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Analysis of the Explosive Boiling Process of Liquefied Gases Due to Rapid Depressurization 2017 Journal of Loss Prevention in the Process Indust
Saito Etal 2000
CEV654-Lecture 2a Major Incidents r1
Reboiler Rupture and Fire
No. 2013-03-I-LA
CSB Williams Geismar Case Study
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No part of the conclusions, findings, or recommendations of the CSB relating to any chemical accident
may be admitted as evidence or used in any action or suit for damages. See 42 U.S.C. 7412(r)(6)(G).
This CSB Case Study is dedicated to the two men, listed below, who lost their lives as
a result of this incident, as well as to the numerous workers injured on June 13, 2013.
Zach Green, 29
Scott Thrower, 47
We would never knowingly tolerate a situation in which accidental operation of a valve resulted in the
overpressuring of a vessel. We would install a relief valve. In the same way, accidental operation of a
valve should not be allowed to result in explosion []. Trevor Kletz, What Went Wrong? Case
Histories of Process Plant Disasters and How They Could Have Been Avoided, 5th ed., 2009
This case study examines the June 13, 2013 catastrophic
equipment rupture, explosion, and fire at the Williams
Olefins Plant in Geismar, Louisiana, which killed two
Williams employees. The incident occurred during
nonroutine operational activities that introduced heat to a
type of heat exchanger called a reboiler which was
offline, creating an overpressure event while the vessel
was isolated from its pressure relief device. The
introduced heat increased the temperature of the liquid
propane mixture 1 confined within the reboiler shell,
resulting in a dramatic pressure rise within the vessel due
to liquid thermal expansion. The reboiler shell
catastrophically ruptured, causing a boiling liquid
expanding vapor explosion (BLEVE) 2 and fire.
Analysis of Williams Geismar Process
6.0 Hierarchy of Controls
7.0 Industry Codes and Standards
8.0 Williams Geismar Post-incident Changes
9.0 Strategies for Improving Safety Culture
10.0 Key Lessons
Appendix A Causal Analysis AcciMap
Appendix B Failure Scenario Analysis
Appendix C Metallurgical Analysis Report
Process safety management program weaknesses at the
Williams Geismar facility during the 12 years leading to
the incident caused the reboiler to be unprotected from
overpressure. These weaknesses include deficiencies in
implementing Management of Change (MOC), Pre-Startup Safety Review (PSSR), and Process Hazard Analysis
(PHA) programs. In addition, the company did not perform a hazard analysis or develop a procedure for the
operational activities conducted on the day of the incident. This incident illustrates the importance of:
Using the hierarchy of controls when evaluating and selecting safeguards to control process hazards;
Establishing a strong organizational process safety culture;
Developing robust process safety management programs; and
Ensuring continual vigilance in implementing process safety management programs to prevent major
process safety incidents.
Following the incident, Williams implemented improvements in managing process safety. To prevent future
incidents and further improve process safety at the Geismar plant, the U.S. Chemical Safety and Hazard
Investigation Board (CSB) recommends that Williams strengthen existing safety management systems and adopt
additional safety programs. The CSB also issues recommendations to the American Petroleum Institute (API) to
help prevent future similar incidents industry-wide.
The process fluid in the reboiler contained an estimated 95% propane, with the balance composed mostly of propylene and C4
hydrocarbons, such as butane.
See section 4.0 for a technical explanation of the BLEVE mechanism, and a detailed sequence of events leading to the explosion.
WILLIAMS BACKGROUND
The Williams Companies, Inc. (Williams) is an energy infrastructure company headquartered in Tulsa,
Oklahoma. Founded in 1908, Williams owns interests in natural gas and natural gas liquid (NGL) pipeline and
processing facilities throughout North America, and conducts most of its operations through subsidiary
companies. One of its subsidiary companies is Williams Olefins LLC, which owns and operates the Williams
Geismar Olefins Plant.
GEISMAR OLEFINS PLANT
The Williams Geismar Olefins Plant, which employs approximately 110 people, is located in Geismar, Louisiana,
approximately 20 miles southeast of Baton Rouge. The Lummus Company designed and built the olefins plant in
1967, and Allied Chemical first operated it. In 1985, Union Texas Petroleum purchased the plant from Allied
Chemical and sold it to Atlantic Richfield Company (ARCO) in 1998. Williams then purchased the facility in
1999. At the time of the incident, Williams Olefins LLC and Saudi Basic Industries Corporation (SABIC) jointly
owned the plant, and Williams Olefins was the sole operator.
The Williams Geismar Olefins Plant produces ethylene and propylene for the petrochemical industry. 3 The plant
originally produced 600 million pounds of ethylene annually. Over the years, the production capacity increased
to 1.35 billion pounds of ethylene and 80 million pounds of propylene per year. At the time of the incident,
approximately 800 contractors worked at the Williams Geismar facility on an expansion project, with an end goal
of increasing the production of ethylene to 1.95 billion pounds per year.
The June 13, 2013 incident occurred when a reboiler, a heat exchanger that supplies heat to a distillation column, 4
catastrophically ruptured. The reboiler that failed, EA-425B (Reboiler B) was one of two reboilers (Reboiler A
and Reboiler B) that supplied heat to the propylene fractionatora distillation column that separates propylene
and propane. The process fluid on the shell-side 5 of these reboilers is heated by hot quench water, 6 flowing
through the tubes. Reboiler B had been offline for 16 months while Reboiler A was in operation, but was clean
and available for use when Reboiler A eventually fouled (see Section 2.4). 7 Figure 1 is a simplified flow diagram
highlighting the location of the propylene fractionator relative to the overall olefins production process.
Williams corporate website. https://co.williams.com/operations/ngl-petchem/olefins/ (accessed August 17, 2016). Olefins, also
known as alkenes, are hydrocarbons that contain a carbon-carbon double bond. The primary olefins produced by the Williams
Geismar facility are ethylene (H2C=CH2), and propylene (CH3CH=CH2). Ethylene is a basic chemical used in the production
process of a variety of products including plastics, soaps, and antifreeze. A primary use of propylene is the manufacturing of
plastic materials and antifreeze.
A distillation column is a type of process equipment that separates a feed mixture based upon the mixture components boiling
point temperatures. Components with lower boiling point temperatures, the more volatile components, leave the upper portion of
a distillation column, while components with higher boiling point temperatures, the less volatile components, leave the lower
portion of a distillation column.
The propylene fractionator reboilers are shell and tube heat exchangers. This type of heat exchanger has a large cylindrical
exterior or shell, with a bundle of tubes inside of the shell.
Quench water is water that is used to cool furnace effluent gases through direct contact with the gases. It is a process water
stream because it directly contacts and often contains residual material from the furnace effluent gases.
Fouling historically occurred on the process water (quench water) side of the reboilers. Fouling is a term used to describe a
buildup on equipment surfaces of undesired material that has an adverse impact such as reducing heat transfer efficiency.
Simplified flow diagram of the olefins process. The incident occurred when a propylene fractionator
reboiler that had been offline for 16 months catastrophically ruptured. The propylene fractionator is
OLEFINS PRODUCTION PROCESS DESCRIPTION
At the beginning of the olefins production process, ethane and propane enter cracking furnaces 8 where they are
converted to ethylene and propylene, as well as several byproducts including butadiene, aromatic compounds, 9
methane, and hydrogen (Figure 1). The furnace effluent gases leave the cracking furnaces and enter heat
exchangers that reduce the temperature of the gases. The furnace effluent gases then enter the quench tower for
further cooling by direct contact with quench water, which is sprayed downward from the top of the tower. After
additional processing, the cooled gases go to a series of distillation columns, such as the propylene fractionator,
which separate the reaction products into individual components. The ethylene, propylene, butadiene, and
aromatic compound products are then transported and sold to customers. Unreacted ethane and propane are
recycled back to the beginning of the process.
The quench water that directly contacts the heated furnace effluent gases is part of a closed-loop water circulation
system. As the heated furnace effluent gases are cooled in the quench tower, heat transfers to the quench water.
The heated quench water then serves as a heat source in various heat exchangers within the process, heating
process streams while also reducing the temperature of the quench water. Finally, a cooling water system further
cools the quench water before it circulates back to the quench tower (Figure 2).
Cracking is the breaking apart of molecules to form different molecules.
Examples of aromatic compounds, also called arenes, include benzene and toluene.
Because the quench water directly contacts process gases, oily tar products 10 contained in the gas condense into
the quench water. The quench water settler removes most of the tar material (Figure 2); however, some oily
material remains in the quench water. Over time, some of this material adheres to and builds up on the inside of
process equipment such as heat exchanger tubes, resulting in a decrease in both heat transfer efficiency and
quench water flow rate. The buildup of such material is called fouling. When quench water flow through the
process periodically decreased due to fouling, Williams operations personnel would evaluate the quench water
system by analyzing, among other things, flow rates through pumps and heat exchangers to identify the fouled
piece of equipment likely causing the decrease in quench water flow. Williams personnel were performing this
type of nonroutine operational activity when the incident occurred on June 13, 2013.
Quench water system. The propylene fractionator Reboilers A and B are
highlighted in yellow. The reboiler that ruptured, Reboiler B, is indicated
with the red outline.
The tar products form in the cracking furnaces.
PROPYLENE FRACTIONATOR REBOILERS
The propylene fractionator Reboilers A and B are shell and tube heat exchangers, 11 where tube-side hot quench
water vaporizes shell-side hydrocarbon process fluid, which is approximately 95% propane with the balance
composed mostly of propylene and C4s 12 (Figure 3 13 and Figure 4). (This report refers to the propane mixture as
propane.) Quench water enters the propylene fractionator reboilers at approximately 185 F and partially
vaporizes the shell-side propane, which enters the reboiler at a temperature of approximately 130 F.
The original propylene fractionator design had both reboilers continuously operating. This process design required
periodic propylene fractionator downtime when the reboilers fouled and required cleaning. In 2001, Williams
installed valves on the shell-side and tube-side reboiler piping to allow for continuous operation with only one
reboiler operating at a time. The other reboiler would be offline but ready for operation (see Section 5.1), isolated
from the process by the new valves. This configuration allowed for cleaning of a fouled reboiler while the propylene
fractionator continued to operate. Unforeseen at the time due to flaws in the Williams process safety management
program (discussed in subsequent sections in this report), these valves also introduced a new process hazard. If the
new valves were not in the proper position (open or closed) for each phase of operation, the reboiler could be isolated
from its protective pressure relief valve located on top of the propylene fractionator (Figure 4).
Propylene fractionator reboiler.
The heat exchangers are 24 feet 8 inches long end-to-end. Each exchanger shell (the portion of the heat exchanger that holds the
tube bundle) is approximately 18.5 feet long and over 5 feet in diameter. The tubes are each -inch in diameter, and each heat
exchanger contains 3,020 tubes. To put this in perspective, if one were to lay each tube from one heat exchanger end-to-end in a
straight line, the tubes would span over 10.5 miles.
C4s are hydrocarbon molecules that contain four carbon atoms. For example, butane (C4H10) is a C4 molecule.
Depicted in Figure 3 as a two-pass heat exchanger for purposes of simplicity, the reboilers were six-pass heat exchangers.
Propylene fractionator schematic. This schematic represents the equipment configuration at the time of
the incident. The valves (gate valves) isolating the reboilers from the pressure relief valve at the top of
the propylene fractionator were not part of the original design, and were installed in 2001. Section 5.1
provides additional information about these valves.
3.0 THE INCIDENT
On June 13, 2013, during a daily morning meeting with operations and maintenance personnel, the plant manager
noted that the quench water flow through the operating propylene fractionator reboiler (Reboiler A) had dropped
gradually over the past day (Figure 5). The group then analyzed plant data and noticed the entire quench water
circulation rate seemed to be impaired. An operations supervisor, who Williams often relied on to troubleshoot
and mitigate operational problems, informed the group that he would try to determine what caused the drop in
flow. After evaluating the quench water system in the field, the operations supervisor informed several other
personnel that fouling within the operating reboiler (Reboiler A) could be the problem and they might need to
switch the propylene fractionator reboilers to correct the quench water flow. The operations supervisor attempted
to meet with the operations manager to discuss switching the reboilersa typical chain of communicationso
that they could begin getting the necessary maintenance and operations personnel involved who needed to
perform the work. The operations manager was not available, however, and the operations supervisor decided to
return to the field and continue evaluating the quench water system.
Graph of quench water flow rate through propylene fractionator Reboiler A prior to incident.
Williams personnel identified that quench water flow rate had dropped.
The CSB determined that at 8:33 am, the operations supervisor likely opened the quench water valves on the
offline reboiler, Reboiler B, as indicated by the rapid increase in quench water flow rate shown in Figure 6.
Approximately three minutes later, Reboiler B exploded (Figure 7). Propane and propylene process fluid erupted
from the ruptured reboiler and from the propylene fractionator due to failed piping. The process vapor ignited,
creating a massive fireball. The force of the explosion launched a portion of the propylene fractionator reboiler
piping into a pipe rack approximately 30 feet overhead (Figure 8).
A Williams operator working near the propylene fractionator at the time of the explosion died at the scene. The
operations supervisor succumbed to severe burn injuries the next day. The explosion and fire also injured
Williams employees and contractors who were working on a Williams facility expansion project167 personnel
reported injuries. 14 The fire lasted approximately 3.5 hours, and Williams reported releasing over 30,000 pounds
of flammable hydrocarbons during the incident. 15 The plant remained down for 18 months and restarted in
Graph of quench water flow
rate immediately prior to
incident. Quench water flow
rate rises when Reboiler B tubeside quench water valves are
opened. Reboiler B ruptures
Post-incident photo of the
ruptured Reboiler B.
Of the 167 workers who reported injuries, three were Williams employees and 164 were contractors.
Louisiana Department of Environmental Quality Incident Report. See
http://edms.deq.louisiana.gov/app/doc/view.aspx?doc=8925500&ob=yes&child=yes at p 2 (accessed August 28, 2016).
