equipment such as electricaVelectronic switchgear rooms, cable
tunnels or vaults, turbine/compressor enclosures, etc. Where rotating equipment is involved
both primary and supplemental discharges occur to account for leakages during the rotating
equipment "run-downs." Concentrations are to be achieved in 1 minute and normally
maintained for 20 minutes.
Safety Precautions
CO, is a nonflammable gas, therefore it does not present a fire or explosion hazard. The gas is
generally considered toxic but will displace oxygen in the air, since it is 1.5 times heavier that
air it will settle and air supplies will be pushed out of the area. The C 0 2 gas is considered an
asphyxiation hazard to personnel for this reason. Since the gas is odorless and colorless it
cannot be easiiy detected by human observation in normal environments. Fire protection C 0 2
gas is normally stored under high pressure as a liquid and expands 350 times its liquid volume
upon release.
The normal concentration of oxygen in air is from 21 to 17 percent. When the concentration
of oxygen in air drops below 18 percent, personnel should consider vacating or not entering
an area due to an asphyxiation hazard. Alternatively they can be provided with protective self
contained breathing apparatus to work in low oxygen environments.
There are two factors of personnel hazard from a C 0 2 release:
(1) When increasing amount of C 0 2 are introduced into an environment the rate and
depth of a person's breathing increases. For example at 2 percent C 0 2 concentration,
breathing increases 50 percent and at 10 percent concentration a person will gradually
experience dizziness, fainting, etc.
(2) When atmospheric oxygen content is lowered below 17 percent a person's motor
coordination will be impaired. Below 10 percent, they will become unconscious.
System Discharges
Where fixed automatic C 0 2 systems are installed, a time delay of 30 seconds , warning signs
and alarms or beacons are provided to warn the occupants of the room. This allows the
occupants to immediately evacuate, or initiate an "abort" switch where the activation has been
by accidental means.
System Leakages
Leakages from C 0 2 fire suppression systems are considered extremely rare. With adequate
inspection and maintenance procedures a leak on the system should generally not be expected
to occur. Installed pressure gages on the C 0 2 cylinders should be frequently checked against
the initial pressure readings. If they are found to be different, immediate action should be
taken to investigate possible leakages.
In small rooms where high pressure C 0 2 storage bottles are kept, it is apparent that with a
350 expansion ratio, the room could easily be a hazard to personnel from system leakages.
In small rooms where high pressure C 0 2 storage bottles are kept, it can be readily realized
that with a 350 expansion ratio, the room would easily be a hazard to personnel from system
leakages. A calculation could be performed which would identi@ the amount of potential
C 0 2 build up (ie., percent C 0 2 concentration) from the immediate and complete (ie., leak)
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Handbook of Fire and Explosion Protection
from 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 enclosed
areas they should be well labeled to the possibility of an oxygen deficient atmosphere. The
room should normally be a controlled location (i.e., doors locked) and all personnel entering
the enclosure must be equipped with a portable oxygen monitoring device (unless a fixed
oxygen monitoring system is installed) as dictated by a company's safety procedures for entry
into an area where there is a possibility of an oxygen deficient atmosphere. Should a leak
occur in the enclosure a portable exhaust fan can be positioned to evacuate any accumulated
C 0 2 vapors at the time and an oxygen monitoring device can be arranged to confirm removal
of vapors to allow for safe entry. The provision of permanent operating exhaust fan for these
areas would not necessarily guarantee that when a minor C02 leak occurs they would be
adequately removed from the area, thereby precluding the necessity of oxygen monitoring and
a controlled location. Since C 0 2 vapors are heavier than air they will normally seek the lower
portions of any enclosure. The C 0 2 vapors may not reach the exhaust fan especially if the
exhaust 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 container
for a considerable amount of time. Even when an exhaust fan is installed to dissipate the
vapors, it cannot be guaranteed that the C 0 2 vapors would be entirely removed when an
individual randomly enters the room.
In room that are provided with air conditioning an exhaust fan would always be evacuation
the cooled air. This would defeat the purpose of the air conditioner. (the exhaust fan would
have to be continuously operated since no idea when a leak would occur could be accurately
predicted, unless sensing instruments were provided, if so the exhaust fan as a preventive
device would then be considered somewhat superfluous).
In instances where C02 storage bottles are installed in enclosed spaces, an exhaust fan is
usually provided the protected hazard area. It is activated to remove the vapors once a system
has been klly discharged, rather than a prevention measure for partial vapor release and
disposal of unexpected leakages.
Supplemental measures that may be considered are a fixed oxygen monitoring system, a low
pressure storage bottle alarm(s) or odorization of the stored C02 gas.
Disadvantages
C02 systems have the following disadvantages:
1. The expelled C 0 2 gas presents a suffocation hazard to Humans in the exposed area.
All such areas would require strict access control.
2. C 0 2 gas is considered a "greenhouse" gas and may in the future be considered an
environmental concern.
3. Fixed C 0 2 systems require a large storage area and have considerable weight which
limits their benefit offshore.
4. Deep seated fires may not be hlly extinguished by a gaseous fire suppressant agent.
Halon
Halon is a halogenated compound that contains elements from the halogen series - fluorine,
chlorine, bromine and iodine. Halogen atoms from noncombustible gases when they replace
Methods of Fire Suppression
219
the hydrogen atoms in hydrocarbon compounds such a methane or ethane. Except for Halon
13 10, bromotrifluormethane, most halogenated hydrocarbon compounds are corrosive when
moisture is present. Halon will also break into corrosive and toxic byproducts in the presence
of a sustained electrical arc.
Halon systems were the ideal fire suppression agent before their implications of environmental
impact due to ozone depletion. The industry is gradually phasing out usage of halon systems
for this reason. A flowchart to analyze mechanisms to supplement or eliminate Halon systems
for electrical or computer processing areas is shown in Figure 1 1 . Some of the prime reasons
to eliminate the use of Halon systems is that the facility may be constantly manned with a
relatively low fire risk. Other facilities may have a very low combustible load and can be
supplemented by highly sensitive fire detection means, such as a VESDA fire detection
system.
Halon Replacements
Several Halon replacements are now available that have been tested and accepted by certifying
agencies. These agents generally require higher concentrations than that Halon suppression
systems. They may be asphyiants to humans. Most also have greater storage requirements
(i.e., space and weight) than the previous Halon systems did.
Oxygen Deficient Gas Inerting Systems
To reduce the risk of explosion and fires from enclosed spaces of volatile hydrocarbon storage
tanks, a gas with that would be considered deficient in oxygen is provided to exclude oxygen
from entering the enclosure. Large ocean going tanker vessels are equipped with a continuos
inert gas system that blankets storage holds or tanks with an oxygen deficient gas (combustion
exhaust gases from the prime mover). Similarly some crude oil storage tanks are provided
with a processed gas as a method of excluding oxygen from entering the vapor space of cone
roof storage tanks.
220
Handbook of Fire and Explosion Protection
Fire Initiation
(Failure/Malfunction/
Electrical Fire
1 -
Detection Activated
extinguished
NO
NO
Of Fire Suppressed
ELECTRICAL FIRE INCIDENT CONTROL
Figure 11
Methods of Fire Suppression
221
Chemical Systems
Wet Chemical
Wet chemical systems have a slightly advantage over dry chemicals in that they can coat the
liquid surface of the fire and can absorb the heat of a heat, thereby preventing re-ignition. Wet
chemical systems are primarily provided for kitchen cooking appliances - grills, fryers, etc.
They provide a fixed fire suppression application of liquid fire suppressant through fixed
nozzles. The typical application for petroleum facilities is at the kitchens of onsite cafeterias.
Spray coverage is provided to exhaust plenums, and cooking surfaces activated by fusible
links or manual pull stations. The b i b l e links should be rated for the maximum normal
temperature expected in the exhaust fumes, usually 232 OC (450 OF). Common practice to
conduct a one time agent discharge and operational test during the initial installation
acceptance, together with a hydrostatic test of the system piping.
Dry Chemical
Dry chemical agents currently used are a mixture of powders, primarily sodium bicarbonate
(ordinary), potassium bicarbonate (Purple K), monoammmonium phosphate (multipurpose).
When applied to a fire they cause extinguishment by smothering the fire process. They will not
provide securement of a flammable liquid spill or pool fire and it can re-flash after it is initially
suppressed if an ignition source is present (i.e., a hot surface). Dry chemical is still very
effective for extinguishment of three dimensional flammable liquid or gas fires. It is
nonconductive and therefore can be used on live electrical equipment.
Dry chemical agents reduce visibility, pose a breathing hazard, clog ventilation filters and the
residue may enhance corrosion of exposed metal surfaces. Dry chemicals should not be used
where delicate electrical equipment is located, for the insulation properties of the dry
chemicals may render the contacts inoperative. Dry chemicals may also present a clean up
problem after use, especially for indoor applications. The system should activate fast enough
to prevent equipment becoming too hot to cause a re-ignition once the system has been
discharged. -411 dry chemical agents are corrosive to exposed metal surfaces.
Fixed systems may be fixed nozzles or hand hose line systems. They usually range in capacity
fiom 68 to 1,360 kgs (150 to 3,000 Ibs.). Most use a high pressure nitrogen cylinder bank to
fluidize and expel the dry chemical from a master storage tank. Where immediate water
supplies are unavailable, fixed dry chemical systems may be a suitable alternative.
Dual Agent Systems
Chemical and Foam
Dual agent suppression systems are a combination of simultaneous application of foam water
and dry chemical to provide for greater fire fighting capabilities. Usually aqueous filmforming foam (AFFF) and potassium bicarbonates are used. They are provided in separate
vessels on a self contained skid. When needed they are charge by a bank of high pressure
nitrogen cylinders and the agents are discharged through two manually operated and directed
nozzles. The nozzles are provided on approximately 30 meters (100 ft.) lengths of hard
rubber hose to provide for fire attack tactics.
Self contained dual agent systems, (foadwater and dry chemical), are provided for manual
fire fighting efforts against three dimensional pressure leaks and large diameter pool fires. The
design affords fast fire knockdown, extinguishment and sealant against re-flash. A skid
222
Handbook of Fire and Explosion Protection
mounted unit is provided at locations where flammable liquids are present and personnel may
be in a direct vicinity of the hazard. Typical hydrocarbon applications are associated with
aircraft operations both fixed wing and rotary (Le., helicopters). For land based operations
the skid is provided on a flatbed of a truck or small trailer for greater mobility at aircraft
landing strips. Offshore the equipment is normally fixed at the helideck periphery.
Methods of Fire Suppression
Process
Area
I
Gas Release
I
I
Offshore
Process Module
Liquid Spill
Gas Release
NFPA 30
Process
Vessels
Liquid Spill
Gas Release
NFPA 30
Fired
Heaters
I
I
Liquid Spill
Gas Release
I
I NFPA30
Tank Farm
Liquid Spill
Gas Release
NFPA 30
Truck
Loading
Liquid Spill
Gas Release
NFPA 30
Rail Loading
Liquid Spill
Gas Release
Liquid Spill
Gas Release
Liquid Spill
NFPA 30
G a s Release
NFPA 30
Marine Loading
b P
Station
Gas
Compression
Flare
Kitchens
Administration
Ofice
I
I Liquid Spill
Liquid Spill
CombustibleFire
CombustibleFire
I
I
NFPA 30
NFPA 30
I
I
2. Monitors
3. Hose Reel
4. Vapor Dispersion Deluge Spray
1. Hydrants
2. Monitors
3. Hose Reel
4. Overhead Foamwater Deluge
1. Hydrants
2. Monitors
3. Hose Reel
4. Water Deluge Cooling Spray
1. Hydrants
2. Monitors
3. Snuffig Steam
1. Hydrants
2. Monitors
3. Water Deluge Cooling Spray
4. Subsurface Foam Injection
5. Foam Topside Delivery
1. Hydrants
2. Monitors
3. Overhead Foamwater Deluge
1. Hydrants
2. Monitors
1. Hydrants
2. Monitors
1. Hydrants
2. Monitors
1. Hydrants
2. Monitors
1 4. Preaction Sprinkler
NFPA30
NFPA I01
NFPA 101
I
1. Hydrants
3. Sprinkler System
1. Dry Chemical
2. Wet Chemical
1. Hvdrants
2 Standpipe System
2 Sprinkler System
Table 26
Fixed Fire Suppression Design Options Basis
I
I
2. NFPA 24
3. NFPA 24
4. NFPA 15
1. NFPA 24
2. NFPA 24
3. NFPA 24
4. NFPA 16
1. NFPA 24
2. NFPA 24
3. NFPA 24
4. NFPA 15
l.NFPA24
2. NFPA 24
3. NFPA 86
1. NFPA 24
2. NFPA 24
3. NFPA 15
4.NFPA 11
5. NFPA 11
1. NFPA 24
2. NFPA 24
3. NFPA 16
1.NFPA24
2. NFPA 24
1. NFPA 24
2. NFPA 24
1. NFPA 24
2. NFPA 24
1. NFPA 24
2. NFPA 24
I 4. NFPA 13
I
1.NFPA24
3 NFPA 13
1. NFPA 17
2. NFPA 17A
1. NFPA 24
2 WPA14
3 NFPA13
223
224
Handbook of Fire and Explosion Protection
Application Table
Table 27
Fire Suppression System Applications
Methods of Fire Suppression
Table 28
Advantages and Disadvantages of Firewater Systems
225
226
Handbook of Fire and Explosion Protection
Bibliography
1. American Petroleum Institute, (API), RP 14G. Recommended Practice for Fire Prevention and Control on Open
T w e Offshore Production Platforms, Third Edition, Washington D.C., 1993.
2.
American Petroleum Institute (API), Standard 610. Centrifugal Pumps for General Refinerv Service, Seventh
Edition, API, Washington D.C., 1989.
3.
American Petroleum Institute (API), Publication 2021. Fighting Fires in and Around Flammable and Combustible
Liauid Atmosuheric Storage Tanks, Third Edition, API, Washington, D.C., 1991.
4.
American Petroleum Institute (API), Publication 2030 Guidelines for Auulication of Water Surav Svstems for Fire
Protection in the Petroleum Industry, First Edition, API, Washington, D.C., 1987.
5.
American Water Works Association (AWWA) C502. Standard for Drv-Barrel Fire Hydrants, AWWA, Denver, CO,
1985.
6.
American Water Works Association (AWWA), C503, Standard for Wet-Barrel Fire Hvdrants, AWWA, Denver,
CO, 1988.
7.
American Water Works Association (AWWA), M17. Installation. Field Testing and Maintenance of Fire Hydrants,
Third Edition, AWWA, Denver, CO, 1989.
8.
American Water Works Association (AWWA), M3 1. Distribution Svstem Reauirements for Fire Protection, First
Edition, AWWA, Denver, CO, 1989.
9.
Bryan, J. L., Automatic Sprinkler and Standpipe Svstems, NFPA, Quincy, MA., 1976.
10. Coon, W., Fire Protection Design. Criteria. Options. Selection, R. S. Means, Kingston, MA. 1991
11. Department of Energy (U.K.), Offshore Installations: Guidance on Fire Fighting Equipment, HMSO, London, U.K.,
1978.
12. Department of Energy (U.K.), 1978 NO. 61 1, Offshore Installations The Offshore Installations (Fire Fighting
Eauiument) Rermlations. 1978, HMSO, London, U.K., 1978.
13. International Association of Underwater Engineering Contractors, Protection of Water Intake Points for Diver
Safe&. AODC Notice #055, Association of Diving Contractors, London, U.K. 1991.
14. Industrial Risk Insures (IN),
IM.2. Section 2.5.3. Fire Protection Water & Still Control for Outdoor Oil &
Chemical Plants, IRI, Hartford, CT, 1992.
15. National Fire Protection Association (NFPA), Fire Protection Handbook, 17th Edition, NFPA, Quincy, MA, 1991
16. National Fire Protection Association (NFPA), NFPA 10. Portable Fire Extinguishers,NFPA, Quincy, MA, 1990
17. National Fire Protection Association (NFPA), NFPA 11. Low Expansion Foam and Combined Agent Systems,
NFPA, Quincy, MA, 1988.
18. National Fire Protection Association (NFPA), NFPA 11A. Medium and Hiph Exuansion Foam Svstems, NFPA,
Quincy, MA, 1990.
19. National Fire Protection Association (NFPA), NFPA 12. Carbon Dioxide Extinguishing Systems, NFPA, Quincy,
MA, 1993.
20. National Fire Protection Association (NFPA), NFPA 13. Installation of Sprinkler Systems, NFPA, Quincy, MA,
1991.
Methods of Fire Suppression
227
21. 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 Sprav
Systems, 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. National Fire Protection Association (NFPA), NFPA 418. Helideck Protection, NFPA, Quincy, MA, 1993.
30. Underwriter's Laboratories Inc. (UL), UL 193, Alarm Valves for Fire Protection Service, Ninth Edition, UL,
Northbrook, IL, 1993.
3 1. Underwriter's Laboratories Inc. (UL), UL 260. Drv Pipe. Deluge, and Pre-Action Valves for Fire Protection Service,
Sixth Edition, UL, Northbrook, IL, 1994.
32. Underwriter's Laboratories Inc. (UL), UL 262. Standard for Safetv for Gate Valves for Fire Protection Service,
Seventh Edition, UL, Northbrook, IL, 1994.
on),
UL 312. Standard for Safetv for Check Valves for Fire Protection Service,
33. Underwriter's Laboratories Inc.
Eighth Edition, UL, Northbrook, IL, 1994.
34. Underwriter's Laboratories Inc. (UL), UL 448. Standard for Safetv for Pumps for Fire Protection Service, Seventh
Edition, UL, Northbrook, IL, 1990.
35. Underwriter's Laboratories Inc. (UL), UL 1091. Standard for Safetv for Butterflv Valves for Fire Protection Service,
Fourth Edition, UL, Northbrook, IL, 1993.
Petroleum operations are found on all the major continents and diversified environmental conditions. These
environments are so different and remote that unique situations develop which require specialized
requirements.
Arctic Environments
Arctic environments pose different ambient conditions than normally encountered at most oil and
gas facilities. The most obvious is that the ambient temperature level can reach extremely low
levels, as much as -45.5 Oc (-SOOF) and that snow or ice storms can be expected to occur.
The primary concern at these locations is the protection of critical equipment so they can continue
to function. This involves both the metallurgical properties of vessels, piping, control systems and
instrumentation. Personnel operations are also hampered in such location. Generally heavy
insulated protective clothing must be worn and accessto equipment becomes blocked or difficult
due to ice and snow accumulation. Locations considerably north or south will also exhibit longer
periods of darkness and light during the seasons,causing disorientation to the unfamiliar personnel.
For means of protection, the use of water based suppression systems may be a hazard due to the
disposal of firewater water, which will freeze quite readily in exposed locations. This may also be
the case with exposed hydrocarbon fluid lines that, if isolated, say for an ESD activation, may
freeze up due to lack of circulation. This will hamper restart operations for the facility. Typical
use in the past has been the reliance on gases fire suppression agents for enclosed area, particularly
Halon. Other methods include fire water storage tanks that are kept warm, together with fire mains
deeply buried and continually circulated.
Desert Environments
Desert environments also pose different ambient
conditions than that normally encountered at most oil
and gas facilities. The most obvious is that the ambient
temperature level can reach extremely high levels, as
much as 54.4 Oc (130 OF) and that sand storms can be
expected to occur. Typical problems of free range
roving livestock ( camels, sheep, goats, etc.) with their
nomadic herders may also exist.
228
Special Locations, Facilities and Equipment
229
Special consideration of thermal relief for piping exposure to sunlight (solar radiation) needs to be
under taken. This is usually accomplished by painting with reflective paint or burial. Hydrocarbon
containing piping is usually painted in a reflective color (i.e., aluminum) for advantages of reflection
of solar radiation (heat input) to avoid thermal expansion of fluids in blocked systems.
Where facilities are exposed to the constant radiation of the sun, sun shades are provided over
exterior exposed equipment that may not function properly at elevated temperatures or would
deteriorate rapidly if left continual exposed to the direct sunlight. Most electrical or electronic
equipment is rated for a maximum operating temperature of 40 O C (104 OF) unless otherwise
specified, 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 foam
concentrates rubber hoses or other rubber components which may dry and crack.
Sand barriers and filters are provided on facilities and equipment where fresh air intakes are
needed. Sand storms can also cause abrasive actions to occur on exposed hardware that might
cause it to malfunction.
Signs, label and instructions exposed to direct sunlight may begin to fade after relatively short
periods after installation.
Offshore Facilities
Offshore facilities are dramatically different from onshore facilities because instead of being spread
out the equipment is segregated essentialiy into compartments or separated into a complex of
platforms. Offshore facilities pose critical questions of personnel evacuation and the possibility of
total asset destruction if prudent risk assessments are not performed. A through analysis of both
life safety and asset protection measures must be undertaken. These analyses should be
commensurate with the level of risk a particular facility represents, either in personnel exposed or
financial 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 and
production platforms may require the most extensive analysis.
Generally the highest risks in offshore facilities are blowouts, transportation impacts and process
upsets. Where inadequate isolation means are provided for either wellheads or pipeline
connections to the installation considerablefuel inventories will be available to an incident.
The helidecks of offshore facilities are usually povided at the highest portion of the offshore
installation for avoidance of obstructions during aircraft maneuvering and available space. As a
result the roof of the accommodation is typically selected. The location also facilitates evacuation
of personnel from installation by helicopter due to its proximity to the highest concentration of
personnel. This enhances one of the avenues of escape from the installation but also exposes the
accommodation to several hazards. The accommodation becomes subject to the hazards of
helicopter crashes, &el spillages, and incidental helicopter 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 Protection
foam water monitor coverage, that have a minimum duration of 20 minutes. The monitors should
be placed as a minimum on opposite sides of the deck, but preferably from three sides. The
monitors should be located below deck levels and provided with a heat radiation screen that can be
seen through. The helideck should be elevated above the accommodation by an air gap to ensure
vapor dispersals fiom fuel spillages. Fuel loading and storage for the helicopters should be located
so they can be jettison or disposed of in an emergency if they are located near the accommodation.
Offshore Floating Exploration and Production Facilities
Floating exploration and production facilities are sometimes provided on jackup rigs, semisubmersible vessels or ex-crude oil shipping tankers converted to production treatment vessels.
These facilities are essentially the same as fixed offshore platform or installations except they are
moored in place or provided with a temporary support structure instead of provided with fixed
supports to the seabed. The major process fire and explosion risks are identical to the risks
produced on offshore platforms. They have one addition major facility risk, that is the maintenance
of buoyancy of the installation. Should fire or explosion effects cause a loss of buoyancy (or evefi
stability) the entire facility is at risk of submergence. Adequate compartimization and integrity
assurances must be implemented in these instances.
u1
I
Pipelines
For the purposes of risk analysis a pipeline should be thought of as an elongated pressure vessel
with unlimited flow. They normally contain large inventories of combustible substances at elevated
pressures. Damage to an entire pipeline is highly unlikely and a damaged portion of a pipeline can
generally be easily replaced. The primary risks of pipelines are the exposures they pose to nearby
facilities and business interruption concerns. To maintain adequate protection against their
hazards, adequate siting, isolation and integrity assurances must 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 offshore
pipelines where there have been numerous incidents of dragged anchors from fishing vessels to
pipelines exposed on the seabed. A radius of exposure from a pipeline can also be easily calculated
for fires and vapor explosions based on the commodity, pressure, release opening, etc. From these
calculations a restricted zone or similar can be designated.
Isolation - It has been shown that the addition of isolation valves at periodic intervals is not as cost
effective as prevention measures such as thickness inspections or tests. However all pipelines
should 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 disaster
has shown. In that accident a contributing factor to the destruction was the backfeed of the
contents of the gas pipeline to platform once the topside isolation valve or piping lost its integrity.
Further isolation means @e.,a subsea isolation valve SSIV) were not available.
Integrity Assurances - When first installed piping systems will be checked for leakages at weld
joints and flange connections. Weld joints are usually verified by NDT radioactive means (Le., xray) or die penetrants.
Depending on the services, the pipeline will usually be hydrostatically or pneumatically tested.
Normally a section is specified for testing from flange point to flange point. Once tested the blank
flanges at the ends of the section are removed and the tested portions are permanently connected
Special Locations, Facilities and Equipment
231
for operational start-up. This usually leaves a flange joint or connection that has not be
hydrostatically tested and will be the most likely point of system leakage upon system startup.
Corrosion is by far the most serious hazard of pipeline incidents. It is imperative that adequate
corrosion monitoring programs be provided for all hydrocarbon pipelines. Order crude oil
pipelines operating at elevated temperatures appear more susceptible to corrosion failures than
other 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 the
seabed. Onshore pipelines are vulnerable to impacts from earth moving operations for construction
or road grading. On occasion impacts from mobile equipment may also directly strike and damage
the pipeline.
Wellheads - Exploration (Onshore and Offshore)
The primary concern with exploration wellheads is the possibility of a
blowout during drilling operations. A blowout is a loss of control of a
wellhead pressure. Normally the wellhead pressure in a well being drilled
is controlled with a counter balance of drilling "mud" that equalizes its
weight with that of the upward pressures of the oil or gas in the well. If
the 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 drilling
rig and its crew on the surface and the oil and gas forcing itself up the
well at 34.5 to 68,948 kPa (5 to 10,000 psi), is a stack of valves called
blowout preventers. In theory, they can stop the upward oil and gas
flow, as long as the well pressure is less than their seals are rated at, and
they are operated in time
(
/
An underground blowout can also occur during a drilling operation. An underground blowout
occurs when a loss of mud control occurs and the reservoir fluids begin to flow from one
underground zone into a zone of lower pressure. Because the loss flow is below the surface it is
considered an underground blowout and are more difficult and complex to evaluate and correct.
Drilling mud is a mixture of barite, clay, water and chemical additives. Initially in the early days of
exploration 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 to
lubricate the drill, remove cuttings and maintain pressure control. M e r exiting the drillhead it
circulates in the annulus of the wellpipe back to the surface where it is reused after the particulates
are removed By varying the weight of the drilling mud into the drillstack, wellhead pressure control
can be effectively maintained. Naturally occurring barite has specific weight of 4.2. Eight or nine
pound drilling mud is considered light and eighteen or twenty pound is considered heavy. Heavier
mud, containing larger quantities of barite is considerably more expensive than light mud, so a
drilling company may try to use the lightest weight mud possible when drilling a well. It has also be
theorized that heavier drilling mud might precipitate reservoir formation damage by blocking the
pores in the reservoir that the oil flows out of or through. On occasion such frugality and reservoir
concerns may have been a contributing factor leading to a wellhead blowout.
Blowout preventers (BOPS) hnction is to cut off the flow of potential blowout. In all wells being
drilled 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 are
annulus formed around the inner pipe. Any one of these under varying conditions can be a source
of through which oil or gas can escape during drilling. The annular preventer is a valve that appears
Handbook of 'Fire and Explosion Protection
as a rounded barrel and is positioned on top of one or more other blowout preventers in a preventer
stack. The annular preventer seals off the annulus area of the well, the space between the drill pipe
and 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 annular preventer allows fluid such as drilling mud to be pumped
down the hole to control the pressure while it prevents material from coming out. Blowout
preventers 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 more
pressure than an annular preventer and are the considered the second line of defense. There are
blind rams that seal off an open hole and pipe rams which are used to close a hole when drill pipe is
in use. There are also shear rams that simply cut 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. Blowout
preventers are operated hydraulically from an accumulator that should be located as remotely from
the wellhead as practical. The control panel for activation should be readily available at the drilling
operations and in some cases (such as offshore) a duplicate activation panel is provided at other
critical emergency control points.
The most common cause of a well to become uncontrolled and develop into a blowout is improper
mud control operations and the inability of the blowout prevention system to contain it because of
system failures, 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 explosion
hazards 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 laboratories
and operating companies indicates that the fire and heat radiation of a wellhead incident can be
considerably lessened when the water spray provided immediately at the wellhead is directed
upwards instead of downwards. Figure 12 shows the general results of tests conducted in the late
1980s that indicated the most efficient water spray geometry consisted of nozzles spraying parallel
to the flame axis based on the mass flow rate of water (Mw) to the mass flow rate of the released
gas (Mg).
Special Locations, Facilities and Equipment
RELATIVE EFFECTIVENESS OF VARIOUS SPRAY ARRANGEMENTS
AT WELLHEAD FLAMES
Figure 12
233
234
Handbook of Fire and Explosion Protection
It is also interesting that in 1970 Chevron pleaded "no contest" to charges of "knowingly and
willfilly" failing to install safety devices on 90 oil wells in the Gulf of Mexico. Three other oil
companies were similarly charged with the same offense (Shell, Conoco and Humble). At the time
Chevron was fined $ 1 million U.S. dollars for 500 violations under the Outer Continental Shelf
Lands Act. The violations involved failure to install safety chokes at the wells - i.e., a method to cut
off the flow of oil automatically in the event of incident.
Loading Facilities
Loading is one of the most hazardous operations in the
manufacturing and handling of hydrocarbon commodities. These ,
facilities represent a strategic point in the process that, if lost, may
adversely affect the entire operation of the facility. Pipeline transport is the preferred method of
material transport but cannot be accommodated in instances where smaller quantities are involved or
trans-ocean shipment is required. The most obvious hazards with loading facilities is the possibility
of overfilling, displacement and release of combustible vapors, concerns with static buildup, and
collisions with the transferring facilities and the carrying vehicle (primarily ships, barges or trucks).
Loading facilities should be sited where the shipping vehicles will not be exposed or expose other
processes during or traveling to and from the loading devices. All manual loading facilities should be
provided with self closing valves. A method for emergency isolation of product flow and transfer
pump shut down should also be considered for all facilities.
The primary area of protection should be centered around the fixed equipment at the product transfer
area, the highest probable leak or spillage location. These include the loading arms, hoses, pipe
connections and transfer pumps. Protection of the fixed equipment ensures rapid restart after the
incident with limited business interruption. Of secondary importance is the protection of the transfer
vehicle (ship, rail or truck). The most critical of these are large shipping vessels where considerable
monetary loss would be incurred. The immense size of some shipping vessels and loading
arrangements make protection of the complete vessel impractical. Risk analyses of shipping incidents
generally indicate the probability of immediate complete vessel fire involvement a low probability
versus the possible destruction from internal vessel explosions from vapor accumulations during
deballasting.
The most practical protection method for protection of ship and rail loading facilities is through fixed
monitors. Due to the relatively smaller size of truck loading racks and liquid spillage accumulation
they are normally protected with an overhead foam water general area deluge system supplemented
with nozzles directed at high leakage points. Some truck loading facilities have been protected with
large fixed dry chemical systems where the water supplies have not been adequate.
Electrical Equipment and Communication Rooms
Facilities that are located in hazardous areas are usually kept pressurized to prevent the egress of
hazardous vapors and keep the interior of the facility as non-classified electrically.
Switchgear and relay rooms are required to have smoke detection per NFPA 850, section 5.8.4 and
IEEE 979, section 2.7. The activation of the fire alarm should shut down the air handling system.
If the facility is especially critical to the continued hydrocarbon process consideration of a fixed fire
protection system should be evaluated.
Special Locations, Facilities and Equipment
235
Combustible gas detection for air intakes should be considered when the enclosures are in
proximity to hydrocarbon processes. This is especially important when the processes can be
demonstrated to be within areas where a WCCE release will not have dissipated at the distance the
facility is placed from it. An alternative is to have the air handling system self circulating so it does
not direct fresh air supplies in from the outside. Such systems are normally provided at unmanned
shelters.