Post-incident photo of the propylene fractionator reboilers and surrounding area. The Reboiler B
vapor return piping can be seen overhead in the pipe rack (red circle). The approximate original
configuration of the piping and equipment is shown in Figure 9 and Figure 14.
The CSB commissioned metallurgical testing of the ruptured Reboiler B by agreement among Williams, OSHA,
and the CSB. 16 The metallurgical testing found that the propylene fractionator Reboiler B failed, resulting in the
formation of a crack, at a high internal pressure estimated to be between 674 and 1,212 pounds per square inch
gauge (psig). The CSB concluded that a pressure of this magnitude was likely the result of liquid thermal
expansion in the liquid propane-filled and blocked-in Reboiler B shell, which overpressured the heat exchanger
while it was isolated from its pressure relief device. 17 The initial crack formation quickly progressed to
catastrophic vessel failure, which resulted in a boiling liquid expanding vapor explosion (BLEVE) (see Section
4.2 for a technical description of the BLEVE mechanism).
FAILURE OF REBOILER B
As explained above, following the 2001 valve installation, Williams Geismar operated one propylene fractionator
reboiler at a time, keeping the other reboiler offlinein a configuration Williams called standby. After the
operating reboiler fouled, Williams operations staff would put the standby reboiler online. They would then shut
down, drain, blind, 18 and clean the fouled reboiler. Next, they would remove the blinds and pressurize the
reboiler with nitrogen, 19 leaving the inlet and outlet block valves isolating the standby, nitrogen-filled reboiler
shell from the propylene fractionator process fluid. The reboiler remained on standby, typically for a couple of
years, until the second, now operating reboiler fouled.
4.1.1 STANDBY REBOILER B CONTAINED LIQUID PROPANE
Williams performed maintenance on Reboiler B in February 2012. Following this maintenance activity, workers
left Reboiler B on standby, reportedly filled with nitrogen and isolated from the process by a single closed block
valve on the inlet piping and a single closed block valve on the outlet piping. The CSB determined that between
the 2012 maintenance activity and the day of the incidenta period of 16 monthsflammable liquid propane
accumulated on the shell side of the standby Reboiler B (Figure 9). 20 The propane could have entered the standby
reboiler via a mistakenly opened valve, leaking block valve(s), or another unknown mechanism. 21 (Depending on
the scenario that allowed propane to enter the reboiler, the nitrogen could have compressed and/or been pushed
from the reboiler into the process.) Williams had not installed instrumentation to detect process fluid within the
reboiler. As a result, Williams personnel did not know that the standby Reboiler B contained liquid propane. 22
The metallurgical report is located in Appendix C.
A blind is a metal plate inserted between flanges to ensure positive isolation of a vessel from the process.
Nitrogen is often used to fill a standby vessel because it is an inert gas. It is used to reduce the oxygen concentration in
equipment in order to eliminate the possibility of a flammable mixture within the vessel or process.
Discussed in Appendix B, the reboiler was at least 65.5 vol% full of liquid propane.
Large gate valves such as the ones installed on the Williams reboilers are known to leak. The American Petroleum Institute (API)
specifies allowable leakage rates through closed valves. For 16-inch and 18-inch valves such as the inlet valve and outlet valve
on the propylene fractionator reboilers, API specifies an allowable leakage rate of 64 and 72 bubbles of gas per minute,
respectively, during leak testing of the valves. (See API Standard 598, 9th ed. Valve Inspection and Testing, September 2009, p
10.) The reboiler block valves were leak tested following the incident. Their leakage rate was within that allowed by API
Standard 598. While valve leakage likely allowed some process fluid to enter Reboiler B while it was on standby, a different
mechanism could have introduced the bulk of the process fluid to the standby reboiler.
Records indicate that Williams filled the Reboiler B shell with nitrogen, to a pressure of approximately 50 psig, during a 2012
maintenance activity. Reboiler B did not have a pressure gauge installed on its shell to allow for periodic monitoring. A pressure
gauge could have alerted the operations supervisor that the Reboiler B shell was at a pressure of at least 124 psig (the equilibrium
vapor pressure of the process fluid at ambient temperature). This could have served as an indication that process fluid had entered
the Reboiler B shell.
Closed gate (block) valves leak,
and they are susceptible to
inadvertent opening. Both
scenarios can introduce process
fluids to offline equipment.
More robust isolation methods,
such as inserting a blind, can
better protect offline equipment
from accumulation of process
***Note: Tube side piping not illustrated
Propane process fluid mixture entered standby Reboiler B by a mistakenly opened
valve, valve leakage, and/or another mechanism.
4.1.2 FAILURE OF REBOILER B DUE TO LIQUID THERMAL EXPANSION
Post-incident field observations identified that the Reboiler B tube-side hot quench
water valves were in the open position (Figure 10). The shell-side process valves
were closed, which isolated the shell of Reboiler B from its protective pressure
relief valve on the top of the propylene fractionator (Figure 4). This valve
alignment shows that heat was introduced into a closed system (i.e., the blocked-in
Reboiler B shell).
When the Reboiler B hot quench water valves were opened, the liquid propane
within the standby Reboiler B shell began to heat up. This caused the liquid
propane to increase in volume due to liquid thermal expansion, 23 filling any
remaining occupiable vapor space within the shell. When the liquid could no
longer expand due to confinement within the blocked-in Reboiler B shell, the
pressure rapidly increased 24 until the internal pressure exceeded the shells
mechanical pressure limit (Figure 11), and the reboiler shell failed. 25
Thermal expansion is the increase in volume of a given mass of a solid, liquid, or gas as it is heated to a higher temperature.
The liquid propane expanded and pressurized the reboiler faster than the vessel contents could escape through the leaking block
The 2008 Goodyear Tire and Rubber Company explosion, investigated by the CSB, also occurred when heat was introduced to a
heat exchanger that did not have an open path to its pressure relief device. That incident killed one person and injured six others.
See the CSBs final investigation report on the incident: Chemical Safety Board Website. Heat exchanger rupture and ammonia
release in Houston, Texas. http://www.csb.gov/goodyear-heat-exchanger-rupture/ (Accessed August 17, 2016).
Post-incident, the Reboiler B quench water inlet ball valve was found partially open (left), and the Reboiler B
quench water outlet ball valve was found fully open (right). When the position indicator is parallel to the pipe,
the valve is open; when the position indicator is perpendicular to the pipe, the valve is closed.
Expanding shell-side liquid propane could
not sufficiently increase in volume due to
the lack of overpressure protection and the
closed shell-side process valves. As a
result, shell-side pressure increased until
reboiler shell failed.
Equipment or pipelines which are full of liquid under no-flow conditions are subject to hydraulic
expansion due to increase in temperature and, therefore, require overpressure protection. Sources of heat
that cause this thermal expansion are solar radiation, heat tracing, heating coils, heat transfer from the
atmosphere or other equipment. Another cause of overpressure is a heat exchanger blocked-in on the cold
side while the flow continues on the hot side. Center for Chemical Process Safety (CCPS), Guidelines for
Engineering Design for Process Safety, 2nd ed., 2012
BLEVE, pronounced blev-, stands for Boiling
Liquid Expanding Vapor Explosion. A BLEVE is
the explosive release of expanding vapor and
boiling liquid when a container holding a pressure
liquefied gaswhere the liquefied gas is above its
normal atmospheric pressure boiling point
temperature at the moment of vessel failure
suddenly fails catastrophically.i This explosive
release creates an overpressure wave that can propel
vessel fragments, damage nearby equipment and
buildings, and injure people. If the pressurized
liquid is flammable, a fireball or vapor cloud
explosion often occurs. BLEVEs often result in the
failed vessel flattened on the ground.
Fireball from propane BLEVE experiment.ii
4.2 BOILING LIQUID EXPANDING VAPOR
EXPLOSION (BLEVE)
The high pressure generated from liquid thermal expansion
of the propane cracked the reboiler shell. The shell contents
began to vaporize near the crack opening, and a jet release of
liquid and vapor accelerated out of the crack. The pressure
loading on the open edges of the crack caused the crack to
continue to grow along the vessel length. As the crack
opening increased in size, the liquid and vapor jet release also
rapidly grew. The continued internal pressure caused the
reboiler shell to fail suddenly and catastrophically, splitting
wide open (Figure 7 and Figure 12).
With the shell confinement suddenly gone, the bulk of the
shell contents abruptly lowered to atmospheric pressure. At
atmospheric pressure, the liquid propane was above its
boiling point (i.e. in a superheated state). (The atmospheric
boiling point of the propane mixture was approximately -43
F, 26 and the liquid propane mixture was at a much higher
temperature.) The propane explosively released into the
surrounding area: propane vapor violently expanded and the
superheated liquid rapidly vaporized. This type of explosion
is known as a BLEVE. 27
The propane then found an ignition source and ignited,
creating a massive fireball. The blast effects flattened the
reboiler shell (Figure 12).
Vessel flattened on ground following BLEVE.iii
i. Birk, A.M.; Davison, C.; Cunningham, M.; Blast Overpressures
from Medium Scale BLEVE Tests. Journal of Loss Prevention in
the Process Industries, 2007, vol. 20, pp 194-206.
ii.http://me.queensu.ca/People/Birk/Research/ThermalHazards/bl
eve/FieldTrials2000-2002.html (accessed August 17, 2016).
iii. Birk, A.M.; VanderSteen, J.D.J.; Davison, C.; Cunningham,
M.H.; Mirzazadeh, I.; PRV Field Trials The Effects of Fire
Conditions and PRV Blowdown on Propane Tank Survivability in
a Fire, TP 14045E, Transport Canada, 2003.
Found using Aspen HYSYS simulation of Williams design composition of the propylene fractionator bottoms.
Center for Chemical Process Safety (CCPS). Guidelines for Vapor Cloud Explosion, Pressure Vessel Burst, BLEVE and Flash
Fire Hazards, 2nd ed.; John Wiley & Sons, Inc.: Hoboken, New Jersey, 2010; p 311.
Post-incident photo of Reboiler B shell. The pressure forces during the event flattened the cylindrical steel
reboiler shell.
In recent years, process safety culture has
been a topic of increased focus within the
chemical process industry. Safety
Culture is often simply described as the
way we do things around here, or how we
behave when no one is watching. The
chemical process industry has defined
process safety culture as [t]he common set
of values, behaviors, and norms at all levels
in a facility or in the wider organization that
affect process safety.i
A significant determinant of an
organizations process safety culture is the
quality of its written safety management
programs (e.g., process safety management
procedures, including PHA, MOC, PSSR,
operating procedures; and written corporate
policies) and how well individuals within
the organization, ranging from the CEO to
the field operator, implement those
programs. The Center for Chemical
Process Safety has labeled these two facets
as Conduct of Operations and
Operational Discipline, respectively.ii
Improving an organizations process safety
culture starts with management. Managers
can help to set a high bar for the
organizations commitment to effectively
implementing safety management programs
i. Center for Chemical Process Safety (CCPS). Conduct of
Operations and Operational DisciplineFor Improving
Process Safety in Industry; John Wiley & Sons, Inc.:
5.0 ANALYSIS OF WILLIAMS GEISMAR
As will be explained in this section, the ineffective
implementation of the Williams Geismar process safety
management programs 28 (Figure 13 shows a timeline of the
program deficiencies during the 12 years leading to the
incident), as well as weaknesses in Williams written
programs themselves, were causal to the incident.
Weaknesses in these programs resulted from a culture at the
facility that did not foster and support strong process safety
performance. Discussed in the following sections, Williams
Geismars process safety management program deficiencies
that contributed to the incident include:
(1) Williams did not perform adequate Management of
Change (MOC) or Pre-Startup Safety Reviews (PSSRs) for
two significant process changes involving the propylene
fractionator reboilersthe installation of block valves and the
addition of car seals (see Section 5.1 and Section 5.2.2.1). 29
As a result, the company did not evaluate and control all
hazards introduced to the process by those changes. Not
identifying and controlling the new process overpressurization
hazard was causal to the incident;
(2) Williams did not adequately implement action items
developed during Process Hazard Analyses (PHAs) or
recommendations from a contracted pressure relief system
engineering analysis (see Section 5.2 and Section 5.4).
Consequently, Williams did not effectively apply overpressure
protection by either a pressure relief valve or by
administrative controls to the standby Reboiler B; and
(3) Williams did not perform a hazard analysis and develop a
procedure prior to the operations activities conducted on the
day of the incident (see Section 5.3).
Process safety management programs have been developed and described in industry good practice guidance (such as books
published by the Center for Chemical Process Safety) and are required by both OSHA as part of its Process Safety Management
(PSM) regulation and by the Environmental Protection Agency (EPA) as part of its Chemical Accident Prevention provisions
(commonly referred to as its Risk Management Program (RMP) regulation). See 29 C.F.R. 1910.119. Process Safety
Management of Highly Hazardous Chemicals and 40 C.F.R. Part 68, Subpart D - Program 3 Prevention Program.
A car seal is a mechanical device that physically locks a valve in the open or closed position to prevent manipulation by an
unauthorized person. A car seal is an administrative control. Nonmandatory Appendix M-5 of ASME Boiler and Pressure Vessel
Code, Section VIII, Division 1, allows for the use of administrative controls such as car seals to ensure an open path between a
pressure vessel and its pressure relief device(s).
When the quench water valves were opened, therefore, there were no safeguards to prevent high pressure on the
shell side of the reboiler. Since the reboiler lacked adequate overpressure protection, introducing heat to the
standby reboiler initiated the overpressure event that caused the reboiler to rupture catastrophically.
The process safety culture of an organization is a significant determinant of how it will approach process
risk control issues, and process safety management system failures can often be linked to cultural
deficiencies. Accordingly, enlightened organizations are increasingly seeking to identify and address such
cultural root causes of process safety performance problems. CCPS, Guidelines for Risk Based Process
Safety, 2007.
Timeline of events leading to the June 2013 incident.