Battery Rooms
Battery rooms are provide for back up and uninterrupted power supplies (UPS), for process control
functions. They are usually provided at or near the facility control room or electrical switchgear
facilities. Lead acid batteries when charged produce free hydrogen as a by product. The hydrogen
is vented from the batteries and released into enclosure. IEEE 484-1987, Section 5.1.4 and NFPA
850, Section 5-8.5,classify battery rooms as nonhazardous (per NFPA 70, Article 500) if adequate
ventilation is provided to the enclosure. Adequate ventilation defined by NFPA 850 is that less
than one percent hydrogen will accumulate in the room at any one time. IEEE defines adequate as
less than 2% hydrogen of the total volume of the battery area. The maximum hydrogen gas release
rate during charring is 0.000269 CFM per charging amphere per cell at 25 OC (77 OF), at one
atmosphere of pressure.
Typical industry practice is to provide an explosionproof rated exhaust fan in the exhaust system
for the battery room and classify the exhaust duct and a radius of 1.5 meters (5 ft.) from the
exhaust vent outlet at Div. I, Class 2 Group B. The light switch for the facility should be located
outside the battery room.
Where drainage provisions are provided to the battery room, the fluid should first collect into a
neutralizing tank before entering the oily water sewer system (OWS).
Where sealed and unserviceable batteries are used, these requirements do not apply since no free
hydrogen is released.
Fire detection capability is considered optional as the batteries themselves have little combustible
materials 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 Packages
Turbines and gas compressors are normally provided as a complete assembly in an acoustical
enclosure. Because the equipment is enclosed and handles gas supplies, it is a prime candidate for
the possibility of a gas explosion and fire.
The most obvious source a gas accumulation is a fuel leak. Other rare losses have occurred due to
lubrication failures, causing the equipment to over heat, with subsequent metal fatigue and
disintegration. Once disintegration occurs heat release from the combustion chamber will occur
along with shrapnel and small projectiles which will be thrown free from the unit from inertia
momentum of the rotating device.
Most enclosures are provided with a high interior air cooling flow that is also helpful to disperse
any gas release. Combustible gas detection is provided in the interior of the enclosure and at the air
exhaust vent. Fixed temperature devices are also installed.
The prime method of protection from a gas explosion in the enclosure is through gas detection and
236
Handbook of Fire and Explosion Protection
oxygen displacement or inerting. C02 or in the past Halon fire suppression systems have been
used as the inerting and fire suppression agents. The agents are stored outside, at a convenient
location, and applied to the appropriate hazard. ESD signals shut off the fuel supplies to the
turbine once an incident occurs. Of critical importance is integrity protection to the ESD fie1
isolation valve and its control from the incident itself.
A one hour fire wall or "substantial space" should be provided between the turbine and gas
compressor. The utilization of explosion blow-out panels in the acoustical enclosure will also limit
damage from an explosion. Although strengthen panels could be provided to protect against
shrapnel ejection, the cost installation coupled with the low probability of such an occurrence and
the low personnel exposure periods, generally render this a non-cost effective safety improvement.
Heat Transfer Systems
Heat transfer systems are normally provided to utilize available process heat, to economize heat for
distillation purposes or to preheat fuel supplies before usage. They are generally considered a
secondary process support system to the main production process, however they may be so critical
to the process that they might be considered a single point failure if not adequately designed.
Most heat transfer systems are of a closed loop design that circulates a heat transfer medium
between heaters and heat exchangers. Circulation pumps provide flow and regulating valves are
used for process control. The heat transfer medium is usually steam, a high flash point oil, or in
process plants flaniniable liquids and gases. Inherently steam is a safer medium to use and is
preferred over other mediums. When steam supplies are unavailable high flash point oils (organic
or synthetics) are sometimes used.
For oil systems, commonly referred to as Hot Oil systems a reservoir is sometimes provided in an
elevated storage tank. The fire risks associated with the Hot Oil systems comprise the temperature
of the circulating oil, location of transfer pumps and protection of the storage reservoir. The
circulating oil may be heated to above it's flash point, therefore producing a "flammable" liquid in
the system rather than a combustible liquid. This may be hrther compounded by the fact the
circulating system (i.e., pumps, valves, and piping) may also eventually reach temperatures above
the flash point of the combustible circulating oil (through conduction with the circulating oil), so
any leak may be immediately ignited.
Small Hot Oil systems are sometimes provided as a prefabricated skid package with pumps, valves
and elevated oil storage on the same skid. Any leak from the circulating pumps will immediately
endanger the components on the skid and storage tank. The circulating pumps seals are usually
source of leakage on the system. Leakage of the medium being heated, usually low flash point
hydrocarbons, into the Hot Oil systems occurs on occasion, further increasing the fire risk
unexpectedly. Such leakages may precipitate considerable low flash point hydrocarbon liquids such
that the Hot Oil eventually takes on the characteristics of a flammable liquid, essentially creating
major fire risk, akin to a process vessel operation instead of an inherently safe heat exchange
system. Should leaks should be immediate corrected and a means to degas the system should also
be incorporated.
If the system itself is critical to production opeiation, the pumps may be the most siriglc ci ttical
components. They should be adequately located away from other process risk and provided with
typical drainage facilities (containment curbing, surface grading, sewer capability, etc ). The
collapse of the storage tank should be analyzed to determine what impact it would have on the heat
transfer 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 storage
temperature is above its flash point its structural supports should be fireproofed. Otherwise
Special Locations, Facilities and Equipment
237
fireproofing of the supports may not be economicallyjustified. Consideration should also be given
to design the amount kept in storage to the minimal amounts.
Cooling Towers
Cooling towers provided at most process industries are typically constructed of combustible
materials. Although abundant water flows through the interior of the tower, outside surfaces and
some interior portions remain totally dry. During maintenance activities most cooling towers are
also not flowing and the entire unit may become dry. The principal causes of cooling tower fires
are electrical defects to wiring, lighting, motors and switches. These defects may in turn ignite
exposed surfaces of the dry combustible structure. On occasion hydrocarbon vapors are released
from 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 will
increase the probability of an electrical hot spot ignition to a wooden combustible surface.
NFPA 214, "Water Cooling Towers", provides guidance in the design of fire protection systems
and protective measures for cooling towers constructed of combustible materials. Specific
protection for the interior of the cooling tower combustible materials but also for the probable
source of origination @e., motors) should be made. Where they are critical to operations, a
sprinkler system is usually provided otherwise fire hose reels or monitors are installed. High
corrosion protection measures must be considered whenever a sprinkler system is provided for a
cooling tower due to the interior environment of the cooling tower which is ideally suited for
corrosion development to exposed metal surface. There is an increasing industry trend to use
noncombustible materials of construction for the installation of cooling towers due to their fire
hazard characteristics and high maintenance costs associated with fire protection measures.
Oil Filled Transformers
Transformers filled with combustible oils pose a fire hazard. Transformers should be adequately
spaced 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 a
transformer should drain into a gravel covered basin which prevents spillage from being exposed
but allows drainage to be collected.
Depending on the criticality and value additional fire suppression systems are provided for
protection. NFPA 850 section 5-8.6 recommends that oil-filled station and start-up transformers at
power generation plants be protected with a water or foamwater spray system. The most common
installation is a fixed water spray. Where several transformers are provided, a firewall is commonly
used to separate and 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 and
combustible liquids are within the requirements of NFPA. Normally a vapor collection hood is
provided when sampling and measurements are conducted with exposed liquids. The primary
concern is the exhaust of vapors and the storage and removal material saturated with liquids. The
exhaust hood, ducting and a radius of 1.5 meters ( 5 ft.)from the exhaust vent should be considered
an electrically classified area.
238
Handbook of Fire and Explosion Protection
Warehouses
Warehouses are normally considered low risk occupancies unless high value or critical components
are 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 the
economic benefits of installing an automatic sprinkler system should be investigated.
Cafeterias and Kitchens
Wet 01-dry chemical fixed suppression systems are typically provided over the kitchen cooking
appliances and in exhaust plenums and ducts. Activation means is afforded by fusible links located
in the exhaust ducts/plenums usually rated at 232°C (450°F). Manual activation means should not
be provided near the cooking area, but in the exit routes from the facility. The facility fire alarm
should sound upon activation of the fixed suppression system and power or gas to the cooking
appliances should be automatically shut off. The ventilation system should also be shut down by
the activation of the fire alarm system. Protective caps should be provided on the suppression
nozzles to prevent plugging horn grease or cooking particulates.
Special Locations, Facilities and Equipment
239
Bibliography
1.
Chauvin, M.R. and Bourgoyne, Jr., A. T., An Experimental Study of Suppression of Obstructed Gas Well Blowout
Fires Using Water Sprays, NBS-GCR-88-547, National Bureau of Standards (NBS), Center for Fire Research,
Gaithersburg, MD, 1988.
2.
Crawford, J., Offshore Installation Practice, Butterworths, London, U.K., 1988
3.
EDM Services Inc., Hazardous Liquid Pipeline Risk Assessment, California State Fire Marshal, Sacramento, CA,
1993.
4.
French Oil and Gas Industry, Blowout Prevention and Well Control, French Oil and Gas Industry
AssociationEditions Technip, Paris, France, 1981 .
5.
Gas Processors Association (GPA), Gas Processing Facility Safe& Inspection Checklist, GPA, Tulsa, OK, 1987
6.
Gowar, R. G., Develooments in Fire Protection of Offshore Platforms, Applied Science Publishers, London, 1978
7. Grouset, D. et. al., "BOSS: Blow Out Spool System", Fire Safety Engineering, Second International Conference,
pages 235-248, BHRA, Cranfield, UK, 1989.
8.
Institute and Institute of Electrical and Electronic Engineers, Inc. (IEEE), IEEE Std. 484. Recommended Practice for
Installation Design and Installation of large Lead Storage Batteries for Generating Stations and Substations, IEEE,
New York, NY, 1987.
9.
Institute of Electrical and Electronic Engineers. Inc. (IEEE), IEEE Std. 979-84. Guide to Substation Fire Protection,
IEEE, New York, NY, 1988.
10. Littleton, J. "Proven Methods Thrive in Kuwait Well Control Success", Petroleum Engineer International,pages 3 1-
3 7, January 1992.
11. National Fire Protection Association (NFPA), NFPA 37. Installation and Use of Stationan, Combustible Engines
and Gas Turbines, NFPA, Quincy, MA, 1994.
12. National Fire Protection Association (NFPA), NFPA 45, Fire Protection for Laboratories Using Chemicals, NFPA,
Quincy, MA, 1991,
13. National Fire Protection Association (NFPA), NFPA 69. Explosion Prevention Svstems,NFPA, Quincy, MA, 1992.
14. National Fire Protection Association (NFPA), NFPA 214. Water Cooling Towers, NFPA, Quincy, MA, 1992
15. National Fire Protection Association (NFPA), NFPA 850. Fire Protection for Electric Generating Plants, NFPA,
Quincy, MA, 1992.
16. Paterson, T., Offshore Fire Safety, Penwell Publishing Company, Houston, TX, 1993
17. Pedersen, K. S., STF88 A83012. Fire and Explosion Risks Offshore. The Risk Picture, SINTEF, Tronhiem,
Norway, 1983.
Chapter 21
Human Factor and Ergonomic Considerations
Human factors and ergonomics play a key role in the prevention of accidents. Some theories attribute up to
90% of all accidents are caused by human factor features. It is therefore imperative that an examination of
human factors and ergonomics be undertaken to prevent fire and explosions at petroleum facilities since
historical experience have also shown it is a major contributor either as a primary or underlining cause.
Human factors and ergonomics concern the ability of personnel to perform their job functions within the
physical and mental capabilities or limitations of a human being. Human beings have certain tolerances and
personal attitudes. Tolerances can be related to the ability to accept information, how quickly the
information can be understood and the ability and speed to perform manual activities. When information is
confbsing, lacking or overtaxing, the ability to understand and act upon it quickly or effectively is absent. It
is therefore imperative to provide concise, adequate and only pertinent information to do all the tasks
associated with petroleum activities. This includes activities associated with emergency fire and explosion
protection measures.
Attitudes reflect the leadership of management or personnel traits of the employees and if not constuctive
can lead to negative influences which can precipatate accidents.
It should also be realized that it may be virtually impossible to eliminate human errors
fiom occurring and therefore additional safeguards are always necessary. Personnel may
forget, become conhsed or in some cases, are not admittedly knowledgeable in the
tasks at hand, especially during stressful environments. It is therefore usefil in critical
operations to design systems that might not only be specified as fail-safe, but also be
considered ''foolproof'', This applies to not only to the design of the system for
operation but for maintenance activity periods, the time when most of the historically
catastrophic incidents have occurred.
A human error or reliability analysis (HRA)can be performed to identify points that may contribute to an
accidental loss. Human errors may occur in all facets of a the hydrocarbon industry. They are generaIIy
related 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 are
normally predicted as indicated in Table 29. Individual tasks can be analyzed to determine the probability of
an error occurring. From these probabilities, consequences can be identified which deterdine the risk of a
particular error.
240
Human Factor and Ergonomic Considerations
Probability
1.0
-
0.1
0.1 - 0.01
0.01
-
0,001
0,001 - 0.0001
0.0001
-
0.00001
241
Description
I
Processes involving creative thinking, unfamiliar operations, a
short period of time, or high stress.
Errors of omission, where dependence is on situation cues and
memory.
Errors of commission, i.e. operating wrong button, reading
wrong display, etc.
Errors regularly performed in commonplace tasks.
Extraordinary errors for which it is difficult to conceive how
they might occur, occurring in stress free environments with
powerfUl cues.
Table 29
Probability of Human Errors
Drug and alcohol influences will also contribute to an accidental event occurring. Locations where strict
controls or testing for such influences have a relatively lower level of accident occurrences.
242
Handbook of Fire and Explosion Protection
Human Attitude
The single most influence effect of human performance is attitude. Attidtude is the mind set, point of view
and the way we look at things. The way we look at things is the partly responsible for the nature of our
behavior and performance. Some of the more common attitudes which influence accidental behavior are
listed below:
Attitude
DescriDtion and Conseauences
Apathy or Indiffernce
Sluggish, don't care, passive, not alert. Such attitude has a detrimental
affect on co-workers in that it can infect the entire organization.
Complacency
Satisfied, conte t and comfortable. This happens when things are going
smoothly. The workers then drop their guard and become vulnerable.
Hostility
Getting angry or mad. Chip on the shoulder and argumentative,
sometimes sullen. Vision narrows and they become victims of unseen
hazards.
Impatience
Hasty, hurried and anxious. Impatience makes you do things you
wouldn not normally do. This increases the risk taking mentality,
especially if peer pressure is involved.
Impulsiveness
Spontaneous or spur-of-the-meonent. This is the risk taking activity and
can activate the act first and ask questions later attitude.
Impunity
No penalty or consequence, it can$ happen to me.
sanctions.
Invulnerability
Invincible, superman complex. Invulnerabilityis an illusion that does not
recognize reality.
Negligence
Lax, remiss or not prudent. This is a failure to do what should be done
or deliberately doing what should be done. Forms the basis of most
negative legals actions.
Overconfidence
Brash, risk taker. May take short cuts
Rebelliousness
Defiant, disobedient, rule breaker. Often in hostile nature. Difficult to
work with.
Recklessness
Irresponsible, not trustworthy or reliable, often self centered. A risk
taker.
No Ownership
No personal stake in anything. This is the opposite of accountability.
Immune from
The treatment for most of these attitudes is the developement of an effective loss prevention team culture
within the company, (i.e,, led by senior management, with employee involvement), that demostrates the
mutual benefits of an accident free environment.
Human Factor and Ergonomic Considerations
243
Access and Acceptability
Fire fighting equipment should be mounted at heights that are easily accessible by the average person. This
includes portable fire extinguishers, hose connections to fire hydrants, access to emergency shutoff valves,
emergency stopESD push buttons, etc.
Process control, valves and control panels should be easily accessible and viewable. ASTM standard F- I 166
provides graphical charts for the physical means to view and operable controls and instruments.
Instructions, Markings and Labeling
There are six basic categories of signs. These are normally considered the following:
Fire Fighting - Those giving information or instructions about fire .prevention and fire fighting
equipment (e.g., No Smoking, no open lights, etc.).