REBOILER VALVES INSTALLATION
The original 1967 design of the propylene fractionator required both Reboiler A and Reboiler B in service at the
same time. This design had no valves between the reboilers and the propylene fractionator, protecting the two
reboilers from overpressure with the relief device located on top of the propylene fractionator. In subsequent
years, Williams determined that the propylene fractionator could operate with only one reboiler in service.
Operating with a single reboiler allowed continuous propylene fractionator operation and avoided shutdowns
when the reboiler tubes fouled and required cleaning. To implement single reboiler operation, in 2000 Williams
Geismar management approved a $270,000 investment to install valves on both the process side and quench water
side of six of the quench water heat exchangers, including the propylene fractionators Reboiler A and Reboiler B.
In 2001, Williams installed the valves (Figure 14); however, Williams did not identify the overpressure hazard
that resulted from this change.
***Note: Tube-side piping not illustrated
Illustration of the propylene fractionator reboilers prior to the incident, with shell-side piping shown.
The four shell-side process valves were installed in 2001.
Robust Management of
Change (MOC) practices are
needed to ensure the review
analyzes hazards in the
entire process affected by the
change. Similar to PHAs,
conducting MOC reviews as
and different areas of
expertisecan assist in
introduced by a process
change. Companies must
conduct MOCs before
implementing a change in
the field, and should not treat
them as a paperwork or
check-the-box exercise.
VALVE INSTALLATION MANAGEMENT OF CHANGE
Industry good practice guidance advisesand the OSHA PSM regulation and the
EPA RMP regulation requirechemical process facilities to conduct a
Management of Change (MOC) review before making a change to a covered
process, such as a change in equipment. 30 Among other requirements, OSHA and
EPA require that a facilitys MOC reviews consider the impact of the change on
safety and health, and whether operating procedures need modifications. OSHA
and EPA also require that companies train affected employees on the change
prior to startup or implementation. 31
In 2001, Williams performed one MOC to cover the installation of valves on the
six quench water heat exchangers identified in the 2000 proposal, including the
propylene fractionator Reboiler A and Reboiler B. The Williams MOC process
required the Operations Department, Maintenance Department, Technical
Department, Environmental Department, Safety Department, and Project
Engineering Department to consider the potential safety implications of installing
the valves. They did this by answering checklist questions used to prompt
targeted analysis for each department. Department managers were required to
respond to each prompt by checking yes, no, or n/a (not applicable). While
MOC checklists can ensure consideration of common hazards and typical change
requirements, the Williams MOC reviewers nevertheless did not identify the
serious overpressure hazards introduced by installing valves on the reboilers. 32
29 C.F.R. 1910.119(l) and 40 C.F.R. 68.75.
29 C.F.R. 1910.119(l)(3) and 40 C.F.R. 68.75.
Installing block valves into a process can introduce overpressure hazards to process equipment. The ASME Boiler and Pressure
Vessel Code allows block valves to be installed in a relief path where there is normally process flow, as long as the user provides
a method of overpressure protection, such as applying administrative controls, mechanical locking elements, valve failure
controls, and valve operation controls to provide an open path between the vessel and its pressure relief device(s). See American
Society of Mechanical Engineers. ASME Boiler and Pressure Vessel Code, 2015. Section VIII, Division 1, UG-135 and
Nonmandatory Appendix M-5.7(3).
MANAGEMENT OF CHANGE PERFORMED AFTER VALVE INSTALLATION
The MOC process at Williams intended to provide a method 33 to identify and control 34 all possible hazards
presented by a process change before making the process change in the facility. 35 Williams, however, did not
perform an MOC before installing and commissioning the new block valves on the reboilers. In fact, Williams
did not perform the MOC until after the plant was operating with the new valves. 36 The MOC was an after-thefact activity for Williams to address a regulatory requirement rather than an effective tool used to identify and
control new process hazards prior to installing the new equipment.
When it is difficult to get all of the required authorizations prior to implementation of the change []
[a]bove all, this indicates that there is a potential process safety culture issue that must be addressed.
Site management should not tolerate the startup of a change prior to obtaining the necessary
authorizations. CCPS, Guidelines for Management of Change for Process Safety, 2008.
MANAGEMENT OF CHANGE DID NOT IDENTIFY SIGNIFICANT HAZARDS
Installing block valves into a process where they previously did not exist is a significant process change that
needs careful safety analysis during the MOC review. But the Williams 2001 MOC review did not identify the
significant overpressure hazard introduced by the valves. Figure 15 highlights portions of the Williams MOC that
the CSB identified as ineffective assessment of the change presented by the new valves. These weaknesses
(1) The Williams MOC failed to identify or control the overpressure hazard. The MOC reviewers indicated that
the valves did not have to be car sealed open (Figure 15), which would have provided overpressure protection for
the reboilers. The option of using a car seal was the only specified overpressure protection method on the MOC
checklist, even though in this case installing pressure relief valves could be a better option. Nevertheless, the
MOC reviewers did not identify that the reboilers required overpressure protectionthrough either an open path
to a pressure relief device using a car sealed open valve, or by installing a pressure relief device on each reboiler;
The Williams Geismar MOC procedure states, the purpose of the MOC review process is to include a safety/health,
environmental, technical, mechanical, engineering, and operations review of the change. Changes shall be reviewed for impact
on safeguards, critical instrument systems, pressure relief systems, equipment inspection programs, operability of equipment,
constraints in currently approved process or mechanical design, and operating procedures.
The OSHA PSM and EPA RMP regulations do not specify that the purpose of the MOC is to identify and control hazards
introduced by the process change. Rather, the regulations specify that the impact of change on safety and health must be
considered. Industry guidance publications, as well as Williams internal MOC procedure, specify that MOCs should identify and
control hazards introduced by the change prior to startup.
OSHA PSM and EPA RMP regulations require MOCs prior to the change. See 29 C.F.R. 1910.119(l)(2) and 40 C.F.R.
68.75(b).
Plant data indicates the unit was shut down between January 4, 2001 and February 20, 2001. The valves were installed during
this period. The PSSR for the valves installation was performed on February 1, 2001, but the MOC was not initiated until March
2, 2001, and was not approved until April 6, 2001. OSHA PSM requires the MOC prior to implementing the change. See 29
C.F.R. 1910.119(l)(2).
Portion of the MOC performed by Williams for the installation of the valves on Reboilers A and B.
Yellow highlights indicate weaknesses in MOC analysis. Note: Image of document is poor quality.
Overpressure in equipment occurs when the
equipment is subjected to a pressure that exceeds a
pre-defined pressure limit, such as the maximum
allowable working pressure (MAWP). Such defined
pressure limits are used to prevent equipment
mechanical failure due to excess pressure. There
are several methods to protect equipment from
overpressure. One is the use of a pressure relief
valve. Pressure relief valves are designed to open
and relieve excess pressure by releasing process
fluids from equipment when the equipment reaches
a specified pressure set point. They are an active
control that requires no human activation to
Photo of a pressure relief valve
Overpressure protection can also be provided to
equipment by ensuring an open path to pressure
relief by a locked open block valve. Valves are
commonly locked open by using a car seal, a
mechanical device that physically locks a valve in
the open or closed position to prevent manipulation
by an unauthorized person. Car seals are
administrative controls that rely on human
operation. They can be more prone to failure than
Depiction of a Car Seali
i. Car seal depiction from Total Lockout Website. Car Seals.
http://www.totallockout.com/online-store/car-seals-2/ (accessed
November 19, 2015).
(2) The MOC reviewers incorrectly indicated that existing
operating procedures were adequate to account for the new
valves, even though there was no procedure specifically for
switching the propylene fractionator reboilers. The CSB
found that Williams Geismar had relied on its generic
procedure, last revised in 1996, to start up any reboiler
within the entire facility. Williams considered this generic
procedure applicable to start up the propylene fractionator
Reboiler B; however, Williams generic procedure was
based on the assumption that all reboilers had the process
fluid on the tube side of the reboiler (Figure 16), which was
not the configuration of the propylene fractionator Reboiler
B. As a result, attempting to use this generic procedure to
start up Reboiler B could be confusing to workers and could
result in initiating an overpressure scenario on the shell side
of Reboiler Ba pressure vessel that was not equipped
with a protective pressure relief device. A robust,
equipment-specific procedure detailing the steps to switch
the propylene fractionator reboilers should communicate the
importance of opening the process valves (cold side) before
opening the quench water valves (hot side), and should
communicate the importance of overpressure protection.
The MOC process is intended to triggerand should have
triggeredthe development of such a procedure: a
procedure that is equipment-specific and addresses the
hazards of the operation;
(3) The MOC reviewers improperly indicated that the
change did not require a Process Hazard Analysis (PHA), a
more robust hazard evaluation option performed at the
discretion of the MOC reviewers. The installation of the
valves introduced a serious overpressure hazard to the
reboilers, and a formal PHA would have been the best
opportunity to identify and control that hazard; and
(4) The MOC reviewers selected incorrect responses
regarding whether the new equipment met all applicable
codes and standards. Reviewers indicated either the valves
met all codes and standards, or that the question was not
applicable. The addition of the valves without ensuring
overpressure protection for the reboilers, however, does not
meet requirements within industry codes and standards by
the American Petroleum Institute (API), and the American
Society of Mechanical Engineers (ASME). 37
Louisiana has not adopted Section VIII of the ASME Boiler and Pressure Vessel Code; however, Williams Geismar specified in
site policy documents that they will follow the Codes requirements.
Schematic from the Williams Geismar Generic Reboiler Startup Procedure. This was the applicable
procedure to startup the propylene fractionator reboilers. Since the procedure uses the reverse of the
Reboiler B configuration, it can be confusing, and workers could initiate a high-pressure scenario on
the shell (process) side. Williams had not equipped this reboiler with a protective pressure relief
(PSSRs)
(MOC) are
review analyzes
hazards in the entire
affectedofby
ofasfield
Companies should conduct
groupcomprised of
thorough and effective PSSRs
before placing equipment in
experiences and different
areas of expertisecan
change. MOCs must be
The selected responses in the MOC checklist indicate that the reviewers
focused largely on managing documentation and maintenance requirements
for the new valves, such as needed process safety information updates and
inspection requirements, and not on how the addition of the valves could affect
the operability and safety of the overall process.
Not only does this focus-on-the-new-equipment-only approach to
conducting Management of Change not meet the intent of regulatory
requirements, 38 it can be dangerous. Williams introduced hazards that it did
not fully understand or control.
5.1.1.3 PRE-STARTUP SAFETY REVIEW WAS INEFFECTIVE
Following the installation of the propylene fractionator Reboiler A and
Reboiler B valves, Williams performed a Pre-Startup Safety Review (PSSR)
as required by process safety management regulations. 39 Conducting the
Williams PSSR required filling out a 21-question form. The CSB found that
Williams reviewers either did not answer or incorrectly answered key PSSR
process safety questions. Figure 17 shows a selection of these questions and
The Williams PSSR instructions directed the reviewer to Circle the
appropriate response. But each PSSR prompt question did not have a circled
answer in the completed and management-approved documentation. The
PSSR questions that Williams reviewers did not answer or answered
incorrectly were areas that played a direct role in the June 13, 2013 incident.
No response was given to the question, Has a process hazard analysis
been completed, recommendations resolved, and incorporated in
design as deemed appropriate? A PHA was not conducted, which
could have identified hazards introduced by the valves;
The OSHA PSM and EPA RMP regulations require that Management of Change procedures shall ensure that the impact of
change on safety and health is considered and addressed prior to the change. See 29 C.F.R. 1910.119(l)(2)(ii) and 40 C.F.R.
68.75(b)(2).
The OSHA Process Safety Management (PSM) regulation requires that [t]he employer shall perform a pre-startup safety review
for new facilities and for modified facilities when the modification is significant enough to require a change in the process safety
information. See 29 C.F.R. 1910.119(i)(1). The EPA RMP regulation requires that [t]he owner or operator shall perform a
pre-startup safety review for new stationary sources and for modified stationary sources when the modification is significant
enough to require a change in the process safety information. See 40 C.F.R. 68.77. Both regulations also state that the prestartup safety review shall confirm, safety, operating, maintenance, and emergency procedures are in place and are adequate.
No response was given to the questions regarding operator training, and PSSR reviewers incorrectly
answered yes to the questions Are all necessary operating procedures in place and current for safety,
environmental, operating, emergencies, maintenance and technical? and Are procedures available for
new and modified equipment? Operations personnel were not effectively trained and procedures were
not developed to address the new propylene fractionator reboiler startup requirements; and
No response was given to the question, PRVs [pressure relief valves] lined up and block valves car
sealed open? Pressure release systems in place and operational and traced where appropriate? The
company did not provide effective overpressure protection for the propylene fractionator reboilers.
When a company does not effectively implement its written safety management programssuch as only partially
completing the PSSR document and incorrectly answering some of the document questionsit indicates a
weakness in process safety culture (see Section 9.0). Managements approval of incomplete documentation can
lead to a culture of complacency and, therefore, subpar and incomplete process safety analyses. At a company
with a strong commitment to effectively implementing process safety management programs, everyonefrom the
front line worker to company executivesshould perceive incomplete documentation, such as this PSSR
document, as unacceptable.
Selection of responses on the checklist filled out during the PSSR performed following the 2001
reboiler valve installation. Several key process safety questions were not answered or were
[U]nauthorized shortcuts should not be tolerated, even if there are short-term benefits.[] In the
absence of [operational discipline], management personnel intentionally turn a blind eye toward
what workers do because they are only interested in achieving the desired results. CCPS, Conduct
of Operations and Operational Discipline, 2011.
Overpressure protection is an
essential safeguard for all
pressure vessels. PHA teams
must ensure that all pressure
vessels have effective
overpressure protection. At a
minimum, a pressure relief
device is a necessary
safeguard to protect process
equipment from overpressure
scenarios where internal
vessel pressure can exceed
design code limits.