0
0
Mandatory - Those giving instruction or information that must be obeyed or observed (e.g.,
security).
Emergency - Those giving instructions to be followed in case of an emergency
Warning - Those giving information that should be heeded to avoid possible dangerous
occurrences (e.g., toxic gas).
0
0
Prohibition
- Those that prohibit a particular activity (Le., no horseplay)
General - Those that convey general information of a non-critical nature not covered by the
five categories above.
Instruction signs should be posted at all emergency systems in which the operation of the unit is not
inherently obvious (i.e., fire pump startup, fixed foam systems, etc.). Flow arrows of water flow should be
provide on piping where the isolation means is provided. Number of hydrants, monitors, pumps, foam
chambers can all enhance the operational use of such equipment. Control panel labels should be provided
which are descriptive instead of just numerical identifications.
Warning and instructional signs and instruction should be primarily provided in the national language of the
country of operation. They should be concise and direct. Use of jargon, slang or local dialect references
should always be avoided, as these may not always be correctly interpreted. Abbreviations should be
avoided unless the abbreviation is commonly known and used by the population, versus the descriptive word
or words.
Labels should be as precise as possible without distorting the intended meaning or information. They should
not be ambiguous, use trade names, company logos or other information not directly involved for
performing the required functions.
The following are common problems that may be faced in hydrocarbon facilities pertaining to labeling:
- Poor or missing labels.
- Similar names are used which may be confbsed.
- Supplied labels not understood.
- Labels are not provided in a consistent format.
- Labels (ie., equipment) are not specified in a sequential or logical order.
244
Handbook of Fire and Explosion Protection
Color and Identification
Colors
Standard colors have been adopted in the industrial world for the identification of physical hazards, marking
of safety equipment, and operating modes of typical equipment. These conventions have been incorporated
into standards used worldwide for the recognition of such devices and are categorized by the following color
coding.
Table 30
Color Coding Applications
The colors purple, brown, black, and gray have not been assigned a safety connotation. Specific color codes
are also employed in the identification of alarms panel indicators, piping, compressed gas cylinders, electrical
wiring, fire sprinkler temperature ratings, etc. Although these sometimes do not correspond with similar
meanings.
Human Factor and Ergonomic Considerations
245
It should also be mentioned that there may be slight confusion by certain color indicating lamps or button by
the industry. Typically the industry uses red for hazardous running conditions (e.g., operating a pipeline
pump) versus the common traffic signal of red for stop and vice versa. Red is also used as the color of ESD
push buttons to stop an operation. On the face value it appears that this is a conflict of meanings. If the
overall meaning of hazardous versus safe is kept in mind then the colors have more relevance. NFPA 79
provides definition of when a particular color is used, however this may be slightly confusing to personnel
new to the industry as the example of red above highlights.
Numbering and Identification
Process instrumentation displays should be arranged in relation to each other according to their sequence of
use or functional relationship to the components they represent. They should be arranged in their functional
groups, 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 from
approximately 30 meters (100 ft.) away. It should be viewable from the normal access points to the facility
or equipment and is of colors contrasting with the surrounding background. The identifications normally
consist 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 quick
identification of process equipment is critical and necessary from a distance.
Instrumentation Alarm Overload
Process alarms should be arranged to provide a major common alarm that is supplemented by an individual
indicator, e.g., a master alarm should be provided to indicate the status of the entire subsystem components.
Multiple simultaneous alarms that can overload the senses of an operator should be avoided.
Noise Control
High noise levels emitted by facility equipment can damage the hearing of personnel working at the plant, be
a nuisance to the local community, and interfere with the annunciation of emergency alarms and instructions.
The principle sources are rotating equipment (pumps, compressors, turbines, etc.), air-cooler fans, furnaces
or heaters, vents and flares. Noise levels may be extremely high during an emergency due to operation of
relief systems, depressurization, blowdown and ff are systems operating at their maximum capacities without
adequate measures to control the ambient noise levels.
Distance is a major factor in reducing nuisance noise and suitable spacing should be considered in the plant
initial layout. The acceptable amount of noise generation should be specified on the purchase order for the
equipment. Where sound levels cannot be alleviated by purchasing a different make of equipment, sound
attenuation devices should be fitted (i.e., enclosures) as an alternative.
Whenever ambient noise levels are above emergency alarm signals or tones, flashing lights or beacons should
be considered that are visible in all portions of the affected area. The color of flashing lights should be
consistent with the safety warning colors adopted at the facility.
Handbook of Fire and Explosion Protection
246
Panic
Panic or irrational behavior is likely to be generated during any hydrocarbon emergency. It is the result of
unfamiliarity, conhsion and fright. Panic affects individuals in different irrational outcomes. Panic may
exacerbate the consequences of an explosion or fire incident in relation to the function of or lack of function
by the responsible personnel. It has been observed to affect personnel in the following ways:
It may produce illogical or indecisive actions to control or minimize an incident, for example
opening the wrong valve or failure to activate process emergency controls or instructions.
Personnel may impede escape mechanisms by using the wrong routes, not being organized for
orderly evacuation, etc.
0
It may produce hyperactivity in personnel. Hyperventilation will exacerbate the effects of
irritants or toxic gases present.
0
Personnel required to perform emergency hnctions may just freeze or become unable to
undertake decisive actions. Without decisive action they will succumb to the ever increasing
effects of an incident.
Training, clear instructions and personal self assurance are 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 and
procedures. During an emergency, adequate instructions should be issued to all personnel. Mechanisms that
can be automated once an emergency has been realized should be considered in order avoid the "human
element" .
Security
Unfortunately most hydrocarbon facilities are key political instruments for international
affairs. Numerous terrorist activities have been directed towards these installations,
either as figurative demonstrations or for real intent of destruction. Additionally
industrial facilities can become the target of labor unrest.
Management should consider these threats are real and consider contingency planning
for major events similar to accidental hydrocarbon incidents. Key isolation and shutdown mechanism should
have the utmost integrity where shut threats are realized.
Facilities should be provided with appropriate barriers to prevent unauthorized entries to the general public
and employees not required to be put at risk from their normal job duties.
Accommodation of Religious Functions
In 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. These
activities must be respected and accommodated for the employees and any personnel who may be in
attendance at the facility. Typically where hydrocarbon facilities are located in areas were such practices are
performed, a specialized installation (ie., mosque) is normally provided. The primary concern in their
application is that the installation does not interfere with the operation of the facility, is not provided within
the confines of a hazardous location (i.e., process location), and that it is shielded or removed from the
effects of an explosion or fire. Typical applications provide these specialized facilities just outside the
security fencing and access gate a facility.
Human Factor and Ergonomic Considerations
247
Bibliography
1.
American National Standards Institute (ANSI), A13.1. Scheme for the Identification of Piping Systems, New York,
NY, 1993.
2.
American Petroleum Institute (API), Standard 615, Sound Control of Mechanical Equipment for Refinew Services,
API, Washington, D.C., 1987.
3.
American Petroleum Institute (API), Publication 1637 Usin? the API Color Code Svstem to Mark Equiument and
Vehicles For Product Identification at Service Stations and Distribution Terminals, First Edition, API, Washington,
D.C., 1986.
4.
American Society of Testing Materials (ASTM), F-1166-88. Standard Practice for Human Engineering Design for
Marine Svstems, Eauiument and Facilities, ASTM, 1988.
5.
British Standards Institute (BSI), BS 1710, Piping Identification Colors, BSI, London, U.K.
6.
British Standards Institute (BSI), BS 5266 Emergencv Lighting, BSI, London, U.K.
7.
British Standards Institute (BSI), BS 5378: Parts 1.2. and 3: Safetv Signs and Colors, BSI, London, U.K.
8.
British Standards Institute (BSI), BS 5395. Stairs. Ladders and Walkwavs Part 3. Code of Practice for the Design of
Industrial T w e Stairs. Permanent Ladders and Walkways, BSI, London, U.K., 1985.
9.
British Standards Institute (BSI), BS 5499: Fire Safetv Signs. 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 Safety Executive (HSE), Booklet HS(G)48, Human Factors in Industrial Safetv. HMSO. London, U.K.
12. Illuminating Engineering Society of North America (IESNA),, 1991.
IESNA, New York, NY,
13. Illuminating Engineering Society of North America (IESNA), Lighting Handbook, (Chapters 20 & 33), IESNA,
New York, NY, 1991.
14. International Organization for Standardization (ISO), I S 0 508: 1966, Piping Identification Colors, ISO, Geneva,
Switzerland, 1966.
15. International Organization for Standardization(ISO), I S 0 1503:1981, Ergonomic Principles of the Design of Work
Systems, ISO, Geneva, Switzerland, 1981.
16. International Organization for Standardization (ISO), IS0 6309: 1987 Fire Protection - Safetv Sims, ISO, First
Edition, Geneva, Switzerland, 1987.
17. International Organization for Standardization (ISO), ISO, IS0 8995: 1989. Principles of Visual Ergonomics - The
lighting of Indoor Work Systems, Geneva, Switzerland, 1989.
18. Miller, G. E., “The Omission of Human Engineering in the Design of Offshore Equipment and Facilities, How
Come?”, OTC 6481,22nd Annual Offshore Technology Conference, Houston, TX, 1990.
19. National Electrical Manufactures Association, 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 Protection
2 1. Woodsen, W. E., Human Factors Design Handbook, McGraw-Hill Inc.,New York, NY, 198 1
APPENDIX A
TESTING FIREWATER SYSTEMS
249
250
Handbook of Fire and Explosion Protection
Appendix A.l
Testing of Firewater Pumping Systems
The following is a generic test procedure that may be used to achieve flow performance tests of fixed
firewater pumps. The purpose of this procedure is to provide operations and engineering personnel,the basic
steps and engineering knowledge to adequately and efficiently perform the performance testing that may be
necessary by company polices and procedures. The procedure should be revised and modified to suit the
particular facility equipment under evaluation by adding identification numbers and locations as appropriate
to highlight the exact items and valves set ups that are necessary. The procedure should be according to
local work permit procedures.
Testing periods should be arranged with the appropriate management of any installation through the
approved work orders or permits of the facility. Careful observations of the equipment under test should be
made to observe any abnormalities and signs of impending failures. The operational testing area should be
restricted to the personnel solely involved with the testing.
Normal fire protection practices and standards recommend fire pumps be tested annually to determine
performance levels. Common practice in the petroleum industry is to trend the result of flow performance to
prepare predictive maintenance and replacement forecasts. Such forecast can predict poor pump
perfoniiance and prepare measures to implement corrective actions before this occurs.
Basic Procedure
1. Obtain the manufacturers pump curve for the unit to be tested. Confrm the pump to be tested is
properly identified, i.e., veri@ nameplate tag number, serial number, etc.
2. Ensure that calibrated pressure gages 0 - 1,380 H a (0-200 psig) are installed on the suction and
discharge of each fire pump to be tested. (Record calibration dates on the flow performance data sheet).
For pumps taking suction lift calculate the NPSH to the level of pump discharge. Offshore installations
vertical turbine fire pumps require a calculation of vertical head loss to the point of pressure reading
taking into account tide levels and seawater densities.
3. Determine the flow measurement method to be used during the test, Le., flowmeter or pitot tube
measures of the nearest available water outlets on the system. Ensure that the flow measurement
devices 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 are
available and 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 system
discharge valve 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 valve
only during testing period, if not leave relief valve in service during testing activities.
7. Open the pump discharge valve approximately 50%.
8. Start up pump and let run for a minimum of I5 minutes, for stabilization of the mechanical systems.
Appendix A Testing Firewater Systems
251
Adjust driver (i.e., engine) rpm to operate to the pump as close as possible to it's rated rpm performance curve.
9.
Record five pressure (inlet and outlet) and flow readings for the pump near the following rated flow
points - 0%, 50%, loo%, 125%, & 150%, simultaneously recording the rpm. The time of flow is
dependent 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 conditions
permit data should be plotted immediately during the test to indicate abnormalities that may be
corrected, e.g., partially closed or open valves.
11. Continuous monitoring of engine and pump should be maintained during the test. Special attention
should 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 to
the attention of the maintenance personnel immediately.
Supplemental Checks
For engine driven units, a sample of the fuel supply in the day tank should be taken It should be analyzed for
indications of water or sediment contamination. The sample should be allowed to stabilize for 24 hours to
determine content. Entrained water will collect at the bottom of the sample container and hydrocarbon
fluids will collect on top of it. Particulates will settle to the bottom.
Verify not leakages of oil or water for engine driven units.
connections for water cooling and fuel supplies.
Especially check condition of flexible
Verify pump start up on low pressure indication if such capability is fitted.
Correction Factors for Observed Test RPM to Rated RPM of Driver
Flow 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 Protection
Typical Data Form for Fire Pump Testing
SUPPLEMENT FIRE PUMP TEST INFORMATION
PUMP NO.
LOCATION:
DATE OF TEST:
By:
or Meter
Feet
TIDE
Correction for GPM:
-------RATED RPM
Correction for PSI:
-------RATED RPM2
X GPM = CORRECTION FACTOR
PUMP RPM
PUMPR P M ~
X PSI = CORRECTION FACTOR
TEST POINT CORRECTION
X CF(
GPM
X CF(
PSI
NOTE:
TEST POINTS
)=CORR.
)=CORR.
GPM 1 . 2 . 3 . 4 . 2 . 6 .
-6-5-4.3-2-1P
S
l
Each Change in Pump Speed requires calculating a new correction factor.
DRIVER:
PERFORMANCE
Smooth
Temperature
Low-
Fuel Level
114
Rough
Normal11'2
34
High-
FUU
Note any unusual noise, smoke, or mechanical condiion
Fuel Sample
Clean-
Dirty-Water-
Comments
RIGHT ANGLE DRIVE:
Smooth
Rough
Comments
PUMP PERFORMANCE:
Flow:
Yo Above
% Below
Rated Curve
Pressure:
% Above
% Below
Rated Curve
Comments
Other
Appendix A Testing Firewater Systems
253
Supplemental data pump testing form
FIRE PUMP TEST REPORT
PUMP
No.
DRIVER
Start
Mfg.
Type
Rating
stop
RPM
Type
Power
Engine Hours
Gear Ratio
Location
Frne:
CALIBRATION DATES:
Flow Meter
m
m
u1
Y)
Setting PSI
PSV-PSV
Gages
10
Mlg.
M
m
80
Po
IW
110
GPM
PERCENT RATE CAPACITY
120
BAR
l
a
IUI
iw
im
im
180
254
Handbook of Fire and Explosion Protection
Appendix A.2
Testing of Firewater Distribution Systems
General Considerations
Testing of firewater distribution systems is accomplished to determine if the condition of system is adequate
to support a WCCE need for firewater. The condition of piping, leaks, existence of closed valves or
sediment, operability of valves and monitors, etc., should be determined annually.
Typically a network of firewater systems mains is provided in a facility that form loops. These can be
segregated into sections or legs and the performance of each can be determined by flow test. Flow tests
release quantities of water that are measured and graphed. Performing an initial acceptance baseline test and
recording the results from year to year can portray the performance of the firewater system and projections
of 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 water
distribution systems.
Determine which fire main is to be analyzed. Within this segment select the hydrants that are the most
remote on the system fiom the source of supply. (Most remote is intended to mean the most remote
hydraulically and the selected hydrants may not be the most remote physically). A test hydrant and flow
hydrant(s) are identified. The data collected will refer to the test hydrant. The flow hydrant is the next
downstream hydrant(s) from the test hydrant.
It is imperative that the water in the mains is flowing in one direction only during the test (i.e., from the test
hydrant to the flow hydrant). In the case of looped and gridiron mains, the water may be flowing in two
directions and then issuing fiom the flow hydrant depending on the particular test being undertaken.
Appendix A Testing Firewater Systems
255
TEST PROCEDURE
Make preparations to conduct the testing - prepare scheduling, coordinate with operations, obtain
calibrated gages, ensure water flows will not affect operations, etc.