5.2 PROCESS HAZARD ANALYSES
Both OSHA PSM and the EPA RMP regulations require covered facilities to
perform or revalidate a Process Hazard Analysis (PHA) at least every five years to
identify, evaluate, and control the hazards involved in the process. 40 Industry
good practice publications provide guidance on how to conduct effective PHAs. 41
Williams performed three PHAs following the installation of the valves on the
propylene fractionator reboilers. Williams did not sufficiently implement the
recommendations issued in those PHAs and did not effectively mitigate
overpressure hazards in the propylene fractionator reboilers. This section
analyzes the documented findings, recommendations, and actions taken pertaining
to the propylene fractionator reboilers following the three PHAs, which Williams
conducted in 2001, 2006, and 2011.
5.2.1 2001 PHA
Williams performed a PHA on the process area that included the propylene
fractionator reboilers in 2001the year Williams installed valves on the
propylene fractionator reboiler piping. The 2001 PHA evaluated possible
consequences of closing the propylene fractionator reboiler process valves when
they should be open. The PHA team did not identify reboiler overpressure as a
possible safety consequence. Instead, the team identified a low-severity process
upset. The CSB notes that an effective PHA should have identified the more
serious safety consequence of reboiler overpressure, as it is a typical potential
hazard for a pressure vessel.
The PHA team correctly identified that the piping and instrumentation diagrams
(P&IDs) did not show the new valves on the propylene fractionator reboilers. The
PHA team recommended updating the relevant P&ID (Figure 18). The CSB notes
that the P&ID update should have been required as part of the MOC process. In
addition, the PSSR process should have reviewed a marked-up version of the
P&ID showing the approved change. Such a review could have identified the
significant error with the engineering drawing.
29 C.F.R. 1910.119(e) and 40 C.F.R. 68.67(f).
See CCPS publications including Center for Chemical Process Safety (CCPS). Guidelines for Hazard Evaluation Procedures.
3rd ed.; John Wiley & Sons, Inc.: Hoboken, New Jersey, 2008 and Frank, Walter L. and Whittle, David K. Revalidating Process
Hazard Analyses. American Institute of Chemical Engineers: New York, New York, 2001.
Excerpt from Williams Geismar 2001 PHA. The
PHA recommended updating the applicable P&ID
to indicate the valves installed on the propylene
fractionator reboilers.
2006 PHA
During the 2006 review, the PHA team emphasized evaluating whether equipment had sufficient overpressure
protection. The PHA team identified that the propylene fractionator reboilers potentially dont have sufficient
relief capabilities could overpressurize equipment (Figure 19). As a result, the PHA team issued the following
Consider locking open at least one of the manual valves associated with each of the
propylene fractionator reboilers (EA-425 A/B) so that the relief valves on top of the
propylene fractionator can provide thermal relief protection for these reboilers.
This 2006 PHA recommendation was marked Complete more than three years later in January 2010 in
Williams action item tracking system. This action item, however, was not implemented as the PHA team had
intended. The CSB found that only the shell-side outlet valve of the operating reboiler was car sealed open. The
shell-side valves of the standby reboiler remained closed, with no car seals on the manual valves and no protective
pressure relief device installed on the shell. This configuration isolated the standby reboiler from the relief device
on top of the propylene fractionator, creating a high-risk scenario. This was an implementation error of the PHA
recommendation. But as discussed in Section 5.2.2.1, the error remained unidentified because key process safety
programs (i.e. MOC and PSSR), which could have identified the implementation error, were not performed.
The CSB found that the contracted PHA facilitator was under the incorrect impression that both propylene
fractionator reboilers operated at the same time. The CSB was not able to determine why the PHA team did not
discuss that in practice only one reboiler operated at a time. This incorrect assumption likely contributed to the
PHA team choosing car seals as the recommended overpressure protection strategy, as the shell-side valves would
PHA action items addresses
the original safety concerns
identified by the PHA team.
Companies should ensure
that action items have been
field verified before closing
have to be open for both reboilers to operate. With the knowledge of the current
practicethat only one reboiler operated at a timea recommendation to car seal
open both the operating and standby reboilers would be atypical; the standby
reboiler would thus not be operating, but still open to the process and filled with
process liquid. While unusual, this was a low corrosive and minimally fouling
environment, and such a configuration would likely not harm equipment. This
configuration, however, would have left an unnecessary inventory of hazardous
chemicals in the process. An inherent safety review should identify the opportunity
to minimize the hazardous chemical inventory by blinding the standby reboiler from
The CSB notes that pressure relief valves (active safeguards) are a more robust
safeguard compared to car seals (administrative safeguards), which are lower on the
hierarchy of controls (Section 6.0). Administrative controls such as car seal
programs fall low on the hierarchy of controls because of the many types of human
factors 42 that can reduce or eliminate their effectiveness. Misunderstanding of what
equipment to car seal in order to satisfy the 2006 PHA action item likely contributed
to only partial completion of the action item, resulting in only the active reboiler
being car sealed open. This misunderstanding likely stemmed from the fact it would
have been unusual to car seal open the standby reboiler, and the recommendation to
car seal open the standby reboiler was a result of confusion by the PHA team. Had
the 2006 PHA team instead recommended installing pressure relief valves on both
propylene fractionator reboilers, that action item would have been more difficult to
implement incorrectly, as the relief valves would be newly installed, fixed
Excerpt from Williams Geismar 2006 PHA. The PHA
recommended locking open at least one manual valve
on each of the propylene fractionator reboilers to allow
for thermal relief protection of the reboilers.
Human factors are the environmental, organizational, or job factors, as well as a persons individual characteristics, which can
influence a persons actions in a way that can affect health and safety. See Health and Safety Executive (HSE), Reducing Error
and Influencing Behaviour, 2009, p 5. http://www.hse.gov.uk/pubns/priced/hsg48.pdf (accessed September 7, 2016).
MANAGEMENT OF CHANGE NOT PERFORMED FOR CAR SEAL INSTALLATION
The installation of a car seal to lock open a propylene fractionator reboiler process valveas recommended by
the 2006 PHAwas a significant process change that required an MOC and a PSSR. But Williams did not
perform an MOC or a PSSR for the installation of the car seal. 43 The field verification portion of the PSSR
should have provided an opportunity to identify that the PHA action item to car seal open a process valve on both
reboilers was not complete. Yet, the PSSR was never performed.
The CSB determined that Williams did not perform an MOC for the car seal installation likely because key
operations personnel did not understand that an MOC was required. Also, before the June 13, 2013 incident,
although prohibited by OSHA PSM regulatory requirements and company policies, at times Williams began
fieldwork on a process change without a completed and approved MOC.
The next PHA of the propylene fractionator was in 2011. This PHA relied on Williams action item tracking
system and MOC database to identify changes made to the process since the last PHA. The Williams PHA action
item tracking system incorrectly indicated as complete the 2006 recommendation to lock open at least one of
the manual process valves on each reboiler. Therefore, the PHA facilitator documented as safeguards in the 2011
spreadsheet that valves on both reboilers were car sealed open to provide relief protection (Figure 20). Williams
did not perform a field verification of the documented safeguards as part of the PHA. As a result, they did not
identify the discrepancy between documentation and the actual equipment installed in the field.
Excerpt from Williams Geismar 2011 PHA. The PHA
recommended updating the propylene fractionator P&ID to
show that the reboilers were car sealed open.
Performing an MOC and PSSR for this type of process change was required by OSHA PSM, EPA RMP Regulation, and by the
Williams Geismar internal site policy on Management of Change.
Relying on erroneous documentation that the outlet valve for each propylene fractionator reboiler was car sealed
open, the 2011 PHA team identified that the applicable P&ID did not show the car seals. Therefore, the PHA
team recommended updating the relevant P&ID (Figure 20):
Update P&ID 8F to indicate that one manual valve associated with each propylene
fractionator reboiler (EA-425 A/B) is car sealed open to ensure that the relief valves on top
of the propylene fractionator provide thermal relief protection for the reboilers.
In a May 2012 email, the Engineering Records Coordinator communicated to the PSM Coordinator that
[a]ccording to the car seal list only the in service exchanger is to be car sealed open. I will put a note on the P&ID
to reflect this. The Engineering Records Coordinator added a note to the applicable P&ID:
The in service EA-425A/B Exchangers 18 block valve will be tagged (CSO) in the
field to insure that the reboiler gets thermal protection from SV-421QA/QB. 44
This P&ID change did not address the full intent of the recommendation issued in the 2011 PHA because the
standby reboiler valve was not car sealed open. Williams management, however, approved this recommendation as
complete without verifying that the recommendation was implemented as intended. The PSM Coordinator tracked
the status of the 2011 PHA recommendation as Complete in the PHA action item tracking spreadsheet, and did
not include the additional emailed information provided by the Engineering Records Coordinator in the PHA action
item tracking documentation.
Williams did not perform an MOC and PSSR for the installation of the car seal on the in-service propylene
fractionator reboiler (see Section 5.2.2.1). Effectively performing these process safety programs could have
identified that both reboilers required car seals and ensured accurate process safety information.
More than ever before, companies recognize that insufficient control of changes plays a major role in
accidents. Experience has demonstrated that inadvertent, unintended, erroneous, or poorly performed
changes changes whose risk is not properly understood can result in catastrophic fires, explosions, or
toxic releases. CCPS, Guidelines for Management of Change for Process Safety, 2008
CSO is an acronym for car sealed open. SV-421QA/QB is the tag number for the pressure relief valves on top of the
propylene fractionator.
Operating procedures need
sufficient detail to ensure
effective performance of
critical steps, including
performing steps in the
correct order. Affected
employees such as operators
must receive training on the
procedures. Management
must establish expectations
5.3 LACK OF HAZARD ANALYSIS AND OPERATING PROCEDURE
[T]reating procedures as if they were equipment (just like a pump, valve,
reactor, or safety system), is fundamental for building a successful Process
Safety Management system. Who would start up a new process without all
of the pumps in place and tested? What craftsperson would tackle a pump
seal replacement without the required tools and parts? By accepting this
idea, that procedures are components, the [concept of requiring effective
procedures] will naturally fall into place. CCPS, Guidelines for Writing
Effective Operating and Maintenance Procedures, 1996
On the day of the incident, a decreasing quench water flow through the propylene
fractionator reboiler (Reboiler A) prompted the operations supervisor to enter the
process unit to evaluate the cause of the decreased flow. During this evaluation,
evidence indicates that the operations supervisor likely opened the quench water
valves (hot side) on the standby reboiler (Reboiler B) while its shell-side process
valves (cold side) remained closed, initiating the overpressure event. Prior to
manipulating valves in the field, Williams did not conduct a hazard analysis and
develop a procedure for the operations activity. 45 The CSB could not conclusively
determine the reason for opening these valves.
As demonstrated by this incident, it can be hazardous to conduct field operations
both to personnel performing the operation and to personnel working in the
vicinitywithout first establishing procedures and evaluating and controlling
hazards. As fouling in the quench water system was a known historical issue,
Williams should have developed a procedure prior to the day of the incident
detailing the method to assess the quench water system to identify the fouled heat
exchanger. Furthermore, Williams could have better managed the heat exchanger
fouling by establishing a routine maintenance schedule to take off-line and clean
this equipment, which was known to foul, prior to the occurrence of any process
OSHA issued a Willful violation to Williams, with a proposed fine of $70,000, for not developing and implementing written
operating procedures that provide clear instructions for safely conducting activities This citation was contested by Williams,
and was ultimately reduced to a Serious violation with a fine of $7,000. This resulted in a total fine amount of $36,000 for the
violations identified by OSHA following the incident. (OSHA Inspection Number 915682).
Detailed written procedures can ensure that operations activities are safe and hazards are effectively controlled.
In its book Guidelines for Writing Effective Operating and Maintenance Procedures, the Center for Chemical
Process Safety (CCPS) states:
Procedures should identify the hazards presented by the process. Procedures
should also state precautions necessary to prevent accidental chemical
release, exposure, and injury. Process safety information is an important
known hazards are addressed properly. 46
When a process condition requires operator activity in the field, such as opening or closing valves, these operation
activities can present hazards to workers. Before starting such field operations, a companys process safety
management system should ensure a procedure is developed and a thorough hazard evaluation is performed to identify
RELIEF VALVE ENGINEERING ANALYSIS
The ASME Boiler and Pressure Vessel Code requires that all pressure vessels shall be provided with overpressure
protection []. 47 Williams contracted an engineering services firm to perform a relief valve engineering analysis of
the Williams Geismar facility in 2008 to ensure the valves were properly sized for the equipment they were designed
to protect. The analysis identified that the propylene fractionator reboilers did not have sufficient overpressure
protection. A finding listed in the contractors analysis states:
There are block valves at the inlet and outlet to the shell side of [the propylene fractionator
reboilers]. Because those valves are not [car sealed open], [the propylene fractionator relief
valves] will not provide overpressure protection to the shell side of the reboilers in the
event of a fire or in the event of liquid expanding/vaporizing due to heat input from the hot
side. Unless these valves are car sealed open, additional overpressure protection will be
needed for the shell side of [the propylene fractionator reboilers].
The engineer who performed the relief valve engineering analysis also directly emailed a Williams project
engineer, alerting him of the lack of overpressure protection on the reboilers, and indicating the two options to
provide overpressure protection to the reboilers. Figure 21 shows her email.
The CSB learned that Williams did not develop an action item to address this relief valve engineering analysis for
the propylene fractionator reboilers. Williams determined their existing plan to car seal open both reboilers, from
the recommendation in the 2006 PHA, would address the hazard. Because the company did not fully implement
the 2006 PHA action item, this overpressure hazard remained unmitigated (see Section 5.2.2.).
Center for Chemical Process Safety (CCPS). Guidelines for Writing Effective Operating and Maintenance Procedures; American
Institute of Chemical Engineers: New York, New York, 1996; p 18.
American Society of Mechanical Engineers. ASME Boiler and Pressure Vessel Code, 2015. Section VIII, Division 1, UG-125.
Email from engineering services firm engineer to Williams employee alerting that the propylene fractionator
reboilers were not protected from overpressure. In figure, SV-421QA/QB are the propylene fractionator relief
valves. DA-406 is the propylene fractionator column. EA-425A/B are the propylene fractionator reboilers.