Choose the Test Hydrant and record the date, time, and location of the test. Remove one of the hydrant
outlet caps and attach a recently calibrated pressure gage fitted with a petcock valve. Slowly open the
hydrant and bleed off any trapped through the petcock valve on the pressure gage cap, then close the
petcock valve.
Record the reading on a pressure gage as the Fire Flow - Static Pressure. (Leave the test hydrant valve
open).
Continue along the main in the direction of water travel to the next hydrant identified as the flow
hydrant(s). Remove the hydrant outlet caps and veri@ the outlet internal diameter to the nearest 1/16 of
an inch.
Determine the hydrant coefficient of discharge, "C" (See Appendix B.4).
Slowly open the hydrant full bore and wait about 30 seconds or longer until the flow is stabilized and a
clear stream is established.
Insert the pitot flow measuring device into the hydrant water flow, bleed off air from the pitot tube, and
then measure the pitot gage pressure. The pitot tip should be inserted in the center of the water flow
stream at a distance of 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 206.9 W a (10 and 30 psi).
If the pitot gage readings are higher than this open another outlet on the hydrant and pitot both the
flows 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, if downstream of the test hydrant. If more than one outlet
was 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 nozzle
should be placed on the flow outlet to reduce the size of the opening and increase the flow pressure.
Simultaneously with the previous step, record the pressure on the test hydrant as the Fire Flow Residual
Pressure.
If a pressure gradient of the entire system is desired, additional pressure cap gages can be placed along
several points of the water main from the source of supply to the flow hydrant and these pressure
readings taken for each flow measurement.
If a second test point is desired, the flow hydrant outlet may be throttled to any desired point and the
pitot gage pressure read along with the Fire Flow Residual Pressure. Obtaining a second flow point will
improve the accuracy of the flow test data.
If no fkrther test readings are necessary, restore the system back to normal by slowly closing all hydrant
valves and replacing the outlet caps. Ensure all water has stopped flowing and the hydrant is drained of
water before replacing the cap.
256
Handbook of Fire and Explosion Protection
When water flow encounters a loop or grid, two features occur - (1) the flow splits into a determinable ratio,
and (2) the pressure drop across each of the two legs will be the same.
There are four methods to test a loop or grid system:
Isolate the Legs
By closing the proper sectioning valves, the water can be forced to flow through one of the legs only. M e r
recording 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 (provided the
facility pumps have the capacity and pressure).
Chose Two Hvdrants on a Large Main
Normal water paths are always in the direction of least resistance, in other words, generally from the larger
mains to the smaller mains. By choosing two hydrants on a large section of pipe (within a loop or grid) and
estimating the water flow direction, a test can be conducted.
Simultaneous Flow
In a multi-supply system in which good pressure and volumes are present, this method is desirable. Choose
a symmetrically centered hydrant (this is the Test Hydrant) and simultaneously flow two or three hydrants.
Obtain the two or three pitot readings.
Single Hvdrant Flow Test
This method uses a single hydrant as the Test and Flow hydrant. Static, Residual and Flow pressures are all
read from the same hydrant. This technique is considered to produce higher levels of error with the test data
than other methods.
Appendix A Testing Firewater Systems
257
Preparing Test Results
The total flow available at any point in a system is sometimes stated as the "gpm available at 137.9 kPa (20
psi) residual pressure". The 137.9 Wa (20 psi) is a safety factor which fire departments or company fire
brigades should be well aware so as not to damage the water mains. Usually most fire water tests are
comparing the results from year to year to determine if deterioration of the mains is occurring (pressure
gradient graph) or the available water supply and pressure in a particular area for design of a new fixed fire
water system. Therefore the complete water supply graph for a particular is always useful.
Hydrant Flow Data
Readily available flow tables are available that provide the amount of flow through a given size orifice, given
the pitot pressure reading. All pitot flow measurements should be first converted from a pressure reading
into a flow reading and then corrected for the outlet discharge coefficient by multiplying by the appropriate
factor. The results of the individual flow for each hydrant can then be plotted by marking the static pressure
at no flow and then the flow at the residual pressure. Connecting the points provides flows and pressures at
any desired point. The graph can be used a visual presentation of all the pressures and volumes that can be
expected at the test hydrant through the water mains.
258
Handbook of Fire and Explosion Protection
Appendix A.3
Testing of Sprinkler and Deluge Systems
Wet and Dn, Pipe Sprinklers
Wet and dry pipe sprinklers are not functionally tests for coverage since design codes have
eliminated problems with distribution patterns, provided the installation has been adequately inspected. The
normal testing verifies adequate pressure is available, piping is not plugged and activation of alarms occurs.
Main Drain - a flow of the main drain is accomplished which provides an estimate of the residual system
water pressure for the system. Condition of the water will also confirm if supplies are clean and dries
fiee.
Inspectors test - inspector test flows are accomplished on each portion of the system where fitted to
ensure system flow can be accomplished.
0
-
Alarm Activation all systems should be fitted with alarms that will indicate if water flow has occurred.
The alarm activation should occur with the activation of one sprinkler head and usually simulated by the
fitting of an orifice at the inspectors test outlet.
Deluge Svstems
A hll hnctional wet test of the deluge system is normally accomplished. This test ensures coverage and
density patterns are being achieved. A calculated collection pan can be provided during the testing to
confirm the density rate per minute. The mechanism to activate the deluge should be tested under conditions
that will simulate as real as can be reasonably obtained. Where equipment to be protected is not normally in
place, Le., ships, trucks or rail cars, the test should not be conducted until they are in their normal position
during operations.
Appendix A Testing Firewater Systems
259
Appendix A.4
Testing of Foam Systems
Foam systems are provided wherever there are large quantities of liquid hydrocarbons that pose a high risk.
The primary concern with foam system performance is the proper production of foam and the time to
provide adequate foam sealage coverage to the designated area.
Foam systems are designed to proportion liquid foam concentrate in the foamwater distribution network at
certain ratios usually expressed in percentages. The most common of these are I%, 3%, and 6%. The
foamwater can then be aspirated or non-aspirated to the appropriate liquid surface as the risk demands. The
foam production should be verified it is being proportion in the ratio designed for the system otherwise foam
consistency may be inadequate and foam supplies will be consumed at rates higher than expected.
Coverage confirmation, time to provide full foam coverage, leaks, blockages, rupture disk function, age of
foam, portioning calibration mechanisms, performance of delivery pumps or bladder tanks, foam drain times,
etc. should be verified for each unique system. NFPA 11 provides guidance in the specific test requirements
for several characterisiticfoam systems.
260
Handbook of Fire and Explosion Protection
Appendix A.5
Testing of Hose Reels and Monitors
General Requirements
All manually directed devices should be tested for coverage and range of the water sprays. Flow testing
should uncover shortcomings of water pressure or blockages and proper operation of the device. Wind
strength can either enhance or degrade the range of a water spray depending if it is directed upwind or
downwind. Residual pressures should be noted during full flow conditions.
Hose Reels
Hard rubber fire hoses are usually provided throughout the process area of a hydrocarbon facility. The coil
of a hose on a hose reel presents a considerable friction loss factor to the flow of water through it. In some
instances a fire water hose reel may not be completely unrolled from a reel before its use. Therefore it is
prudent to conduct a hose reel flow test with a partial removal of the hose and fhll unreeling from it. The
spray reaches of each scenario can then be l l l y evaluated and observed.
The ease of unrolling a hose reel to the protected hazard should be tested.
Monitors
The placement of monitors should be cognizant of obstructions. The arc and depth of the spray coverage
shouId be confirmed.
Where monitors are placed close to hazards, such as at helicopter landing sites, supplement monitor heat
should be considered for operator protection. The heat shield should not obstruct the visor of the operator
and clear heat resistant plexi-glasses have been used at some installations.
Dual coverage for high leak potential areas (e.g., pumps, compressors, etc.) should be verified during actual
flow testing.
Appendix A Testing Firewater Systems
Hydrants, and Monitors
Standpipes and
Hose Reels
Sprinkler Systems
Deluge and
Water Spray
Foam Water
Systems
C02 Fixed
Systems**
Drv Chemical**
Wet Chemical**
261
9.3.1
NFPA 14, Section 8-4.1
200 psi*
2 Hours
200 psi*
2 Hours
200 psi*
2 Hours
NFPA 13, Section 82.2.1
NFPA 15, Section 5-2
200 psi*
2 Hours
NFPA 16, 5-2.1
No Mention
No Mention
NFPA 12
See note 3
NIA
See note 4
N/A
NFPA 17, Section 25.4.2
NFPA 1 7 4 Section 24.4.2
* If operation pressure is greater than 150 psi, test pressure to be 50 psi above operational pressure.
** Limited to hoses and agent containers
Note 3 Piping not to be hydrostatically tested.
Note 4 Hydrotesting of piping is not required.
Hydrostatic Test Requirements
APPENDIX B
REFERENCE DATA
262
Appendix B: Reference Data
263
Appendix B.l
Fire Resistance Testing Standards
The following is a listing of specific US. industry standards for fire performance testing for specific fire
exposures that may be applied in the petroleum industry.
API Spec 6FA
API Spec 6FB
API Spec 6FC
API Bull 6F1
API Bull 6F2
API Std. 589
API Std. 607
Specification for Fire Test for Valves, 1994.
Fire Test For End Connections, 1992.
Specification for Fire Test for Valve with Automatic Backseats, 1994.
Bulletin on Performance of API and ANSI End Connections in a Fire Test According to
API Spec 6FA, 1994.
Bulletin on Fire Resistance Improvements for API Flanges, 1994.
Fire Test for Evaluation of Valve Stem Packing, 1993.
Fire Test for Soft Seated Quarter Turn Valves, 1993.
ASTM E-84
ASTM E- IO8
ASTM E-108
(Modified)
ASTM E- 119
ASTM E-136
Surface Burning Characteristicsof Burning Materials.
Fire Tests of Roof Coverings.
BS 476, Part 4
BS 476, Part 6
BS 476, Part 7
BS 476, Part 10
BS 476, Part 11
BS 476, Part 20
BS 476, Part 24
BS 476, Part 31
Non-combustibilityTest for Materials.
Method of Test for Fire Propagation for Products.
Surface Spread of Flame Test for Materials.
Guide to the Principles and Application o€Fire Testing.
Method of Assessing the Heat Emission from Building Materials.
Method for the Determination of the Fire Resistance of Elements of Construction
(Similar to ASTM E 1 19).
Methods for Determination of the Fire Resistance of Non-load bearing Elements of
Construction.
Methods for Determination of the Contribution of Components to the Fire Resistance of a
Structure.
Method for Determination of the Fire Resistance of Ventilation Ducts.
Methods for Measuring Smoke Penetration through Doorsets and Shutter Assemblies.
UK HSE
Department of Energy, Hydrocarbon Fire Test.
Fire Tests of Exterior Walls.
Fire Tests of Building Construction and Materials.
Standard Test Method for Behavior of Materials in a Vertical Tube Furnace at 750
degrees C, 1993.
ASTM E-152
Fire Tests of Door Assemblies, 1981.
Surface Flammability of Materials Using a Radiant Heat Energy Source, 1990.
ASTM E- 162
ASTM E- 163 Fire Test of Window Assemblies, Methods, 1984.
ASTM E-286
Surface Flammability of Building Materials Using a 8 Ft. Tunnel Furnace, 1984.
Critical Radiant Flux of Floor Covering Systems Using a Radiant Heat Energy Source
ASTM E-648
NST(NBS) Flooring Radiant Panel], 1993.
ASTM E-662
Specific Optical Density of Smoke Generated by Solid Materials N S T (NBS) Smoke
Chamber], 1993.
Standard Test Method for Fire Test of Through Penetration Fire Stops, 1994.
ASTM E-8 14
ASTM E- 1529 Standard Test Methods for Determining Effects of Large Hydrocarbon Pool Fires on
Structural Members and Assemblies, 1993.
BS 476, Part 22
BS 476, Part 23
264
Handbook of Fire and Explosion Protection
IEEE 817
IEEE 1202
Standard Test Procedure for Flame Coatings Applied to Insulated Cables in
Trays, 1993.
Standard for Flame Testing of Cables for Use in Industrial and Commercial Occupancies.
1991.
IMO
Fire Tests for Bulkheads and Decks.
I S 0 834
Fire Resistance Tests - Elements of Building Construction, 1975, (similar to ASTM E
119).
Fire Tests - Building Materials - Non-combustibility Test, 1990.
Fire Resistance Tests - Door and Shutter Assemblies, 1976 (1984), (similar to ASTM E
152).
Fire Resistance Tests - Glazed Elements, 1976 (1984), (similar to ASTM E 163).
Fire Tests - Reaction to Fire - Ignitability ofBuilding Products, 1986.
Fire Resistance Tests - Ventilation Ducts, 1985.
I S 0 1182
I S 0 3008
IS0 3009
I S 0 5657
I S 0 6944
NFPA 25 1
NFPA 268P
Standard Methods of Fire Tests of Building Construction and Materials, 1990 (Similar to
ASTM E-1 19).
Standard Methods of Fire Tests of Door Assemblies, 1990 (similar to ASTM E- 152).
Standard Method of Test for Critical Radiant Flux of Floor Coveriig Systems Using a
Radiant Heat Source Energy Source, 1990 (similar to ASTM E 648).
Standard Method of Test of Surface Burning Characteristics of Building Materials,
(similar to ASTM E-84).
Standard Methods 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 Generation of Solid Materials
(similar to ASTM E 662).
Standard Test Method for Potential Heat of Building Materials, 1993.
Standard Methods of Tests and Classification for Cigarette Ignition Resistance of
Components of Upholstered Furniture 1989.
Standard Methods of Tests for Determing Resistance of Mock-up Upholstered Furniture
Material Assemblies to Ignition by Smoldering Cigarettes, 1989.
Method of Test for Fire and Smoke Characteristics of Electrical Wire and Cables, 1990.
Standard Method of Test for Heat and Visible Smoke Release Rates for Materials and
Products, 1990.
Standard Method of Test for Heat and Visible Smoke Release Rates for Materials and
Products Using an Oxygen Consumption Calorimeter, 1992.
Standard Method of Test for Heat Release Rates for Upholstered Furniture Components
or Composites and Mattresses Using an Oxygen Consumption Calorimeter, 1990.
Ignitability of Exterior Wall Assemblies Using a Radiant Heat Energy Source, 1994.
SOLAS
Standard Fire Test, (Defined in SOLAS Regulation 3 Part 2), (Similar to ASTM E-1 19).
UBC 17-4
UBC 17-6
Fire Test Standard for Insulated Roof Deck Construction (FM Calorimeter).
Evaluation of Flammability Characteristics of Exterior, Nonload-Bearing Wall Panel
Assemblies Using Foam Plastic Insulation.
Test Method for Surfixe Burning Characteristics of Building Materials (similar to ASTM
E 84).
Standard Test Method for Evaluating Room Fire Growth Contribution of Textile
Wallcovering.
Fire Tests of Building Construction and Materials (similar to ASTM E-1 19).
Fire Tests of Door Assemblies (similar to UL 10B).
Fire Tests of Window Assemblies (similar to ASTM E-163).
Fire Tests of Through-Penetration Fire Stops (similar to ASTM E-814).
NFPA 252
NFPA 253
NFPA 255
NFPA 256
NFPA 257
NFPA 258
NFPA 259
NFPA 260
NFPA 261
NFPA 262
NFPA 263
NFPA 264
NFPA 264A
UBC 42-1
UBC 42-2
UBC 43-1
UBC 43-2
UBC 43-4
UBC 43-6
Appendix B: Reference Data
265
UBC 43-7
UBC 43-12
UBC 43-13
Fire Dampers and Ceiling Dampers.
Smoked Dampers (similar to UL 555s).
Horizontal Sliding Fire Doors Used in a Exit
UL9
Fire Tests of Window Assemblies, 1989. (similar to ASTM E 163).
Fire Tests of Door Assemblies, 1986 (similar to ASTM E 152).