PHA and MOC teams should
effectively use the hierarchy
of controls to the greatest
extent feasible when
evaluating safeguards.
Pressure relief devices are
safeguards than car seals.
Pressure relief devices (active
safeguards) are higher on the
hierarchy of controls than car
seals (administrative
The Hierarchy of Controls 48 is a method to provide effective risk reduction by
applying, in order of robustness, inherently safer design, passive safeguards,
active safeguards, and procedural safeguards (Figure 22). 49 This strategy
promotes a tiered or hierarchical approach to risk management. The higher in
the hierarchy, the more effective the risk reduction achieved. Applying the
hierarchy of controls at the design phase is the best opportunity to ensure that
process hazards are properly analyzed and risks are effectively reduced, before
the design is implemented in the field. After the design phase, when
construction is complete and the process is operating, process safety
management programs such as MOC and PHA are important opportunities to
apply the hierarchy of controls to further reduce risk throughout the life of a
Hierarchy of Controls. The higher in the hierarchy (further to the left), the more
effective the risk reduction achieved.
Williams did not effectively use the hierarchy of controls in the 2001 design
change that added block valves to the propylene fractionator reboilers.
Williams also missed key opportunities in its 2001, 2006, and 2011 PHAs to
implement the hierarchy of controls when analyzing the risk of overpressure for
the propylene fractionator reboilers. 50 Instead of applying inherently safer
design, passive safeguards, or active safeguardsdesign strategies that are
higher on the hierarchy of controlsWilliams relied upon administrative
controls to mitigate a serious overpressure hazard.
The use of a pressure relief valve is an Active Safeguarda safeguard that
requires a specific device to function when needed. Car seals, the safeguard
chosen by Williams to provide a path to pressure relief for the reboilers, are
The CSB describes the concept of the Hierarchy of Controls in several previous investigation reports. See the CSB final reports
on the Tesoro Anacortes Refinery investigation, the Chevron Richmond Refinery investigation, and Key Lessons for Preventing
Incidents from Flammable Chemicals in Educational Demonstrations. (accessed August 17, 2016)
Center for Chemical Process Safety (CCPS). Inherently Safer Chemical Processes A Life Cycle Approach. 2nd ed.; John Wiley
& Sons, Inc.: Hoboken, New Jersey, 2009; Section 2.1.
As a result of its investigation of the 2012 Chevron refinery pipe rupture and fire in Richmond, California, the CSB recommended
that the State of California update its process safety regulations to require the use of the hierarchy of controls in establishing
safeguards for identified process hazards.
Procedural Safeguards, also known as Administrative Controls. Procedural safeguards require an action by a
person, and are lower on the hierarchy of controls than active safeguards because of the many types of human
factors that can reduce or eliminate their effectiveness.
During the 2011 PHA, Williams correctly identified the high potential severity from equipment rupture, but
incorrectly assessed the likelihood of an overpressure incident (see severity (S) and likelihood (L) rating in Figure
20). The 2011 PHA team categorized the likelihood of a propylene fractionator reboiler overpressurization as
improbable. Such a low frequency indicates a weak evaluation and poor understanding of the availability of
procedural safeguards such as car seals.
CCPS Layer of Protection Analysis guidance suggests that users consider pressure relief valves to have 99 percent
availability, 51 while car seal availability is only 90 percent. 52 Therefore, installing a pressure relief valve on the
shell side of each propylene fractionator reboiler, the design strategy Williams applied post-incident, is a more
robust approach to reduce the likelihood of an overpressure event than the use of car seals, an administrative
control that is more prone to failure, and in fact did fail in this case.
Administrative controls provide another safeguard or layer of protection, but should not be relied on
in lieu of practical engineered controls. Administrative approaches that require human action can
increase the likelihood of human error. CCPS, A Practical Approach to Hazard Identification for
Operations and Maintenance Workers, 2010
CCPS provides a value of 0.01 as the generic probability of failure on demand for spring-operated pressure relief valves. See
Center for Chemical Process Safety (CCPS). Guidelines for Initiating Events and Independent Protection Layers in Layer of
Protection Analysis; Center for Chemical Process Safety / American Institute of Chemical Engineers: New York, New York,
2014; p 180.
CCPS provides a value of 0.1 as the generic probability of failure on demand for adjustable movement-limiting devices such as
car seals. See Center for Chemical Process Safety (CCPS). Guidelines for Initiating Events and Independent Protection Layers
in Layer of Protection Analysis; Center for Chemical Process Safety / American Institute of Chemical Engineers: New York, New
York, 2014; p 260.
The American Petroleum Institute (API), the American Society of Mechanical Engineers (ASME), and The
National Board of Boiler and Pressure Vessel Inspectors develop codes and standards that detail requirements and
recommended practices for overpressure protection of pressure vessels.
API is an industry trade association that develops standards and recommended
practices for the oil and natural gas industry. These publications apply to
petrochemical facilities, including the Williams Geismar Olefins Plant. At the
time of the June 13, 2013 incident, the fifth edition (2007) of the API Standard
521, Pressure-Relieving and Depressuring Systems (API 521-2007) was the
recognized and generally accepted good engineering practice (RAGAGEP) for
pressure relieving and disposal systems.
API 521-2007 divided guidelines into four main sections: causes of
overpressure, determination of individual relieving rates, selection of disposal
systems, and disposal systems. The CSB identifies below weaknesses and
ambiguities in the causes of overpressure guidelines.
API 521-2007 does not specifically address the hierarchy of controls; however, the standard does address the use
of administrative controls and recommends the user apply good engineering judgment or sound engineering
judgment. 53 API 521-2007 provides guidance regarding inadvertent closure of a manual block valve on the
outlet of an on-stream pressure vessel, which is applicable to the valves on the Williams propylene fractionator
reboilers. The guidance presents users with a choice between two seemingly equivalent options: either install a
pressure relief device or develop an administrative control. The API 521-2007 guidance states:
The inadvertent closure of a manual block valve on the outlet of a pressure vessel while
the equipment is on stream can expose the vessel to a pressure that exceeds the maximum
allowable working pressure. If closure of an outlet-block valve can result in overpressure,
a pressure-relief device is required unless administrative controls are in place.54
The API 521-2007 guidance cautions the user that catastrophic failure can occur when relying on administrative
control, but the guidance is vague:
If the pressure resulting from the failure of administrative controls can exceed the corrected
hydrotest pressure 55 [], reliance on administrative controls as the sole means to prevent
overpressure might not be appropriate. The user is cautioned that some systems can have
unacceptable risk due to failure of administrative controls and resulting consequences due
API does not define good engineering judgment or sound engineering judgment; however, it is generally taken to mean that
users should apply their engineering knowledge when developing a qualitative basis for a design using the standard.
API Standard 521, 5th ed. Pressure-relieving and Depressuring Systems, January 2007, section 4.3.2.
API defines corrected hydrotest pressure as hydrostatic test pressure multiplied by the ratio of stress value at design temperature
to the stress value at test temperature.
to loss of containment. In these cases, limiting the overpressure to the normally allowable
overpressure can be more appropriate. 56
Given the design of the Williams propylene fractionator reboilers, it was possible to exceed the corrected
hydrotest pressure. (The maximum allowable working pressure was 300 psig, and the hydrostatic test pressure
was 450 psig. Metallurgical analysis indicates the reboiler shell exceeded this pressure during the event, failing at
a pressure of at least 674 psig.) 57 The email shown in Figure 21 provides evidence that the API 521-2007
approach was applied during the relief valve engineering analysis at Williams. The engineering analysis
performed on the propylene fractionator reboilers resulted in a choice between either installing car seals or adding
pressure relief devices. Williams selected the car seal approach.
In January 2014, seven months after the Williams incident, API published a new (Sixth) edition of API Standard
521, Pressure-relieving and Depressuring Systems (API 521-2014). The new version of the standard has
significant improvements that address the gaps and ambiguities in API 521-2007 that contributed to the Williams
incident. As shown below, when evaluating situations like the propylene fractionator reboilers at Williams, API
521-2014 requires a pressure relief device, prohibits reliance on administrative controls, and highlights the
importance of the hierarchy of controls.
The inadvertent closure of a valve on the outlet of pressure equipment while the equipment
is on stream can expose the equipment to a pressure that exceeds the MAWP. Every valve
(i.e. manual, control, or remotely operated) should be considered as being subject to
inadvertent operation. If closure of an outlet valve can result in pressure in excess of that
allowed by the design code, a PRD [pressure relief device] is required. 58 (emphasis added)
In the case of a manual valve, administrative controls can be used to prevent the closed
outlet scenario unless the resulting pressure exceeds the maximum allowed by the pressure
design code []. 59
A hierarchy of measures should be used to ensure equipment is not subject to excess
pressure. Such a hierarchy first involves avoiding or reducing risks, then providing
engineering controls, and finally providing administrative controls. Avoiding risks
includes, for example, setting the MAWP of the equipment above the maximum pressure
of all possible sources. Engineering controls include providing pressure relief on the
vessel. Administrative controls include provision of block valves of the locked-open
design. The user is cautioned that some systems may have unacceptable risk due to failure
of administrative controls and resulting consequences due to loss of containment. 60
Although API 521-2014 made significant safety improvements that address API 521-2007 weaknesses revealed
by the Williams incident, additional gaps still exist. For example, in one area of the standard that addresses
hydraulic (thermal) expansion, the requirement to use a relief valve is not restated, and the language indicates that
See Metallurgical Evaluation of Williams Olefins Ruptured Reboiler EA-425B in Appendix C.
API Standard 521, 6th ed. Pressure-relieving and Depressuring Systems, January 2014, section 4.4.2.1.
API Standard 521, 6th ed. Pressure-relieving and Depressuring Systems, January 2014, section 4.2.1.
administrative controls may be relied upon when a relief valve is not installed on a heat exchangereven when
the corrected hydrotest pressure can be exceeded.
[C]losing the cold-fluid block valves on the exchanger unit should be controlled by
administrative procedures and possibly the addition of signs stipulating the proper venting
and draining procedures when shutting down and blocking in. Such cases are acceptable
and do not compromise the safety of personnel or equipment, but the designer is cautioned
to review each case carefully before deciding that a relieving device based on hydraulic
expansion is not warranted because the corrected hydrotest pressure could be exceeded if
the administrative procedures are not followed. 61
This language contradicts the language in the standard requiring a pressure relief device for scenarios that develop
pressure greater than allowed by the design code. API should further enhance this standard to help prevent
overpressurization incidents caused by failure of administrative controls by clearly requiring a pressure relief
device for overpressure scenarios that can result in pressure greater than allowed by the design code.
The American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel
Code, Section VIII, provides requirements for pressure vessel construction,
inspection, and testing, including requirements for overpressure protection. Section
UG-135 Installation details the requirements for placement of pressure relief
devices on pressure vessels. UG-135 directs users to Nonmandatory Appendix M
for guidance on placement of stop (block) valves between a pressure vessel and its
relief device. Nonmandatory Appendix M, Section M-5.7, states that, Stop
valve(s), excluding remotely operated valves and process control valves, may be
provided in the relief path where there is normally a process flow [...]. 62
In order to install a block valve in the path between a vessel and its pressure relief device, the appendix specifies
management system and design guidance. In situations where the closure of the stop (block) valve could
overpressure a vessel, the appendix allows the user to apply administrative controls, mechanical locking
elements, valve failure controls, and valve operation controls[.] 63 While Louisiana has not adopted the ASME
Boiler and Pressure Vessel Code, Section VIII, Williams Geismar has chosen to comply with the Codes
requirements. The CSB encourages all companies to follow the more robust pressure relief requirements in API
521-2014 that require a relief device if the overpressure scenario can result in pressure greater than allowed by the
API Standard 521, 6th ed. Pressure-relieving and Depressuring Systems, January 2014, section 4.4.12.1.
American Society of Mechanical Engineers. ASME Boiler and Pressure Vessel Code, 2015. Section VIII, Division 1,
Nonmandatory Appendix M, Section M-5.7.
The National Board Inspection Code (NBIC), developed by the National Board of Boiler and Pressure Vessel
Inspectors, provides rules for installation, inspection, repair, and alteration of pressure vessels. Part 1, Section 4.5
Pressure Relief Devices details requirements for placement of pressure relief devices on pressure vessels. 64
Section 4.5.3 Location states:
The pressure relief device shall be installed directly on the
pressure vessel, unless the source of pressure is external to the
vessel and is under such positive control that the pressure cannot
exceed the maximum overpressure permitted by the original code
of construction and the pressure relief device cannot be isolated
from the vessel, except as permitted by NBIC Part 1, 4.5.6 e)2). 65
[W]hen necessary for the continuous operation of processing
equipment a full area stop valve between a pressure vessel and
its pressure relief device should be provided for inspection and
repair purposes only. 66 (emphasis added)
At Williams, because the source of overpressuring the reboilers was internal to the vessel (i.e. hot quench water
flowing through the vessel could cause the vessel to overpressure), the NBIC requires installing the pressure relief
device directly on the vessel. The design of the Williams reboilers did not meet this design requirement.
Louisiana, however, has not adopted this portion of the NBIC and Williams did not list the NBIC as a standard it
would voluntarily follow.
Previous versions of the NBIC had similar requirements as the 2015 version.
The National Board of Boiler and Pressure Vessel Inspectors. National Board Inspection Code, 2015. Part 1-Installation, Section
4.5.6, e2.
Williams made positive changes to its Geismar facility process safety management programs following the
incident. Williams personnel told the CSB that a significant cultural shift occurred after the incident in
understanding the importance of process safety programs in key areas where weaknesses contributed to the
incident. The following sections detail some improvements that Williams Geismar implemented following the
NEW REBOILER DESIGN
Following the June 13, 2013 incident, Williams redesigned the propylene fractionator reboilers to include a
pressure relief valve on the shell side of each reboiler (Figure 23). Discussed in Section 6.0, this design strategy
of using pressure relief valves, categorized as active safeguards, is higher on the hierarchy of controls than using
administrative controls, such as a car seals. This practice also aligns with guidance published by the American
Petroleum Institute in API 521-2014 (see Section 7.0), which cautions the user that failure of administrative
overpressure protection controls can lead to unacceptable risks. The Williams post-incident design also aligns
with guidance published by the NBIC, which requires a pressure relief device installed directly on the reboiler.
Post-incident, the Williams Geismar facility added pressure relief valves to the shell side of Reboiler A and
Reboiler B.
IMPROVED MANAGEMENT OF CHANGE PROCESS
Before the incident, the Williams Geismar MOC reviews occurred in a sequential process, one person at a time,
where the MOC document passed from reviewer to reviewera process that often occurred while the reviewers
remained in their offices. Following the incident, Williams changed its MOC review to a more collaborative
process, requiring an MOC Review Team to review every MOC in a group setting. Williams Geismar
personnel informed the CSB that this new MOC process facilitates better identification of hazards introduced by
proposed changes. An improved MOC process could have helped improve the hazard identification and
evaluation process conducted in the 2001 MOC for the installation of the block valves on the propylene
fractionator reboilers. A Williams technical employee described to the CSB the new MOC process:
Pre-incident, an MOC was written, it was brought to [the PSM coordinator] for a number,
it was put in a green folder, and it was passed from desk to desk or mailbox to mailbox. It
was a fairly long process. If you had questions, youd have to go track down who had seen
that MOC so far and ask them those questions. [] Oftentimes that would result in a doloop. Youd ask them a question, theyd answer it, that would spar off another question.
Now [after the incident], by having everybody just come and sit around a table and discuss
the MOC at once, if I ask you a question and you answer it, everyone else around the table
that may have the same question hears that answer. And they dont ask the same question,
but it may spur another question. So I think we have a lot of really good conversation by
having that process in place. It also makes it a lot easier to have broader employee
involvement, because every department has to be represented.
Because by having everybody sit around the table and everybody look at the form and
discuss it at once, the [MOC] process doesnt take place in a vacuum. Its very transparent
and very open and a very collaborative process. And so you do have some level of hazard
analysis that takes place right there at that MOC review team meeting. And if it looks like
were getting to the point of actually conducting a semi-HAZOP, then we can say, no, lets
refer this now to a PHA and lets do a full-blown HAZOP on [the proposed change]. But
I definitely think you get a much better hazard review in that collaborative [MOC] process.
The CCPS book Guidelines for the Management of Change for Process Safety also advises readers that the teambased MOC approach can be a more effective MOC approach for identifying the potential safety and health
effects of a proposed change (Figure 24). 67
Center for Chemical Process Safety (CCPS). Guidelines for the Management of Change for Process Safety; John Wiley & Sons,
Inc.: Hoboken, New Jersey, 2008; p 157.
CCPS book Guidelines for the Management of Change for Process Safety suggests a team-based review can
benefit MOC processes by more effectively identifying and controlling important health and safety impacts.
Following the incident, Williams Geismar identified methods to communicate the types of changes that require
an MOC. Also, Williams personnel informed the CSB that workers have an increased focus in ensuring MOCs
are complete before fieldwork begins. Williams began facilitating this verification by sending around a plantwide email to communicate MOC approval. If implemented effectively, these cultural and procedural changes
can strengthen process safety management at the Williams Geismar facility. The CSB recommends to Williams
several processes to ensure that these positive changes continue (Sections 9.0 and 12.0).
IMPROVED PHA ACTION ITEM IMPLEMENTATION PROCESS
Before the incident, the Williams Geismar PHA procedure did not specify a method to follow when the leadership
team decided to reject a PHA recommendation or deviate from the proposed recommendation language.
Identifying this gap after the incident, Williams Geismar updated the Geismar PHA procedure accordingly
(Figure 25), requiring a more robust process when deviating from the proposed PHA recommendation.
The Williams Geismar
revised, post-incident PHA
procedure now specifies a
method the leadership team
must follow to implement
The post-incident procedure change highlighted in Figure 25 reflects good practice guidance presented in the
CCPS book Guidelines for Process Safety Documentation:
Resolution [of PHA recommendations] is not synonymous with
adoption; not all recommendations will eventually be implemented as
originally proposed. Circumstances change, some recommendations
may ultimately be seen to be inappropriate, or a better means of
achieving the same results may become known. [] In any event, the
method of final resolution of recommendations should be documented,
either in the summary report, in an addendum to the report, or in a
separate follow-up report. The rationale for not implementing the
recommendation as originally proposed, as well as any alternative
course of action intended to achieve the objective, should be clearly
documented. 68
This new procedure can aid management when implementing action items differently than originally recommended
by the PHA team.
Williams has also increased emphasis on verifying proper completion of PHA action items. Before the incident,
simply communicating to the PSM Coordinator, who tracks action items, was sufficient to close an action. This
practice led to the ineffective implementation of an action item to install car seals on both propylene fractionator
reboilers, and it prevented Williams Geismar from identifying that an MOC was not conducted for the change.
Now, more enhanced closure verification requirements associated with PHA action itemsfor example the MOC
and PSSR documentationlink to the PHA action item tracking system. This approach can more effectively
verify PSM element completion.
Williams also developed a new field verification requirement to ensure accuracy of all P&IDs associated with
each PHA before conducting the PHA. 69 If effectively implemented, this practice can help to ensure accurate
process safety information prior to conducting the PHA.
NEW DEFINITIONS FOR STANDBY AND OUT-OF-SERVICE EQUIPMENT
Before the incident, the differences in definitions and pressure relief requirements for standby and out-ofservice equipment likely were not fully understood by all Williams personnel. When Williams implemented the
2006 PHA action item to car seal open the reboiler shell-side valves, only the active reboiler outlet valve was car
sealed open. Prior to the incident, some Williams personnel may have believed that standby equipment, such as
the standby propylene fractionator reboiler, did not require overpressure protection because they perceived it as
out-of-service. To clarify these definitions and prevent future misunderstandings, after the incident Williams
Geismar developed definitions for the two categories. The company now emphasizes these definitions in training
and in operating procedures to ensure standby equipment has adequate overpressure protection:
Center for Chemical Process Safety. Guidelines for Process Safety Documentation; American Institute of Chemical Engineers:
New York, New York, 1995; pp 102-103.
Williams has not developed a procedure for this practice.
Standby Equipment is a term used to describe equipment available for active service with
a minimum of interaction and under the control of the operations group [through] normal
operating procedures. Pressure relief protection is required and is available without further
interaction by operators.
Out-of-Service Equipment is a term used for positive isolation of a piece of equipment
from active service. This is accomplished when isolation is complete and the process fluids
have been emptied. At this point relief protection is not needed.
Williams more clearly specified pressure relief requirements for Standby and Out-of-Service equipment
internally; however, the CSB found little industry guidance on the definitions and pressure relief requirements
for the two categories of inactive equipment. API Standard 521, Pressure-relieving and Depressuring
Systems is the applicable industry standard to provide guidance on pressure relief requirements for standby
versus out-of-service equipment. The CSB found that this industry standard defined neither standby
equipment nor out-of-service equipment. In addition, pressure relief requirements for these classifications of
equipment are not explicitly stated. API can improve the clarity of overpressure protection requirements by
defining these terms and stating whether overpressure protection is required for each classification.
Since the incident, Williams Geismar improved information provided to operators during an event that may
require troubleshooting, such as when a process alarm activates. Now, when board operators get an alarm on
the distributed control system (DCS), they can right-click on the alarm and display troubleshooting guidance.
The guidance includes directions on what to check in the field, what the field operators should look for, and
the consequences of improper field actions. This information is also in the standard operating procedures, and
operators receive training on this information. A Williams Geismar technical employee informed the CSB,
Although troubleshooting is still kind of beyond the standard operating procedure, I think [this new practice]
gives us a more disciplined set of guidelines, and it gives the operators [better] access to that guidance.
Good process safety
metrics will reinforce a
promoting a belief that
process safety incidents are
preventable, that
and that policies and
and will be followed.i By
process safety metrics,
weaknesses in a companys
program can be identified.
Finding these weaknesses
and taking proactive steps to
improve upon them can help
to strengthen safety culture
and prevent process safety
i. Center for Chemical Process Safety
(CCPS). Guidelines for Process Safety
Metrics; John Wiley & Sons, Inc.:
Hoboken, New Jersey, 2010; p 30.
8.6 IMPROVED FOCUS ON LEADING AND LAGGING INDICATORS
In recent years, both industry and the CSB have published guidance and conducted
forums emphasizing the importance of collecting and analyzing leading 70 and
lagging 71 indicators (metrics) to help prevent process safety incidents. 72 The CSB
conducted a 2012 public hearing and issued a recommendation to API to develop a
consensus standard defining performance indicators for process safety for use in the
refining and petrochemical industry. (In response, API developed API RP 754,
Process Safety Performance Indicators for the Refining and Petrochemical
Industries.) The CCPS book Guidelines for Process Safety Metrics describes the
purpose of process safety metrics succinctly:
Process safety metrics are critical indicators for
evaluating a process safety management systems
performance. More than one metric and more than one
type of metric are needed to monitor performance of a
process safety management system. A comprehensive
process safety management system should contain a
variety of metrics that monitor different dimensions of the
system and the performance of all critical elements [].
Good process safety metrics will reinforce a process
safety culture promoting a belief that process safety
incidents are preventable, that improvement is
continuous, and that policies and procedures are
necessary and will be followed. Continuous improvement
is necessary and any improvement program must be
based on measureable elements.
continuously improve performance, organizations must
develop, implement, and review effective process safety
metrics. 73
Leading Indicators can help to predict future performance. API RP 754 provides leading indicator examples, including process
hazard evaluations completion, process safety action item closure, training completed on schedule, procedures current and
accurate, and MOC and PSSR compliance. See API Recommended Practice 754, 2nd ed. Process Safety Performance Indicators
for the Refining and Petrochemical Industries, April 2016, Section 8.3.
Lagging Indicators are retrospective, based on incidents that have occurred. API RP 754 provides lagging indicator examples,
including number of recordable injuries, loss of containment incidents, and pressure relief device discharge events. See API
Recommended Practice 754, 2nd ed. Process Safety Performance Indicators for the Refining and Petrochemical Industries, April
2016, Section 5.2.2 and Section 6.2.2.
Publications and events include (1) CSB Public Hearing: Safety Performance Indicators, July 23-24, 2012, Houston, Texas,
http://www.csb.gov/events/csb-public-hearing-safety-performance-indicators/ (accessed August 17, 2016); (2) U.S. Chemical
Safety and Hazard Investigation Board, Refinery Explosion and Fire, BP Texas City, REPORT NO. 2005-04-I-TX, (March
2007); (3) API Recommended Practice 754, 1st ed., Process Safety Performance Indicators for the Refining and Petrochemical
Industries, April 2010; (4) International Association of Oil & Gas Producers Recommended Practice, Process Safety Recommended Practice on Key Performance Indicators, Report No. 456, November 2011; (5) Center for Chemical Process Safety
(CCPS). Guidelines for Process Safety Metrics; John Wiley & Sons, Inc.: Hoboken, New Jersey, 2010; among others.
Center for Chemical Process Safety (CCPS). Guidelines for Process Safety Metrics; John Wiley & Sons, Inc.: Hoboken, New
Jersey, 2010; p 30.
Williams Geismar did not effectively measure leading and
lagging process safety indicators before the incident. Such
a system could have identified the excessive time it was
taking to implement PHA action items. For example, it
took three and a half years to close the 2006 PHA action
item to car seal open the propylene fractionator reboiler
valves. Since the incident, Williams worked to develop a
leading and lagging process safety metrics system. For
example, Williams Geismar increased its focus on incident
and near miss 74 reporting, and these events are now valued
as learning opportunities. Williams distributes incident
and near miss reports to all facility leads, supervisors,
engineers, and managers. In addition, the company now
investigates high potential near miss incidents using a root
cause methodology. Williams began performing statistical
analyses on the incidents reported, and the trends and
findings are distributed each month to Williams
employees and senior managers (Figure 26). Williams
also implemented electronic tools and databases to track
PHA action items and preventive maintenance items
with the ability to report overdue items or upcoming due
dates for action items to management.
Sample indicators report circulated to Williams
Geismar management.
These efforts are just the beginning in the development of a robust leading and lagging process safety indicators
program. CCPS developed example leading and lagging indicators that facilities can use in all areas of process
safety management. Figure 27 shows an example list of indicators for Management of Change published by
CCPS. 75 Williams Geismar should expand its existing indicators program to ensure all facets of its process safety
management systems, including MOC, PSSR, PHAs, and operating procedures, are effective.
CCPS defines a near miss incident as The description of less severe incidents (i.e., below the threshold for inclusion in a lagging
metric), or unsafe conditions that activated one or more layers of protection. Although these events are actual events (i.e., a
lagging metric), they are generally considered to be a good indicator of conditions that could ultimately lead to a severe
incident. Center for Chemical Process Safety (CCPS). Guidelines for Process Safety Metrics; John Wiley & Sons, Inc.:
Hoboken, New Jersey, 2010; p xvii.
Table from Center for Chemical Process Safety (CCPS). Guidelines for Process Safety Metrics; John Wiley & Sons, Inc.:
Hoboken, New Jersey, 2010; p 152.
Example MOC indicators published in the CCPS book Guidelines for Process Safety Metrics
PROCESS SAFETY MANAGEMENT PROGRAM ASSESSMENTS
Conducting in-depth assessments of a facilitys process safety management program is another way to proactively
identify weaknesses in process safety programs including MOC, PSSR, PHA, and operating procedure programs.
These assessments go beyond the requirements of the OSHA PSM Compliance Auditwhich only requires basic
compliance with the OSHA PSM regulationto evaluate the quality of each process safety management program
and the quality of implementation of those programs. Such an evaluation requires detailed analyses of historical
process safety management documentation, including MOC and PSSR forms, PHA recommendations, PHA
action item tracking systems, and written operating procedures. Process safety management program assessments
that analyze a high percentage of historical process safety documentation can be used to identify systemic safety
management program failures.