Tests for Fire Resistance of Record Protection Equipment, 199I ,
Tests for Flammability of 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 Propagation of Fabrics and Film, 1976.
Fire Tests of Building Construction and Materials, 1992 (similar to ASTM E 1 19).
Fire Dampers, 1990.
Smoke Dampers.
Tests for Surface Burning Characteristicsof Building Materials, 1983. (similar to ASTM
E 84).
Tests for Fire Resistance of Roof Covering Materials, 1983. (similar to ASTM E 108)
Tests for Flame Propagation and Smoke Density Values for Electrical and Optical Fiber
Cables in Spaces Transporting Environmental Air, 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 Propagation Height of Electrical and Optical Fiber Cables Installed
Vertically in Shafts, 1991.
Vertical Tray Fire Propagation and Smoke Release Test for Electrical and Optical Fiber
Cables, 1992.
Rapid Rise Fire Tests of Protection Materials for Structural Steel, 1989.
Fire Test of Interior Finish Material, 1989.
Fire Test of Pneumatic Tubing for Flame and Smoke Characteristics, 1989.
Fire Test of Plastic Sprinkler Pipe for Flame and Smoke Characteristics, 1989.
Fire Tests of Mattresses, 1991.
Fire Tests for Foamed Plastics Used for Decorative Purposes, 1990.
Fire Test for Heat and Visible Smoke Release for Discrete Products and Their
Accessories Installed in Air-Handling Spaces, 1992.
UL 1OB
UL 72
UL 94
UL 155
UL 214
UL 263
UL 555
UL 55.54
UL 723
UL 790
UL 910
UL 1056
UL 1256
UL 1479
UL 1666
UL 1685
UL 1709
UL 1715
UL 1820
UL 1887
UL 1895
UL 1975
UL 2043
266
Handbook of Fire and Explosion Protection
Appendix B.2
Explosion and Fire Resistance Ratings
Fire Resistance Ratings
“A”, “B“, and ”C” fire barriers are normally specified for ships and were originally defined by the Safety of
Life at Sea (SOLAS) Regulations. Since then they have used extensively for offshore oi and gas installation
construction specifications. Recently, as more knowledge of hydrocarbons fires was gained, “H” fire rated
barriers have been specified and 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 pressure
hydrocarbon jet fires.
A Barriers
A0
A 15
A 30
A 60
Cellulosic Fire, 60 minute barrier against flame and heat passage, no temperature insulation.
Cellulosic Fire, 60 minute barrier against flame and heat passage, 15 min. temperature insulation.
Cellulosic Fire, 60 minute barrier against flame and heat passage, 30 min. temperature insulation.
Cellulosic Fire, 60 minute barrier against flame and heat passage, 60 min. temperature insulation.
Class A divisions are those divisions that 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 constructed to prevent the passage of smoke and flame for a one hour standard fire
test.
(4) They are insulated with approved noncombustible materials such that the average temperature
ofthe unexposed side will not rise more than 180 OC above the original temperature, within the
time listed (Le. A-60: 60 minutes, A-30: 30 minutes, A-15: 15 minutes, A-0: 0 minutes).
B Barriers
B 0 Cellulosic Fire, 30 minute barrier against flame and heat passage, no temperature insulation.
B 15 Cellulosic Fire, 30 minute barrier against flame and heat passage, 15 min. temperature insulation.
Class B barriers are those divisions formed by ceilings, bulkheads or decks that comply with the following:
(1) They are constructed to prevent the passage of flame for 30 minutes for a standard fire test
(2) They have an insulation layer such that the average temperature on the unexposed side will not
rise more than 139 OC above the original temperature, nor will the temperature at any one point,
including any joint rise more than 225 O C above the original temperature @e., a Class B-15: 15
minutes, Class B-0: 0 minutes).
(3) They are of noncombustible construction.
Appendix B: Reference Data
267
C Barriers
C
Noncombustible Construction.
Class C barriers are made of noncombustible materials and are not rated to provide any smoke, flame or
temperature passage restrictions.
H Barriers
H0
H 60
H 120
H 180
H 240
Hydrocarbon Fire, 120 minute barrier against flame and heat passage, no temperature insulation.
Hydrocarbon Fire, 120 minute barrier against flame and heat passage, 60 min. temp. insulation.
Hydrocarbon Fire, 120 minute barrier against flame and heat passage, 120 min. temp. insulation.
Hydrocarbon Fire, 120 minute barrier against flame and heat passage, 180 min. temp. insulation.
Hydrocarbon Fire, 120 minute barrier against flame and heat passage, 240 min. temp. insulation.
J Ratings
Jet Fire or "J" ratings are specified by some vendors for resistance to hydrocarbon jet fires. Currently no
specific standard or test specification has been adopted by the industry as a whole or a governmental
regulatory body. Some recognized testing agencies (e.g., SINTEF, Shell Research, British Gas, etc.) have
proposed J fire test standards which are currently being used by some of the major operators in lieu of a
recognized standard.
Heat Flux
Heat rate input: is normally taken as 205 kW/m2 (65,000 Btu/ft2) - hr @ 5 minutes for hydrocarbon fires
Fire Doors
0.3 Hours (20 minutes), Cellulosic Fire
0.5 Hours (30 minutes), Cellulosic Fire
0.75 Hours (45 minutes), Cellulosic Fire
1 .O Hour, Cellulosic Fire
1.5Hours, Cellulosic Fire
3.0 Hours, Cellulosic Fire
4.0 Hours, Cellulosic Fire
The doors are also rated at three temperature levels that indicate the maximum temperature transmitted to
the unexposed side after 30 minutes,: up to 121 OC (250 OF), up to 250 OC (450 OF), and up to 361 OC (650
OF).
Fire Windows
0.3 Hours (20 minutes), Cellulosic Fire
0.5 Hours (30 minutes), Cellulosic Fire
0.75 Hours (45 minutes), Cellulosic Fire
1 .OHour, Cellulosic Fire
1.5Hours, Cellulosic Fire
3.0 Hours, Cellulosic Fire
268
Handbook of Fire and Explosion Protection
Fire Dampers
0.3 Hours (20 minutes), Cellulosic Fire
0.75 hours (45 minutes), Cellulosic Fire
1 hour, Cellulosic Fire
1.5 hours, Cellulosic Fire
Smoke Dampers
Smoke dampers are specified on the leakage class, maximum pressure, maximum velocity, installation mode
(horizontal or vertical) and degradation test temperature of the fire (Ref UL Std. 555 S).
Blast Ratings
Explosion blast ratings are taken as the maximum peak overpressure that may be expected to occur.
Commonly industry rating requested are listed below. No standardized test criteria has been adopted by the
industry or regulating bodies, rather the operator is required analyse the exposures and demostrate adequate
protection is afforded where required.
0.1
0.25
0.5
1.0
Bar (1.5 psi) Overpressure
Bar (3.6 psi) Overpressure
Bar (7.3 psi) Overpressure
Bar (14.5 psi) Overpressure
Electrical Svstem Temperature ODerating Limits
Electrical components are guaranteed for performance at a maximum ambient temperature. Most electrical
or electronic equipment is rated for a maximum operating temperature of 40 OC (1 04 OF) unless otherwise
specified, e.g., hazardous area lighting fixtures are normally specified for maximum ambient operating
temperature of 40 OC (104 OF). At temperatures above these levels the performance of the electrical
components cannot be assured.
Appendix B: Reference Data
269
Appendix B.3
National Electrical Manufacturers Association (NEMA)
NEMA Classifications
Type 1 - General Purpose
A general purpose enclosure that is intended to primarily prevent accidental contact with the enclosed
apparatus. It is suitable for general purpose applications indoors where it is not exposed to unusual service
conditions and 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 Tight
A semi-dust tight enclosure that is similar to Type 1 enclosure, with the addition of a gasket around the
cover.
-
Type 1B Flush Type
A flush type enclosure that is similar to Type 1 enclosure, but is designed for mounting in a wall and is
provided with a cover that also serves as a flush plate.
Type 2 - Drip Proof Indoors
A drip tight enclosure that is intended to prevent accidental contact with the enclosed apparatus and in
addition,is srrcomtractecf as t r r ~ x c l a d e f ~ f i n g r n ~tbutisnutdrmt
~ ~ ~ ~ o t - ~ tigtii.
Type 2 enclosures are suitable for applications where condensation may be severe, such as encountered in
cooling rooms and laundries
-
Type 3 Dust Tight, Rain Tight and Sleet (Ice) Resistant Outdoor
A weather resistant enclosure intended to provide suitable protection against specified weather hazards. It is
suitable for use outdoors. It is designed to provide a degree of protection against rain, sleet, windblown
dust, and damage from external ice formation.
A Type 3 enclosure is suitable for applications outdoors i? ice is not a serious problem
Type 3R - Rain Proof, Sleet (Ice) Resistant Outdoor
An outdoor enclosure designed against rain, sleet, and damage from external ice formation. They are not
dust tight, snow or sleet (ice) proof.
-
Type 3s Dust Tight, Rain Tight, and Sleet (Ice) Proof - Outdoor
An outdoor enclosure designed to protect against dust and water and to operate covered with ice or sleet.
270
Handbook of Fire and Explosion Protection
Type 4 - Water Tight and Dust Tight
An enclosure so designed to provide a degree of protection against windblown dust and rain, splashing
water, water directed under pressure, and damage from external ice formations.
A Type 4 enclosure is suitable for application outdoors on loading docks, and in water pump houses but not
in hazardous locations.
Type 4X - Water Tight, Dust Tight, and Corrosion Resistant
A Type 4 outdoor enclosure that is also protected to provide corrosion resistance
Type 5 -- Dust Tight, Watertight
An indoor enclosure with a degree of protection against settling dust, dirt, and noncorrosive liquids
Type 6 - Submersible
Type 6 enclosures are intended for indoor or outdoor use primarily to provide a degree of protection against
the entry of water during occasional temporary submersion at a limited depth. They are not intended to
provide protection against conditions such as internal condensation, internal icing, or corrosive
environments.
A Type 6 enclosure is suitable for application where the equipment may be subject to temporary
submersion. The design of the enclosure will depend upon the specific conditions of pressure and time. It is
also dust tight and sleet (ice) resistant.
Type 6P - Prolonged Submersible
An enclosure for indoor or outdoor use to provide a degree of protection against direct pressurized water
application, entry of water during prolonged submersion, and damage from external ice formation.
Type 7 (A, B, C, or D) Hazardous Locations - Class I Air Break
These enclosures are designed to meet the applicable requirements of the National Electrical Code (NFPA
70) for Class I Groups A, B, C, or D hazardous locations that may be in effect. In this type of equipment,
the circuit interruption occurs in air.
Specifically note that Type 7 (explosion-proof) enclosures and their associated conduit systems are neither
gas or liquid tight. Consequently, corrosive gases such as hydrogen sulfide and water from rain or internal
condensation can accumulate with the enclosure. Premature failure of electrical devices and
interconnections often results when preventive measures such as drains, air purges, and dual rated enclosures
are not used to remove or exclude these corrosive elements. Type 7 enclosures are intended for indoor use.
Type 8 (A, B, C, & D) Hazardous Locations - Class I Oil Immersed
These enclosures are designed to meet the application requirements of the National Electrical Code (NFPA
70), for Class I Groups A, B, C, or D hazardous locations either indoors or outdoors. The apparatus may be
immersed in oil
Type 9 (E, F, or G) Hazardous Locations - Class I1
These enclosures are designed to the applications requirements of the National Electrical Code (NFPA 70),
Appendix B: Reference Data
271
for Class 11, Groups E, F, or G hazardous locations
The letters or letter following the type number indicates the particular groups or groups of hazardous
locations (as defined by the National Electrical Code) for which the enclosure is designed. The designation
is incomplete without a suffix letter or letters.
-
Type 10 Mine Safety and Health Administration (MSHA) - Explosion Proof
A Type 10 enclosure is designed to meet the explosion proof requirements of the U.S. Mine Safety and
Health Administration (MSHA). It is suitable for use in gaseous coal mines.
Type 11 - Acid and Fume Resistant - Oil Immersed
A Type 11 enclosure is suitable for application indoors where the equipment may be subject to corrosive
acid or fumes, as in chemical plants, plating rooms, sewage plants, etc. The apparatus may be immersed in
oil.
-
Type 12 Industrial Use
A Type 12 enclosure is designed for use in those industries where it is desired to exclude such materials as
dust, lint fibers, and flyings, oil seepage, or coolant seepage.
-
Type 13 Oil Tight and Dust Tight Indoor
An 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 or
coolant
272
Handbook of Fire and Explosion Protection
NEMA Type 7 (Indoor) and Type 8 (Indoor and Outdoor)
Applications for Hydrocarbon Environments
Source
National Electrical Manufacturers Association, Publication No. 250
Appendix B: Reference Data
Appendix B.4
Hydraulic Data
Coeflicient of Discharge Factors
Outlet
Discharge Coefficient
Nozzles, Underwriters Playpipes or similar
Nozzles, Deluge Sets or Monitor
Nozzles,Ring
0.99
Open Pipe, Smooth Opening
Open Pipe, Burred Opening
0.80
0.70
Sprinkler Head (nominal 1/2 inch orifice)
0.75
Standard Orifice (sharp edge)
0.62
Hydrant butt, smooth on well rounded outlet, flowing full
Hydrant butt, square and sharp at hydrant barrel
Hydrant but, outlet square, projecting into barrel
0.90
0.80
0.70
0.97
0.75
273
274
Handbook of Fire and Explosion Protection
Appendix B.5
Selected Conversion Factors
Metric Prefixes, Symbols and Multiplying Factors
Prefix
Symbol
Multiplying Factor
exa
Peb
tera
€k3a
mega
kilo
hecto
deca
E
P
T
1018
1015
1012
109
106
I 03
102
deci
centi
milli
micro
nano
pic0
femto
atto
G
M
k
h
da
a
C
m
I.L
I1
P
f
a
101
100
10-1
10-2
10-3
10-6
10-9
10-12
10-15
10-18
Word
1,000,000,000,000,000,000
1,000,000,000,000,000
1,000,000,000,000
1,000,000,000
1,000,000
1,000
100
10
1
0.1
0.01
0.001
0.000,00I
0.000,000,00I
0.000,000,000,001
0.000,000,000,000,001
0.000,000,000,000,000,001
= one trillion
= one billion
= one million
= one thousand
= one hundred
=ten
= one
= one tenth
= one hundredth
= one thousandth
= one millionth
= one billionth
= one trillionth
The prefixes should be attached directly to the SI base unit: e.g., kilogram, millisecond, gigameter, etc. Similarly, the abbreviations
attach directly to the abbreviation for the SI units: e+, an,Mg, mK, etc. Do not use two or more of the SI units. Although kilogram
is the normal base unit for mass, the prefixes are added to gram (g), not kilogram (kg).
Temperature Conversion
9= P C x 1.8) + 32
O C = ("F - 32)/1.8
% = 9f 459.67
%=OC+273.15
Freezing Point of Water: Celsius = 0 deg., Fahr. = 32 degrees
Boiling Point of Water: Celsius = 100 deg., Fahr. = 212 degrees
Appendix B: Reference Data
Selected Conversion Factors
Multiply
by
to Obtain
Acres
Acres
Acre feet
Acre feet
Acre feet
Atmospheres
Atmospheres
Atmospheres
Atmospheres
Atmospheres
Atmospheres
Barrels, Oil
Barrels, Oil
Barrels, Oil
Barrels, Oil
Bars
Bars
Bars
Bars
Bars
BtU
Btu
Btu
Btu/A2
Btulttt"?/hr
BtLl/fiZ/hr/F
Btdft2/hr/F/in.