The CSB found that process safety management program deficiencies spanning the 12 years leading to the
incident were causal to the June 13, 2013 Williams Geismar reboiler rupture and fire. A robust process safety
management program assessmentthat analyzes years of historical process safety documentationshould be
instituted by Williams to identify past safety management deficiencies that could cause future process safety
incidents. To drive continual improvement, the CSB recommends to Williams Geismar to conduct such process
safety program assessments at least once every three years.
Managements Obligations
organizations commitment to implement
effective safety management programs and
company expectations (i.e., operational
discipline) by:
Requiring the collection of key
performance indicators for process
safety and regularly reviewing them;
Setting process safety performance
expectations and providing the resources
Looking for management system failures
as root causes for incidents;
Consistently identifying and correcting
substandard actions or conditions during
field walkthroughs;
Completing management reviews and
approvals related to work activities in a
Holding everyone (including
themselves) accountable for
commitments and ensuring that issues
are resolved in a timely manner;
Ensuring adequate staffing to operate
units safely; and
Ensuring adequate funding to maintain
equipment and safety systems in good
These are examples from the CCPS book
Conduct of Operations and Operational
DisciplineFor Improving Process Safety
in Industry, 2011, p 5.
A sequence of process safety management deficiencies resulting
in unmitigated hazards often precedes serious process safety
incidents such as the June 13, 2013 Williams Geismar incident.
Additionally, incidents often initiate when existing system gaps
coincide with actions at the front line, where workers may not
recognize the underlying hazards. To prevent process incidents,
organizations must develop a culture that promotes effective
In recent years, the chemical process industry has increasingly
focused on process safety culture (safety culture). An
organizations safety culture is determined by the quality of its
written safety management programs (e.g., process safety
management procedures, including PHA, MOC, PSSR, operating
procedures; written corporate policies) and the quality of
implementing those programs by individuals in the organization,
ranging from the CEO to the field operator. The Center for
Chemical Process Safety has labeled these two facets as Conduct
of Operations and Operational Discipline, respectively. 76
In the years leading up to the incident, Williams Geismar
exhibited characteristics of a weak process safety culture. The
weaknesses below contributed to the June 13, 2013 incident,
reflecting both deficiencies in and poor implementation of the
existing process safety management system:
(1) Williams did not perform the 2001 MOC until after the plant
was operating with the valves installed, and the associated
PSSR was incomplete. These actions did not comply with
facility (and regulatory) safety management system
requirements; however, Williams management accepted both
of these practices;
(2) Car seals are low-level, administrative controls, but they were
the favored safeguard in the 2006 PHA recommendation to
prevent overpressure events. Williams Geismar did not have a
policy requiring the effectiveness of safeguards to be analyzed;
(3) Williams Geismar did not follow OSHA PSM regulatory
requirements that operations activities have an associated
procedure to safely conduct the work. For example, Williams
did not create a procedure specifically for switching the
propylene fractionator reboilers Such a procedure should have
alerted the operations personnel of the overpressure hazard;
Center for Chemical Process Safety (CCPS). Conduct of Operations and Operational DisciplineFor Improving Process Safety
in Industry; John Wiley & Sons, Inc.: Hoboken, New Jersey, 2011, pp 6-7.
It is essential to maintain a
high level of vigilance when
management programs. Only
partially or ineffectively
conducting elements of PSM
programs such as MOCs,
PSSRs, PHAs, safeguard
evaluations, and procedure
development programs can
cause significant hazards to
be overlooked, and this can
lead to catastrophic incidents,
(4) The Williams PHA policy did not require effective action item resolution
and verification, resulting in incorrect action item implementation in the
(5) The Williams PHA policy did not require PHA teams to effectively evaluate
and control risk; and
(6) Operations personnel had informal authorization to manipulate field
equipment as part of assessing process deviations without first conducting a
hazard evaluation and developing a procedure.
Lessons from the Williams Geismar incident have broad application to other
organizations. The deficiencies listed above highlight that both a strong written
safety management system and effective implementation of that system are
required to have good process safety performance. Lessons to consider include:
(1) Ensure company standards always meet or exceed regulations, industry
codes and standards, and best practices;
(2) Verify the facility complies with company standards and procedures
through activities such as performing audits and tracking indicators; and
(3) Assess and strengthen the organizational safety culture including the
organizations commitment to process safety. 77
Item (3) above can be the most challenging to measure and to identify action
items to improve performance. Areas to consider include:
(1) Leaders create culture by what they pay attention to. Is management, from
the top down, engaged in process safety? Do leaders require proof of safety
rather than proof of danger?
(2) Does the organization have a reporting culture? Is reporting of incidents,
near misses, and unsafe conditions encouraged? Can personnel report such
occurrences without fear of retaliation? Does the company / site proactively
investigate worker safety concerns and implement timely and effective
(3) Does the organization encourage a learning culture? Does it examine
incidents outside of the organization? Does it apply relevant lessons
broadly across the organization?
(4) Are employees effectively involved in process safety decisions? Before
making decisions, is there an open and collaborative process to evaluate
Process safety refers to strategies to prevent chemical releases, fires, and explosions through process design and process safety
(5) Are members of the organization overconfident, or do they maintain a healthy sense of
vulnerability regarding safety? Are employees susceptible to normalization of deviance? 78
In its book Guidelines for Risk Based Process Safety, the Center for Chemical Process Safety provides example
methods a facility can employ to improve its process safety culture. These include:
(1) Establish process safety as a core value;
(2) Provide strong leadership [for process safety];
(3) Establish and enforce high standards of [process safety] performance;
(4) Maintain a sense of vulnerability;
(5) Empower individuals to successfully fulfill their process safety
(6) Defer to expertise;
(7) Ensure open and effective communications;
(8) Establish a questioning / learning environment;
(9) Foster mutual trust;
(10) Provide timely response to process safety issues and concerns; and
(11) Provide continuous monitoring of [process safety] performance. 79
Another tool to evaluate a facilitys safety culture is the use of anonymous safety culture assessments of staff.
These assessments have historically been conducted by surveying a sites employees through multiple-choice
questionnaires. Facilities may also use qualitative assessment practices that go beyond simple employee
questionnaire surveys. Such safety culture assessments include personnel interviews, focus group discussions,
and detailed document analyses. With qualitative assessments, workers interact with auditors, using their own
terms and concepts to express their point of view. [I]ntensive and in-depth information can be obtained using
the [workers] own language. 80
Normalization of deviance is the acceptance of events that are not supposed to happen. Objective outside observers view the
given situation as abnormal or deviant, whereas those individuals on the inside become accustomed to it and view it as normal
and acceptable. See Vaughan, Diane. Interview with ConsultingNewsLine, May 2008,
http://www.consultingnewsline.com/Info/Vie%20du%20Conseil/Le%20Consultant%20du%20mois/Diane%20Vaughan%20%28
English%29.html (accessed August 17, 2016).
Center for Chemical Process Safety (CCPS). Guidelines for Risk Based Process Safety; John Wiley & Sons, Inc.: Hoboken, New
Jersey, 2007; pp 39-66.
Wiegmann, Douglas A.; Zhang, Hui; von Thaden, Terry L.; Sharma, Gunjan; Gibbons, Alyssa Mitchell. Safety Culture: An
Integrative Review. The International Journal of Aviation Psychology, 2004, Vol 14, No 2, pp 117-134.
Guidance published in recent years describes how to conduct safety culture assessments of chemical process
facilities. In 2011, Contra Costa County in California published a guidance document on conducting safety
culture assessments. 81 Also in 2011, CCPS released the second edition of its book Guidelines for Auditing
Process Safety Management Systems. Chapter four of this book provides detailed guidance for auditors
evaluating an organizations safety culture. 82 Such safety culture assessments are an additional tool for
understanding the overall commitment to process safety at a facility, and facilities can use findings from the
assessment to develop action items to continually improve the facilitys approach to safety. The CSB
recommends that Williams begin implementing a process safety culture continual improvement programusing
safety culture assessmentsas another tool to improve overall safety at its Geismar facility.
Achieving and sustaining a positive [safety] culture is not a discreet event, but a journey.
Organisations should never let their guard down. Healthy safety cultures result in high reliability
organisations which are characterized by their chronic sense of unease. Organisations must ensure
that senior management are committed to a journey of continuous improvement. International
Association of Oil & Gas Producers, A Guide to Selecting Appropriate Tools to Improve HSE Culture,
Contra Costa Health Services. Industrial Safety Ordinance Guidance Document, Section F-Safety Culture Assessments; June 15,
2011. http://cchealth.org/hazmat/iso/guidance.php (accessed August 17, 2016).
Center for Chemical Process Safety (CCPS). Guidelines for Auditing Process Safety Management Systems; John Wiley & Sons,
Inc.: Hoboken, New Jersey, 2011; pp 181-211.
Overpressure protection is an essential safeguard for all pressure vessels. PHA teams must ensure that all
pressure vessels have effective overpressure protection. At a minimum, a pressure relief device is a
necessary safeguard to protect process equipment from overpressure scenarios where internal vessel pressure
can exceed design code limits.
Closed gate (block) valves leak, and they are susceptible to inadvertent opening. Both scenarios can
introduce process fluids to offline equipment. More robust isolation methods, such as inserting a blind, can
better protect offline equipment from accumulation of process fluid.
It is important to ensure that the final implementation of PHA action items addresses the original safety
concerns identified by the PHA team. Companies should ensure that action items have been effectively
implemented and field verified before closing them out.
Robust Management of Change (MOC) practices are needed to ensure the review analyzes hazards in the
entire process affected by the change. Similar to PHAs, conducting MOC reviews as a multidisciplinary
groupcomposed of individuals with different experiences and different areas of expertisecan assist in
identifying hazards introduced by a process change. Companies must conduct MOCs before implementing a
change in the field, and should not treat them as a paperwork or check-the-box exercise.
Pre-Startup Safety Reviews (PSSRs) are key opportunities to verify effective implementation of design
intent, accuracy of process safety information, and proper installation and configuration of field equipment.
Companies should conduct thorough and effective PSSRs before placing equipment in service.
Operating procedures need sufficient detail to ensure effective performance of critical steps, including
performing steps in the correct order. Affected employees such as operators must receive training on the
procedures. Management must establish expectations to maintain and follow accurate procedures.
PHA and MOC teams should effectively use the hierarchy of controls to the greatest extent feasible when
evaluating safeguards. Pressure relief devices are typically more robust safeguards than car seals. Pressure
relief devices (active safeguards) are higher on the hierarchy of controls than car seals (administrative
Good process safety metrics will reinforce a process safety culture promoting a belief that process safety
incidents are preventable, that improvement is continuous, and that policies and procedures are necessary
and will be followed. 83 By measuring and analyzing process safety metrics, weaknesses in a companys
process safety management program can be identified. Finding these weaknesses and taking proactive steps
to improve upon them can help to strengthen safety culture and prevent process safety incidents.
It is essential to maintain a high level of vigilance when implementing process safety management programs.
Only partially or ineffectively conducting elements of PSM programs such as MOCs, PSSRs, PHAs,
safeguard evaluations, and procedure development programs can cause significant hazards to be overlooked,
and this can lead to catastrophic incidents, sometimes years later.
In the years leading up to the June 13, 2013 incident, significant weaknesses in the Williams Geismar process
safety culture were evident in a series of deficiencies in implementing the sites process safety management
programs and in weaknesses in the written programs themselves. These deficiencies include a poorly conducted
MOC and PSSR, ineffective safeguard selections and insufficient safeguard evaluation requirements, poor
implementation of PHA action items, inadequate focus on developing and maintaining operating procedures, and
allowing uncontrolled field equipment manipulations without first assessing the hazards and developing a
procedure. Those deficiencies ultimately contributed to the reboiler rupture and the deaths of two employees.
This incident highlights that maintaining process safety excellence at a facility requires consistent and organized
effort by a company and its employees. Former CSB Chairperson John Bresland called on companies to strive for
process safety excellence when he stated, Operating hazard[ous] chemical plants need to have the highest level
of chemical process safety possible to make sure they operate safely day in and day out. It requires constant
diligence and constant attention to process safety management. 84
While Williams made safety improvements following the incident, the CSB has identified additional good
practices Williams Geismar should implement for further improvement. These strategies, including conducting
safety culture assessments, developing a robust indicators tracking program, and conducting detailed process
safety program assessments, can aid in maintaining a consistent focus on process safety.
The CSB also identified gaps in industry guidance provided by the American Petroleum Institute (API). Postincident, API now requires relief devices for scenarios that generate pressure greater than what is allowed by the
equipment design code; however, the CSB found the API guidance remains inconsistent, as API still specifies in
some guidance that reliance on administrative controls is sufficient to prevent equipment from overpressuring. In
addition, the CSB found limited guidance from API on definitions and pressure relief requirements for standby
and out-of-service equipment. Further enhancing guidance in API publications can enable broader learning of the
lessons from the Williams incident. Applying these lessons industry-wide can prevent future catastrophic
Walter, Laura; CSB Issues Urgent Safety Recommendations Following CITGO Refinery Accident. EHS Today [Online] 2009.
http://ehstoday.com/safety/news/csb-issues-urgent-safety-recommendations-citgo-refinery-accident-1411 (accessed August 17,
12.1 WILLIAMS GEISMAR OLEFINS FACILITY
2013-03-I-LA-R1
Implement a continual improvement program to improve the process safety culture at the Williams
Geismar Olefins Plant. Ensure oversight of this program by a committee of Williams personnel
(committee) that, at a minimum, includes safety and health representative(s), Williams management
representative(s), and operations and maintenance workforce representative(s). Ensure the continual
improvement program contains the following elements:
a. Process Safety Culture Assessments. Engage a process safety culture subject-matter expert,
who is selected by the committee and is independent of the Geismar site, to administer a
periodic process safety culture assessment that includes surveys of personnel, interviews
with personnel, and document analysis. Consider the process safety culture audit guidance
provided in Chapter 4 of the CCPS book Guidelines for Auditing Process Safety
Management Systems as a starting point. Communicate the results of the Process Safety
Culture Assessment in a report; and
report developed from the Process Safety Culture Assessments, and (2) oversee the
development and effective implementation of action items to address process safety culture
issues identified in the Process Safety Culture Assessment report.
As a component of the process safety culture continual improvement program, include a focus on the
facilitys ability to comply with its internal process safety management program requirements. Make the
periodic process safety culture report available to the plant workforce. Conduct the process safety culture
assessments at least once every five years.
2013-03-I-LA-R2
Develop and implement a permanent process safety metrics program that tracks leading and lagging
process safety indicators. Consider available industry guidance, such as the guidance presented in the
Center for Chemical Process Safety (CCPS) book Guidelines for Process Safety Metrics and the example
metrics provided in the books accompanying CD. Design this metrics program to measure the
effectiveness of the Williams Geismar Olefins Facilitys process safety management programs. Include
the following components in this program:
Develop a system to drive continual process safety performance improvements based upon the data
identified and analysis developed as a result of implementing the permanent process safety metrics
2013-03-I-LA-R3
Develop and implement a program that demands robust and comprehensive assessments of the process
safety programs at the Williams Geismar facility, at a minimum including Management of Change, PreStartup Safety Review, Process Hazard Analyses, and Operating Procedures. Ensure that the assessments
thoroughly evaluate the effectiveness of these important safety programs. To drive continual
improvement of process safety programs to meet good practice guidance, ensure these assessments result
in the development and implementation of robust action items that address identified weaknesses.
Engage an expert independent of the Geismar site to lead these assessments at least once every three
12.2 AMERICAN PETROLEUM INSTITUTE
2013-03-I-LA-R4
To help prevent future major incidents such as a rupture of a pressure vessel in a special operating status,
strengthen API Standard 521, Pressure-relieving and Depressuring Systems, by defining the various types
of equipment operating statuses. Include definitions for standby and out-of-service. Specify pressure
relief requirements for each type of equipment operating status.
2013-03-I-LA-R5
To help prevent future major incidents such as pressure vessel rupture from ineffective or failed
administrative controls, clarify API Standard 521, Pressure-relieving and Depressuring Systems, to
require a pressure relief device for overpressure scenarios where internal vessel pressure can exceed what
is allowed by the design code. Although some portions of API Standard 521 already require a pressure
relief device for these scenarios, other areas, such as Section 4.4.12 Hydraulic Expansion, are not as
protective. Section 4.4.12 Hydraulic Expansion (the failure mode that caused the Williams overpressure
incident) permits omitting a pressure relief device and allows the exclusive use of administrative controls.
40 CFR Chapter 1, Subchapter C, Part 68 Chemical Accident Prevention Provisions.
American Society of Mechanical Engineers. ASME Boiler and Pressure Vessel Code, 2015. Section VIII,
API Recommended Practice 754, 2nd ed. Process Safety Performance Indicators for the Refining and
Petrochemical Industries, April 2016.
API Recommended Practice 572, 3rd ed., Inspection Practices for Pressure Vessels, November 2009.
API Standard 521, 5th Edition. Pressure-relieving and Depressuring Systems, January 2007.
API Standard 521, 6th Edition. Pressure-relieving and Depressuring Systems, January 2014.
API Standard 598, 9th ed. Valve Inspection and Testing, September 2009.
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Journal of Loss Prevention in the Process Industries, 2007, vol. 20, pp 194-206.
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Causal Analysis - AcciMap
CSB ANALYSIS OF LIKELY REBOILER FAILURE SCENARIO
Williams Geismar, LA Investigation
1.0 Summary ..66
2.0 Failure Scenarios Evaluated ...66
2.1 Overpressurization Due to Equilibrium Vapor Pressure at Quench Water Feed Temperature .67
2.2 Explosion Due to High Concentrations of Methyl Acetylene and Propadiene .68
2.3 Overpressurization Due to Liquid Thermal Expansion..69
3.0 Boiling Liquid Expanding Vapor Explosion (BLEVE).....72
On June 13, 2013, a propylene fractionator reboiler (Reboiler B) catastrophically ruptured, resulting in the
fatalities of two Williams employees. The reboiler had been offline, isolated from the propylene fractionator by a
single valve on the inlet piping and a single valve on the outlet piping, when hot water was introduced to the tube
side of the exchanger while the shell-side valves were still closed. Approximately three minutes after the tubeside hot water valves were opened, the reboiler ruptured. Post-incident analysis indicates the reboiler shell likely
failed at an internal pressure estimated to be between 674 and 1,212 psig. 85 The CSB determined that a pressure
of this magnitude was likely generated by liquid thermal expansion in the liquid-filled, Reboiler B shell. The
process liquid within the shell, which contained mostly propane with smaller amounts of propylene and C4
hydrocarbons, such as butane, likely entered the offline Reboiler B shell during the 16 months it was isolated
from the process by at least one of the following: (1) a leaking process valve; (2) a mistakenly opened process
valve; or, (3) another reason not identified. This report details the possible failure scenarios for the reboiler shell,
which the CSB evaluated.
2.0 FAILURE SCENARIOS EVALUATED
The following sections detail the CSBs analysis of possible propylene fractionator reboiler (Reboiler B) failure
scenarios. These include overpressurization due to an increase in the equilibrium vapor pressure as the reboiler
temperature increased, detonation due to an accumulation of methyl acetylene and propadiene (MAPD), and
vessel rupture due to liquid thermal expansion.
2.1 OVERPRESSURIZATION DUE TO EQUILIBRIUM VAPOR PRESSURE AT QUENCH
WATER FEED TEMPERATURE
Boiling Point Curve of Williams reboiler process fluid. Graph indicates process fluid could generate a
vapor pressure of 496 psig at equilibrium conditions.
The tube-side quench water was at a temperature of 187 F. At equilibrium conditions at 187 F, the shell-side
propane mixture generates a vapor pressure of approximately 496 psig (Figure B-1). This pressure is not high
enough to have ruptured the reboiler, which Finite Element Analysis predicts ruptured between 674 and 1,212
psig. 86 The CSB concludes that the overpressurization of the Williams reboiler was likely not caused by an
increase in vapor-liquid equilibrium pressure when heat was introduced to the closed shell side of the reboiler.
2.2 EXPLOSION DUE TO HIGH CONCENTRATIONS OF METHYL ACETYLENE AND
Mixtures of methyl acetylene and propadiene (MAPD) can decompose and ignite without the presence of oxygen,
resulting in an explosion inside of equipment that can violently rupture process vessels. Heat input to the mixture
could be sufficient to initiate the ignition of the materials.87 Experimental studies have found that hydrocarbon
mixtures containing approximately 60 mol% MAPD can sufficiently decompose and propagate a flame. 88
The CSB analyzed whether the decomposition and ignition of MAPD in the reboiler shell caused this incident.
Williams regularly sampled the MAPD composition exiting the propadiene converter, which was immediately
upstream of the propylene fractionator (Figure B-2). The propadiene converter was installed into the process
specifically to prevent accumulation of MAPD in the process. Plant data indicates the propadiene converter was
functioning normally between a February 2012 maintenance activity and the day of the incident. Between the
time Reboiler B was last opened for maintenance (February 2012) and the incident, available composition data
indicates that the process fluid entering the propylene fractionator did not exceed approximately 1.4 mol%
MAPD. This concentration likely was not enough to accumulate a high percentage of MAPD in the standby
reboiler, which was isolated from the propylene fractionator by closed valves.
In a 2013 presentation by Dow at the AIChE Ethylene Producers Conference, two scenarios were identified that
could result in accumulation of MAPD in a propylene fractionator: operating on total reflux or operating with a
loss of bottoms flow. 89 The propylene fractionator was not operated under either condition between February
2012 and the incident. The CSB concludes that this incident was likely not caused by the accumulation and
detonation of MAPD in the offline Reboiler B.
Simplified flow diagram of the olefins process. The propadiene converter and the propylene fractionator
Kuchta, J.M.; Spolan, I.; Zabetakis, M.G. Flammability Characteristics of Methylacetylene, Propadiene (Allene), and Propylene
Mixtures. Journal of Chemical and Engineering Data, 1964, Vol. 9, No. 3, 467-472.
Yoshimine, M.; Kern, W.G.; Belfit, R.W. Stabilization of Methylacetylene and Propadiene Mixtures. Journal of Chemical and
Engineering Data, 1967, Vol. 12, No. 3, 399-405.
Feld, Peter; MAPD Stability and Management in Ethylene Plants, 2013 AIChE Spring National Meeting; San Antonio, Texas;
May 1, 2013; AIChE Paper Number 111b.
OVERPRESSURIZATION DUE TO LIQUID THERMAL EXPANSION
Liquid expands as it is heated and has the ability to generate high pressures when the liquid is confined within a
closed vessel. Based on equipment dimensions and the physical properties of the design composition of the
propylene fractionator bottoms product, the CSB calculated the minimum quantity of process liquid required at
ambient temperature (approx. 77 F) to completely fill the propylene fractionator Reboiler B at the quench water
temperature (187 F). The following calculations were performed to determine the approximate quantity of liquid
process fluid required on the shell side of the Williams reboiler and in connected piping to result in a liquid
overpressurization of the reboiler shell.
Total Volume Available Between Closed Valves
= 289.93 3
Volume of Process Fluid Required to Fill Exchanger Shell at Quench Water Feed Temperature
Williams Propylene Fractionator Bottoms Design Case:
The density of this liquid was evaluated at two conditions using Aspen HYSYS, SRK equation of state:
(1) Ambient temperature (77F): ,77 = 30.89
(2) Quench water inlet temperature (187F): ,187 = 20.22
Mass of liquid required to fill shell side volume at 187F:
= ( ),187 = (289.93 3 ) 20.22
Volume this mass occupies at 77F:
,77 =
= 5,862.38
= 189.78 3
Percentage total volume occupied at 77F:
189.78 3
100 = 65.5 %
289.93 3
The piping and exchanger shell between the two closed reboiler process valves had to be at least 65.5 vol% full of
the liquid propane mixture prior to the introduction of hot quench water to the tube side of the reboiler for liquid
expansion to result in overpressurization of the exchanger shell and piping. A liquid inventory of at least this
minimum quantity of liquid is reasonable because (1) it would have resulted in a level in the reboiler below the
liquid level in the propylene fractionator, and (2) this quantity of liquid would have had enough contact with the
reboiler tubes to sufficiently heat and expand (Figure B-3). Reboiler B was likely between 65.5 vol% and 100
vol% full of the liquid propane mixture prior to the introduction of the 187 F quench water.
Depiction of minimum required liquid level in reboiler EA-425B (Reboiler B) to result in possible liquid
overpressurization of reboiler shell.
Pressure Rise Due to Liquid Thermal Expansion
The following equation was used to calculate the theoretical pressure that could be reached inside the Reboiler B
shell due to liquid thermal expansion of the propane mixture. The calculation assumed that the reboiler was
initially full of the liquid propane mixture.
Assuming negligible leakage across the shell-side valves during the three minutes between the introduction of hot
quench water and vessel failure: 90
(2 1 )( 3| )
2 is the final gauge pressure of blocked-in, liquid-full equipment, expressed in psig;
1 is the initial gauge pressure of blocked-in, liquid-full equipment, expressed in psig;
2 is the final temperature of blocked-in, liquid-full equipment, expressed in F;
1 is the initial temperature of blocked-in, liquid-full equipment, expressed in F;
is the cubic expansion coefficient of the liquid, expressed in 1/F;
| is the linear expansion coefficient of metal wall, expressed in 1/F;
is the isothermal compressibility coefficient of the liquid, express in 1/psi;
is the internal pipe diameter, expressed in inches;
is the modulus of elasticity for the metal wall at 2 , expressed in psi;
is the metal wall thickness, expressed in inches;
is Poissons ratio, typically 0.3.
This calculation finds that the pressure inside of the Reboiler B shell could reach approximately 5,000 psig due to
liquid thermal expansion of the propane mixture within the confined shell. Finite element analysis predicted the
reboiler failed at an internal pressure between 674 and 1,212 psig. 91 The pressure generated by liquid thermal
expansion would be sufficient to achieve this failure pressure. The CSB concludes that liquid thermal expansion
of the liquid-filled Reboiler B shell was the likely failure scenario that initiated the mechanical failure sequence
resulting in the boiling liquid expanding vapor explosion (BLEVE).
Equation from API Standard 521, 6th ed. Pressure-relieving and Depressuring Systems, January 2014, section 4.4.12.4.1.
3.0 BOILING LIQUID EXPANDING VAPOR EXPLOSION (BLEVE)
When the reboiler shell failed locally (cracked) due to liquid thermal expansion of the shell contents, the shell
contents began to flash near the failure opening and a two-phase (liquid and vapor) jet release would have
accelerated out of the failure opening. The two-phase flow would have choked in the failure opening, maintaining
the pressure in the vessel for a short period of time. The pressure loading on the open edges of the failure caused
the crack to continue to grow along the vessel length and the failure opening rapidly increased in size. As this
opening increased in size, the two-phase jet would have grown rapidly. At some point, the full opening of the
vessel would have resulted in an explosive release of the remaining vessel contents. This explosive release is
called a boiling liquid expanding vapor explosion (BLEVE). 92 The pressure forces during this process usually
flatten the vessel cylinder on the ground (Figure B-4). The escaping propane mixture then found an ignition
source and ignited.
Post-incident photo of Reboiler B shell. The originally cylindrical shell was flattened during the event.
The Metallurgical Analysis Report is on the CSB website on the
Williams Olefins Plant Explosion and Fire investigation page.
Members of the U.S. Chemical Safety and Hazard Investigation Board:
Vanessa Allen Sutherland, J.D.
Manuel Ehrlich
Kristen Kulinowski, Ph.D.
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