Btuflb
Btuflb (OF)
Btdcubic foot
Btdgallon
Btu/hour
Btu/minute
Btdminute
Btdminute
Centimeters
Centimeters of Mercury
Centimeters of Mercury
Centimeters of Mercury
Centimeters of Mercury
Cubic Centimeters
Cubic foot
Cubic foot
Cubic foot
Cubic foot
Cubic foot
Cubic footflb
Cubic foot/minute
Cubic foot/minute
Cubic foot/minute
Cubic foot/second
Cubic inch
Cubic inch
Cubic mete1
Cubic meter
Cubic meter
Cubic yard
Cubic yard
Cubic yard
43,560
4,047
43,560
1,233
325,850
29.92
76.0
33.90
14.69595
101.325
1.01325
5.614583
0.1589873
42
158.9873
100
106
10,197
14.5
0.9869233
777.98
1,054.8
07.565
11.360
3.152
5.674
0. I44
2.326
4.1868
37.25895
278.7136
0.293 1
0.01757
12.96
0.02356
0.3937
0.01316
0.4461
27.85
0.1934
0.06 102
0.0283 16847
28.31625
7.48052
1728
O:mKr2
0.06242796
472.0
0.4720
0.1247
448.3
16.39
0.01639
264,1721
35.3I467
6.28981 1
0.76456
27
202.0
Square feet
Square meters
Cubic feet
Cubic meters
Gallons (U.S.)
Inches of mercury
Cms of mercury
Feet of water
Pounddsquare inch
Kilopascals
Bar
Cubic feet
Cubic meters
Gallons (U.S.)
Liters
kiloPascals
Qmedsquare centimeter
Kilograms/squaremeter
Poundslsquare inch
Atmospheres
Foot-pounds
Joules (abs)
Kilogram-meter
Joulelm'
Watt/m2 (IC-factor)
watt/& K
Watt/m K
Kilojouleflulogram
EcllojoulefluIogram('C)
Kilojoulelcubic meter
Kilojoulelcubic meter
Watts
Kilowatts
Foot-punds/second
Horse-power
Inches
Atmospheres
Feet of water
Poundslsquare feet
Poundslsquare inch
Cubic inches
Cubic meters
Liters
Gallons
Cubic inches
Cubic meter
Cubic meterskilogram
Cubic centimeterslsecond
Literdsecond
Gallonslsecond
Gallons/niinute
Cubic centimeters
Liters
Gallons
Cubic feet
Barrels, Oil
Cubic meters
Cubic feet
Gallons
275
276
Handbook of Fire and Explosion Protection
Feet
Feet
Feet
Feet of water
Feet of water
Feet of water
Feet of water
Foot-pounds
Footlsecond
Gallons
Gallons
Gallons
Gallons
Gallons of water
Gallons per minute
Gallons per minute
Gallons per minute
Horsepower
Inch
Inch
Inch
Inches of mercury
Inches of mercury
Inches of mercury
Inches of mercury
Inches of water
I n c h of water
Inches of water
Inches of water
Inches of water
Joules
Jolues
JoulePC
%localorie
Kilograms
Kilogradsquare centimeter
Kilograms/mmZ
Kilometers
Kilowatts
Kilowatt
Kilowatt
Kilowatt-hours
Kilowatt-hours
Kilowatt-hours
Kilograms/squarecm
Liters
Liters
Liters
Literslsecond
Litershecond
Literdsecond
Lux
Lux
Meters
Meters
Meters
Meter
Meterhinute
Miles
Miles
Mileshour
Mileshour
Mileshour
Millibar
Millimeters
Millimeters of mercury
MMCFD
30.48
0.3048
304.8
0.03048
2989.07
0.0294998
0.0298907
1.356
30.48
3.78533
0.13368
23 1
3,785.434
8.3453
0.002228
8.0208
0.0630902
745.7
25.4
2.540
0,0254
3.389
0.03342
1.133
0.4912
0.002458
0.07355
5.202
0.03613
248.8
0.000947817
0.238846
0.000526565
4.184
2.20462
14.22
9.807
0.62 14
1.341
3,412.14
1,000
3,412.14
2.655 x IO6
3.6 x lo6
97.0665
0.2642
61.02
0.0353 1
15.85032
95 1.0194
2.11888
1.0
0.0929
3.281
39.37
1.094
5,280
0.05468
1.609344
5,280
88
1.467
1.609344
100
0.03937
0.1333
28,300
Centimeters
Meters
Millimeters
Kilograms/squarecentimetc
Pascal
Atmospheres
Bars
Joules
Centimeterdsecond
Liters
Cubic feet
Cubic inches
Cubic centimeters
Lbs. of water
Cubic feetlsecond
Cubic feetmour
Liters/second
Watts
Ivhlimeters
Centimeters
Meter
kilopascals
Atmospheres
Feet of water
Pounds/square feet
Atmospheres
Inches of mercury
Pounds/square feet
Poundshquare inch
Pascals
Btu
Calorie
BtUPF
kiloJoules
Pounds
Pounddsquare inch
MPa
Miles
Horsepower
Btu/hour
Joule/second
BtU
Foot-po~ds
Joules
Kilopascals &Pa)
Gallons (U.S.)
Cubic inches
Cubic feet
Gallons per minute (gpm)
Gallons per hour
Cubic fi./minute
Lumenskquare meter
Foot-candles
Feet
Inches
Yards
Feet
Feetlsecond
alometers
Feet
FeethinUte
Feethecond
kilometershour
Pascals
Inches
MoPascals
cubic meterdday
Appendix B: Reference Data
Ounces (fluid)
Pascal
Pound
Pounddsquare inch
Pounds/square inch
Poundslsquare inch
Pounds/square inch
Pounddsquare inch
Pounds/square inch
Pounds/square foot
Pounddcubic foot
Quarts
Slugs
Square Centimeters
Square Centimeters
Square foot
Square Inches
Square meters
Square meters
Square meters
Square Yards
Square Yards
Watts
Watts
Watts
Yards
Yards
0.2957
0.000I45038
0.4535924
2.307
0.06804
2.036
6.894757
6,895
0.0689
47.88
16.01846
0.9463
32.174
0.00 107639
0.15499969
0.929
645.2
1,550
10.76387
1.196
0.8361
1296
3.41304
0.7378
1.341 x IOe3
3.0
0.9144
Miscellaneous Constants
1 gallon of fresh water = 8.33 lbs. = xx kgs.
1 cubic A. of fresh water = 62.4 lbs. = xx kgs.
Absolute Zero: -273.16 deg. Celsius; -459.69 degrees Fahr.
Liters
Pounds/square inch
Kilogram (kgs)
Feet of water
Atmospheres
Inches of mercury
Kilopascals (Wa)
Pascals
Bars
Pascals
Kilograms/cubicmeter
Liters
Pounds
Square feet
Square inches
Square meters
Square millimeters
Square inches
Square feet
Square yards
Square meters
Square inches
Btu/hour
Foot-pounds/second
Horsepower
Feet
Meters
277
ACRONYM
ABS
AC
AFFF
AFNOR
AlA
AIChE
AlT
ALARP
ANSI
AODC
AOV
API
ASA
ASCE
ASHRAE
ASME
ASSE
ASTM
AWWA
BACT
BASEEFA
BLEVE
BMS
BPCS
BPD
BOM
BOP
BOSS
BS
BSI
BS&W
BTU
°C
CAD
CCPS
CENELEC
CFM
CFR
CFT
CIMAH
CMI
CONCAWE
CO2
CPI
CSA
CVD
dB
LIST
American Bureau of Shipping
Alternating Current
Aqueous Film Forming Foam
French Standards (Association Francais de Normalization)
American Insurance Association
American Institute of Chemical Engineers
Autoignition Temperature
As Low As Reasonably Practicable
American National Standards Institute
Association of Offshore Diving Contractors
Air Operated Valve
American Petroleum Institute
Acoustical Society of America
American Society of Civil Engineers
American Society ofHeating, Refrigerating and Air-Conditioning
Engineers
American Society ofMechanical Engineers
American Society of Safety Engineers
American Society for Testing and Materials
American Water Works Association
Best Available Control Technology
British Approval Science for Electrical Equipment in Flammable
Atmospheres
Boiling Liquid Expanding Vapor Explosion
Burner Management System
Basic Process Control System
Barrels per Day
Bureau ofMines (U.S.)
Blowout Preventer
Blowout Spool System
British Standard
British Standards Institute
Basic Sediment and Water
British Thermal Unit
Degrees Centigrade
Computer Aided Design
Center for Chemical Process Safety
European Committee for Electrotechnical Standardization
Cubic Feet per Minute
Code of Federal Regulations
Cool-Flame Reaction Threshold
Control of Industrial Major Accident Hazards
Christian Michelsen Institute (Norway)
Conservation ofClean Air/Water Europe
Carbon Dioxide
Chemical Processing Industry
Canadian Standards Association
Combustible Vapor Dispersion
Decibel
278
Acronym List
DC
DCS
DHSV
DIN
DNV
OF
EIV
EOLR
EOR
ESP
ESD
ESV
ET
FA
FACP
FAR
FC
FCC
FCV
FD
FHZ
FM
FMEA
FO
FP
FS
FSA
FT
FW
FWKO
GOR
GQSP
GOST
GOV
GPA
gpm
HAZOP
WC
HCN
H2S
HFES
HIPS
HMSO
HOV
hP
HPI
HPR
HRA
HSE
HSI
HVAC
Hz
IADC
IEC
Direct Current
Distributed Control System
Down hole safety valve
German Standards
Det Norske Veritas
Degrees Fahrenheit
Emergency Isolation Valve
End of Line Resistor
Enhanced Oil Recovery
Electrical Submersible Pump
Emergency Shutdown
Emergency Shutdown Valve
Event Tree
Fire Alarm
Fire Alarm Control Panel
Fatality Accident Rate
Fail Closed
Fluid Catalytic Cracker
Flow Control Valve
Fire Department
Fire Hazard Zone
Factory Mutual
Failure Mode and Effects Analysis
Fail Open
Flash Point
Fail Steady (i.e. last operating position)
Formal Safety Assessment
Fault Tree
Firewater
Free Water Knock Out
Gas Oil Ratio
Gas Oil Separation Plant
Russian (U.S.S.R.) Standards
Gas Operated Valve
Gas Processors Association
Gallons Per Minute
Hazard and Operability (Review or Study)
Hydrocarbon
Hydrogen Cyanide (Hydrocyanic Acid)
Hydrogen Sulfide
Human Factors and Ergonomics Society
High Integrity Protective System
Her Majesty’s Stationary Office
Hydraulic Operated Valve
Horsepower
Hydrocarbon Processing Industry
Highly Protected Risk
Human Reliability Analysis (or Human Error Analysis)
Health and Safety Executive (U. K.)
Hydraulics Standards Institute
Heating, Ventilation and Air Conditioning
Hertz
International Association of Drilling Contractors
International Electrotechnical Commission
279
280
Handbook of Fire and Explosion Protection
IEEE
ILP
IMO
Lp
LR
IRI
IS
ISA
IS0
.TIS
LIS
LAH
LAL
LFL
LED
LEL
LNG
LPG
LSH
LSL
MAC
Mg
MMCF
MMS
MOV
MPS
MSDS
MSHA
MTBF
Mw
NACE
NEC
NEMA
NDT
NFAC
NFPA
NGL
MOSH
NPD
OIA
OIL
OIM
OREDA
OSHA
OTC
ows
PAH
PAL
PC
PCV
PDQ
P.E.
PFD
PHA
Institute of Electronic and Electrical Engineers
Independent Layers of Protection
International Maritime Organization
Institute of Petroleum (U.K.)
Infrared
Industrial Risk Insurers (U.S.)
Intrinsically Safe
Instrument Society of America
International Organization for Standardization
Japanese Industrial Standards
Liters per Second
Level Alarm High
Level Alarm Low
Lower Flammable Limit
Light Emitting Diode
Lower Explosive Limit (synonymous with LFL)
Liquefied Natural Gas (Methane)
Liquefied Petroleum Gas (Butane or Propane)
Level Safety High (high level sensor)
Level Safety Low (low level sensor)
Manual Activation Callpoint
Mass flow rate of gas
One Million Cubic Feet
Minerals Management Service (U.S.)
Motor Operated Valve
Manual Pull Station
Material Safety Data Sheet
Mine Safety and Health Administration (U.S.)
Mean Time Between Failures
Mass flow rate ofwater
National Association of Corrosion Engineers
National Electrical Code
National Electrical Manufacturers Association
Non Destructive Testing
National Fire Alarm Code
National Fire Protection Association
Natural Gas Liquids
National Institute €or Occupational Safety and Health (U.S.)
Norwegian Petroleum Directorate
Oil Insurance Association
Oil Insurance Limited (Bermuda)
Offshore Installation Manager
Offshore Reliability Data
Occupational Safety and Health Administration (U.S.)
Offshore Technology Conference
Oily Water Sewer
Pressure Alarm High
Pressure Alarm Low
Personal Computer
Pressure Control Valve
Production, Drilling, Quarters
Professional Engineer
Process Flow Diagram
Process Hazard Analysis
Acronym List
PI
PIB
P&ID
PLC
PLL
PML
POB
PPm
PSH
psi
psia
Psig
psi0
PSV
Ptb
QA
QC
QRA
ROR
RP
RPM
RRF
RTT
RV
RVP
SASO
SCADA
SFPE
SI
SIH
SIL
SINTEF
SIS
SMACNA
SNiP
SOLAS
SPE
SSIV
TAH
TAL
TMR
TNT
TSH
TSR
UBC
UFL
UEL
U K.
UL
ULCC
UMC
UPS
u.s
Pressure Indicator
Process Interface Building
Piping and Instrumentation Drawing
Programmable Logic Controller
Potential Loss of Life
Probable Maximum Loss
Personnel On Board
Parts Per Million
Pressure Switch High
Pounds per Square Inch
Pounds per Square Inch Absolute
Pounds per Square Inch Gage
Pounds per Square Inch Overpressure
Pressure Safety Valve
Pounds of salt (Na C1) equivalent per thousand barrels of crude oil
Quality Assurance
Quality Control
Quantitative Risk Assessment
Rate of Rise
Recommended Practice
Revolutions per Minute
Risk Reduction Factor
Preflame-Reaction Threshold
Relief Valve
Reid Vapor Pressure
Saudi Arabian Standards Organization
Supervisory Control and Data Acquisition
Society of Fire Protection Engineers
Systeme International &Unites
Satellite InstrumentationHouse
Safety Integrity Level
Norges Branntekniske Laboratorium (Norwegian Fire Research
Laboratory)
Swedish Standards Association
Sheet Metal and Air Conditioning Contractors National Association
Russian (U.S.S.R.) Regulations
Safety of Life at Sea
Society of Petroleum Engineers
Subsea Isolation Valve
Temperature Alarm High
Temperature Alarm Low
TripIe Modular Redundant
Trinitroluene
Temperature Safety High (high temperature sensor)
Temporary Safe Refbge
Uniform Building Code
Upper Flammable Limit
Upper Explosive Limit (synonymous with UFL)
United Kingdom
Underwriters Laboratories (U.S.)
Ultra Large Crude Carrier
Uniform Materials Code
Uniterruptable Power Supply
United States
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Handbook of Fire and Explosion Protection
USCG
uv
UVCE
VDC
VESDA
VLCC
voc
WCCE
1002
2002
2003
United States Coast Guard
Ultraviolet
Unconfined Vapor Cloud Explosion
Volts Direct Current
Very Early Smoke Detection and Alarm
Very Large Crude Carrier
Volatile Organic Compounds
Worst Case Creditable Event
One Out Of Two
Two Out Of Two
Two Out Of Three
Glossary
Accident - An event or sequence of events that results in undesirable consequences
API Gravity - The gravity (weight per unit volume) of crude oil expressed in degrees according to
American Petroleum Institute recommended system. API gravity divides the number 141.5 by the actual
specific gravity of the oil at 15.5 O C (60 OF) and subtracts 131.5 from the he resulting number. The higher
the API gravity the lighter the crude oil. Higher gravity crudes are generally considered more valuable.
-
Autoignition Temperature (AIT) The lowest temperature at which a flammable gas or vapor-air mixture
will 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 on
demand.
Barrel (BBL) - A barrel has been traditionally the standard liquid quantity of measurement in the petroleum
industry. One barrel of oil equals 159 liters (42 U.S. gallons).
-
Basic Process Control System (BPCS) Pneumatic, electronic, hydraulic or programmable instruments
and mechanisms that monitor and/or operate a facility or system to achieve a desired function, Le., flow
control, temperature measurement, etc., which are supervised by human observation.
Best Available Control Technology (BACT)
operating methodology applied to a process.
- The most currently commercial optimum hardware and
Blast - A transient change in gas density, pressure (both positive and negative), and velocity of the air
surrounding an explosion point.
Boiling Liquid Expanding Vapor Explosion (BLEVE) - The nearly instantaneous vaporization and
corresponding release of energy of a liquid upon its sudden release from a containment under greater than
atmospheric pressure and at a temperature above it's atmospheric boiling point.
Blowdown - The disposal of voluntary discharges of liquids or condensable vapors from process and vessel
drain 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 the
formation, caused by the formation pressure exceeding the drilling fluid pressure. It usually occurs during
drilling on unknown reservoirs.
Blowout Preventer (BOP) - An assembly of heavy duty valves attached to the top of a well casing to
control pressure and flow.
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Handbook of Fire and Explosion Protection
Boilover - A boiling liquid eruption in a hydrocarbon storage tank; usually described as an event in the
burning of certain oils in an open top tank when, after a long period of quiescent burning, there is a sudden
increase in fire intensity associated with the expulsion of burning oil from the tank, due to water at the
bottom of the tank being heated to vaporization and causing a boiling eruption.
Christmas Tree - An assembly of valves, gauges, and chokes mounted on a well casinghead to control the
flow and pressure of oil or gas to a pipeline.
Classified Area - Any area that is electrically classified following the guidelines of a nationally recognized
electrical code such as the requirements of the NEC, Article 500 or API RP 500.
-
Combustion A rapid chemical process that involves reaction of an oxidizer (usually oxygen.in air) with an
oxidizable material, sufficient to 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 liquids
based 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 under
specified conditions. When the ambient temperature of a combustible liquid is raised above its flash point, it
essentiallybecomes a flammable liquid.
Condensate - Liquid hydrocarbons that have been separated from natural gas, usually by cooling the
process stream which "condense" the "entrained" liquid. Typically the fractions of C3, C4 and C5 or
heavier.
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 is
low in sulfur, and therefore more valuable. Generally considered crude oils are hydrocarbon mixtures that
have 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 fire
suppression purposes.
Depressurization - The release of unwanted gas pressure from a vessel or piping system to an effective
disposal system.
Detonation - A propagating chemical reaction of a substance in which the reaction front advances into the
unreacted substance at greater than sonic velocity in the unreacted substance.
Distillate - A generic term for several petroleum fuels that are heavier than gasoline and lighter than residual
fUels; for example, home heating oil, diesel oil, and jet fuels.
Distributed Control System (DCS) - A generic, microprocessor based, regulatory system for managing a
system, 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 fluids
that may enter the wellbore under pressure, before the BOP stack has be set in place. It is used when drilling
through shallow underground gas zones for diverting gas kicks in deep high pressure zones.
Emergency - A condition of danger that requires immediate remedial action
Emergency Shutdown (ESD) - A method to rapidly cease the operation of the process and isolate it from
Glossary
285
incoming and going connections or flows to reduce the likelihood of an unwanted event fiom continuing or
occumng.
Ergonomics - The study of the design requirements of work in relation to the physical and psychological
capabilities and limitations of human beings.
Executive Action - Control process performed to initiate critical instructions or signals to 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 an
explosion of flammable gas inside the enclosure will not ignite flammable gas outside the enclosure. Nothing
is really considered technically explosionproof.
Fail Safe - A system design or condition such that the failure of a component, subsystem or system or input
to it, will automatically revert to a predetermined safe static condition or a state of least critical
consequence.
-
Fail to Danger A system design or condition such that the failure of a component, subsystem or system or
input to it, will automatically revert to an unsafe condition or state of highest critical consequence for the
component, subsystem, or system.
Failure Mode - The action of a device or system to revert to a specified state upon failure of the utility
power source that normally activates or controls the device or system. Failure modes are normally specified
as fail open (FO), fail closed (FC) or fail steady (FS) which will result in a fail safe or fail to danger
arrangement.
Fire - A combustible vapor or gas combining with an oxidizer in a combustion process manifested by the
evolution of light, heat and flame.
Fireproof - Resistant to a specific fire exposure; essentially nothing is absolutely "fireproof" but some
materials or building assemblies are resistant to damage or fire penetration at certain level of fire exposures
that may develop in the petroleum industry.
Fireproofing - A common industry term used to denote materials or methods of construction used to
provide fire resistance for a defined fire exposure and specified time. Essentially nothing is fireproof if it is
exposed to high temperatures for extended time periods.
Fire Retardant - In general a term that denotes a substantially lower degree of fire resistance than "fire
resistive. It is frequently used to refer to materials or structures that are combustible but have been
subjected to treatment or surface coatings to 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 to
which 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 +c
incorrectly 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 not
exceeding 2068 mm Hg (40 psia) at 37.8 O C (100 OF) as determined under specified conditions.
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Handbook of Fire and Explosion Protection
Flash Point (FP) - The minimum temperature of a liquid at which it gives off sufficient vapors to form an
ignitable mixture with air immediately above the surface of the liquid or within the vessel used on the
application of an ignition source under specified conditions.
Foam - A fluid aggregate of air filled bubbles, formed by chemical means that will float on the surface of
flammable liquids or flow over solid surfaces. The foam fimctions to blanket and extinguish fires and/or
prevent the ignition of the material.
Foam Concentrate
combustible liquid.
- Fire suppression surfactant material used to
seal the vapors from the surface of a
Foam Solution - Fire suppression foam concentrates mixed in proper proportion to water as required by
specification of the foam concentrate (currently foam concentrates are available for 1%, 3%, and 6% by
water solution mix).
Foolproof - So plain, simple, or reliable as to leave no opportunity for error, misuse or failure.
Fusible Link - A release device activated by the heat effects of a tire. It usually consists of two pieces of
metal joined by a low melting point solder. Fusible links are manufactured at various temperature ratings
and 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 acronym
for halogenated hydrocarbons, commonly bromotrifluoromethane (Halon 1301) and bromochlorodifluoromethane (Halon 1211). Considered obsolete for fire protection purposes due to a possible environmental
impact to the Earth's 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 heat
transmitted by radiation, conduction, and convection.
Human Factors - A discipline concerned with designing machines, operations, and work environments to
match human capabilities and limitations.
Hydrocarbons - An organic compound containing only hydrogen and carbon. The simplest hydrocarbons
are gases at ordinary temperatures; but with increasing molecular weight, they change to the liquid form and
finally, 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 when
the temperature of a substance is raised to the point at which its molecules will react spontaneously with an
oxidizer and combustion occurs.
Independent Protection Layer (IPL) - Protection measures that reduce the level of risk of a serious event
by 100 times, which have a high degree of avaiIabiIity (greater than 0.99) or have specificity, independence,
dependability and auditability.
Inerting - The process of removing an oxidizer (usually air or oxygen) to prevent a combustion process
from occurring normally accomplished by purging.
Inflammable - Identical meaning as flammable, however the prefix "in" indicates a negative in many words
and can cause cohsion, therefore the use of flammable is preferred over inflammable.
-
Inherently Safe An essential character of a process, system or equipment that makes it without or very
low in hazard or risk.
Glossary
287
-
Intrinsically Safe (IS) A circuit or device in which any spark or thermal effect is incapable of causing
ignition of a mixture of flammable or combustible material in air under prescribed test conditions.
Intumensent - A fireproofing material (epoxy coating, sealing compound or paint) which foams or swells to
severaI times its volume when exposed to heat from a fire and simultaneous forms an outer char covering,
that together forms an insulating thermo layer against a high temperature fire.
Liquefied Natural Gas (LNG) - Natural gas that has been converted to a liquid through cooling to
approximately -1 62OC (-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 compression and/or refrigeration, commonly referred to as "bottled
gas".
Lower Explosive Limit (LEL) - The minimum concentration of combustible gas or vapor in air below
which propagation of flame does not occur on contact with an ignition source.
Naphtha - Straight run gasoline distillate, below the boiling point of kerosene. Naphthas are generally
unsuitable for blending as a component of premium gasolines, hence they are used as a feedstock for
catalytic reforming in hydrocarbon production processes or in chemical manufacturing processes.
Natural Gas - A mixture of hydrocarbon compounds and small amounts of various nonhydrocarbons (such
as carbon dioxide, helium, hydrogen sulfide, and nitrogen) existing in the gaseous phase or in solution with
crude oil in natural underground reservoirs.
Natural Gas Liquids (NGL) - The portions of natural gas that are liquefied at the surface in production
separators, field facilities, or gas processing plants, leaving dry natural gas. They incIude but are not limited
to ethane, propane, butane, natural gasoline, and condensate.
Overpressure - Is any pressure relative to ambient pressure caused by an explosive blast, both positive and
negative.
Process - Any activity or operation leading to a particular event.
Programmable Logic Controller (PLC) - A digital electronic controller that uses computer based
programmable memory for implementing operating instructions through digital or analog inputs and outputs.
Reid Vapor Pressure (RVP) - The pressure caused by vaporized part if a liquid and the enclosed air and
water vapor as measured under standardized conditions in standardized apparatus, the result given in psi at
100 OF, although normally reported as R W in Ibs. R W is not the same as the true "vapor pressure" of the
liquid, 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 the
stated conditions for 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 acceptable level of risk of, relative freedom from and low probability of
harm.
Safety Integrity Level (SIL) - The degree of redundancy and independence from the effects of inherent and
operational failures and external conditions that may affect system performance.
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Handbook of Fire and Explosion Protection
Smoke - The.gaseous products of the burning of carbonaceous materials made visible by the presence of
small particles of carbon, the small particles that are of liquid or solid consistencies are produced as a by
product of insufficient air supplies to 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 specific
characteristic patterns and densities for purposes of cooling exposures, suppression of fires and vapor
dispersions.
Triple Modular Redundant (TMR) - A system that employs a 2 out of 3 (2003), voting scheme to
determine the appropriate output action. It is based on the application of three separate operating systems
running in parallel.
Vapor Pressure (VP) - The pressure, measured in psia, exerted by a volatile liquid as determined by ASTM.
D 323, Standard Method of Test for Vapor Pressure of Petroleum Products (Reid method).
Index
-
Drainage systems - 104, 155
Dry chemical - 221
Dual agent suppression systems - 221
Dual agent systems - 221
Air intakes 100
Alarm overload - 245
Alarms - 197
Arctic environments - 228
Arrangement - 101
Asphalt - 37
Autoignition temperature - 30
Electrical area classification - 143, 146
Electrical equipment - 234
Electronic process control - 112
Emergency isolation valves - 121
Ergonomics - 240
Ethane - 34
Evacuation modeling - 91
Evacuation routes - 197
Event trees - 90
Exits - 198
Explosion overpressure study - 91
Explosionproof equipment - 148
Explosions - 48, 159, 160
Backup power - 191
Basic process control system - 111
Battery rooms -- 235
BLEW -51
Blowdown - 133
Blowdown capability study - 91
Blowout suppression system - 212
BOP failures - 83
Butane - 35
Carbon dioxide systems - 216
Carbon monoxide - 53
Checklist safety review - 89
Classified locations - 147
Color coding - 243
Combustible vapor dispersion study - 91
Combustion - 44
Communication facilities - 100
Communication rooms - 234
Condensate 36
Consequence modeling - 53, 89
Conversion factors - 275
Cooling towers - 237
Critical utilities - 99
Cross zoning - 191
Crude oil - 34
Facility access - 101
Fail safe - 117
Fatality accident rates - 91
Fault trees - 90
Fire control - 56
Fire dampers - 174
Fire detection - 177
Fire models - 91
Fire protection engineering - 5
Fire pumps - 205
Fire testing laboratories - 1678
Fire triangle - 44
Fire zones - 100
Fireproofing - 164, 166, 169
Firesafe valve standards - 122
Firewater distribution systems - 208
Firewater pumps - 98, 208
Firewater reliability study 91
Flame arrestors - 173
Flame blow out - 55
Flame extinguishment methods - 55
Flame resistance - 172
Flares - 98, 133
Flash fire - 47
Flash point - 29
-
Deluge systems - 210
Depressurization capability study - 91
Desert environments - 228
Design principles - 22
Detonation arrestors - 174
Detonations - 48
Diesel - 37
Distributed control system - 112
DOW hazard index - 90
-
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Handbook of Fire and Explosion Protection
Floating production facilities - 230
Flow performance tests - 250
FMEA - 90
Foam - 213
Foam water deluge - 215
Fuel oils - 37
Gas compressor - 235
Gas detection - 185-190
Gaseous releases - 42
Gasoline - 36
Graphic annunciation - 191
Greases - 37
Halon - 218
Halon replacements - 219
M O P - 90
Heat detectors - 179
Heat flux - 45
Heat transfer systems - 236
High expansion foam - 216
Hose reels - 212
Hot work - 143
Human attitude - 242
Human error analysis - 91
Human errors - 241
Human factors - 240
Human reliability analysis - 91
Human surveillance - 177
Hydrants - 212
Hydrogen cyanide - 52
Illumination - 198
Independent layers of protection- 20
Infrared OR) detectors - 181
Infra-red (IR) beam gas detection - 189
Insurance - 6
Internal combustion engines - 151
Intrinsically safe - 148
Ionization detectors - 178
Jet fire
- 46
Kerosene - 37
Kitchens - 238
Laboratories - 237
Leak estimation - 91
Lightning - 150
Liquefied natural gas - 34
Liquefied petroleum gas - 35
Liquid releases - 43
Loading facilities - 234
Lower explosive limit - 29
Lubricating oils - 37
Management accountability - 7
Methane - 34
MOND hazard index - 90
Monitors - 212
Multi-band detectors - 182
Natural gas - 34
NEMA classifications - 269
Noise - 245
Nozzles - 213
Offshore evacuation - 198, 200
Offshore facilities - 229
Oily water sewer - 140
Open flames - 143
Optical (flame) detectors - 180
Overhead foam injection - 215
Overpressures - 50
Panic - 246
Philosophy of protection - 17
Photoelectric detectors - 178
Pipelines - 230
Pool fire - 47
Portable fire extinguishers - 202
Potential loss of life - 91
Power supplies - 98
Preliminary hazard analysis - 90
Pressure relief - 140
Pressure relief valves - 138
Process units - 98
Propane - 35
Pump seals - 156
Purging - 148
Radiation shields - 171
Risk acceptance criteria - 93
Risk evaluation - 89
Risk management - 6
Safety flow chart - 87
Safety integrity levels - 118
Sample points - 155
SCADA - 112
Security - 246
Segregation - 95
Semi-confined explosions - 49
Separation - 96
Smart technology - 112
Smoke - 52
Smoke dampers - 173
Smoke detection - 177
Index
Smoke detectors - 178
Smoke models - 91
Solar heat - 139
Spark arrestors - 151, 173
Spill containment - 107
Sprinkler systems - 210
Static - 149
Steam smothering - 55, 211
Storage tanks - 98
Subsea isolation valves - 121
Subsurface foam injection - 215
Surface drainage - 105
Surface temperatures - 149
Survivability of safety systems study - 91
Thermal relief - 139
Time temperature curves - 168
Transformers - 237
Turbines - 235
Ultraviolet (UV)detector - 180
Ultraviolet/infrared (UV/IR) detectors - 182
Upper explosive limit - 29
Valves - 209
Vapor cloud explosions - 49
Vapor density - 33
Vapor dispersion - 163, 171, 211
Venting - 133
Voting logic - 191
Warehouses - 238
Water cooling sprays - 171
Water curtains - 211
Water flooding - 211
Water spray - 210
Water sprays - 163
Water supplies - 204
Wax - 38
Welding - 143
Wellheads - 231
Wet chemical systems - 221
What-if reviews - 90
291