U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

INTERIM INVESTIGATION REPORT

CHEVRON RICHMOND REFINERY FIRE

CHEVRON RICHMOND REFINERY

RICHMOND, CALIFORNIA

AUGUST 6, 2012

KEY ISSUES

• INHERENTLY SAFER DESIGN

• DAMAGE MECHANISM HAZARD REVIEW

• EFFECTIVE ANALYSIS OF PROCESS SAFEGUARDS IN PROCESS HAZARD ANALYSIS
Chevron Richmond Refinery Interim Investigation Report April 2013

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Summary

On August 6, 2012, the Chevron U.S.A. Inc. Refinery in Richmond, California, experienced a 

catastrophic pipe failure in the #4 Crude Unit. The pipe ruptured, releasing flammable, hydrocarbon

process fluid which partially vaporized into a large vapor cloud that engulfed nineteen Chevron 

employees. All of the employees escaped, narrowly avoiding serious injury. The flammable portion of 

the vapor cloud ignited just over two minutes after the pipe ruptured. The ignition and subsequent 

continued burning of the hydrocarbon process fluid resulted in a large plume of unknown and 

unquantified particulates and vapor traveling across the Richmond, California, area. In the weeks 

following the incident, approximately 15,000 people from the surrounding area sought medical treatment 

due to the release. Testing commissioned by the U.S. Chemical Safety and Hazard Investigation Board 

(CSB) and the California Division of Occupational Safety and Health (Cal/OSHA) determined that the 

pipe failed due to thinning caused by sulfidation corrosion, a common damage mechanism in refineries. 

As a result of the incident, the Chevron Richmond Refinery crude unit remains out of commission over 

eight months later. In addition, Cal/OSHA issued the refinery 17 citations related to the incident and 

eight additional citations, with a total proposed fine of nearly one million dollars. In this interim report, 

the CSB is issuing recommendations to Chevron, the City of Richmond, Contra Costa County, 

Cal/OSHA, the State of California, and the U.S. Environmental Protection Agency, addressing the need 

for inherently safer design, rigorous and documented damage mechanism hazard reviews, and thorough 

analyses of process safeguards. 

This interim investigation report contains detailed analyses of and makes recommendations to Chevron 

and regulatory bodies at the local, state, and federal level. The CSB believes the findings and 

recommendations presented in this report can be applied to refineries, chemical plants, and other 

industries nationwide to improve process safety. 

The CSB plans to release a comprehensive Final Investigation Report later in 2013 that will include 

analyses and recommendations relating to technical and regulatory investigation findings which are not 

included in this interim report. The Final Investigation Report will cover topics including: the importance 

of having a competent, well-funded regulator and an adaptable regulatory regime; Chevron safety culture;

process safety indicator data collection and reporting; emergency planning and response; stop work 

authority; and recommendations for improvement of petroleum industry standards and recommended 

practices. Some of these issues are previewed at the end of this interim report under Additional Issues 

Currently Under Investigation.
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Table of Contents

Figures........................................................................................................................5

Acronyms and Abbreviations ....................................................................................6

Background and Findings..........................................................................................8

Sulfidation Corrosion...............................................................................................16

Sulfidation Corrosion Inspection Techniques..........................................................21

Chevron Sulfidation Corrosion Knowledge and Expertise .....................................24

Other Significant Sulfidation Occurrences..............................................................27

Process Hazard Analysis..........................................................................................31

Operational Changes................................................................................................33

Chevron Sulfidation Corrosion Inspection and Mitigation .....................................36

Inherently Safer Systems .........................................................................................40

Regulatory Oversight...............................................................................................46

Recommendations....................................................................................................53

Additional Issues Currently Under Investigation ....................................................59

Regulatory Oversight............................................................................................59

Emergency Planning and Reporting .....................................................................61

Emergency Response............................................................................................62

Safety Culture .......................................................................................................62

References................................................................................................................65
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Figures

Figure 1. The burned remains of the fire truck that was consumed by the fire.............................................9

Figure 2. Vapor cloud over Richmond area and smoke from Chevron Richmond Refinery fire ...............10

Figure 3. Initial vapor cloud formation and subsequent ignition................................................................11

Figure 4. C-1100 Crude Unit Atmospheric Column and Upstream Process Equipment............................12

Figure 5. Overhead view of the equipment in the #4 Crude Unit...............................................................13

Figure 6. 4-sidecut line configuration................................................................................14

Figure 7. Photo of rupture on 4-sidecut 52-inch component ......................................................................15

Figure 8. Graph showing how corrosion rates increase in carbon steel......................................................18

Figure 9. 4-sidecut piping sample ..............................................................................................................20

Figure 10. Modified McConomy Curves from API RP 939-C...................................................................23

Figure 11. Chevron’s key sulfidation events between 1974 and 2013. ......................................................24

Figure 12. Schematic of failed piping from the Chevron Salt Lake Refinery. ...........................................28

Figure 13. Failed piping component that resulted in the 2007 Richmond crude unit fire...........................29

Figure 14. Percentage increase of the sulfur content in the 4-sidecut.........................................................34

Figure 15. Key events at the Richmond refinery between 1998 and 2013. ................................................36

Figure 16. Hierarchy of controls.................................................................................................................41
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Acronyms and Abbreviations

ALARP As Low As Reasonably Practicable

API American Petroleum Institute

ASTM American Society for Testing and Materials

BIN Business Improvement Network

bpd Barrels Per Day

BPTC BP Texas City

CAA Clean Air Act

Cal/OSHA California Division of Occupational Safety and Health

CCPS Center for Chemical Process Safety

CCR California Code of Regulations

Chevron ETC Chevron Energy Technology Company

CML Condition Monitoring Locations

CSB U.S. Chemical Safety and Hazard Investigation Board

CSHO Compliance Safety and Health Officer

CWS Community Warning System

EPA Environmental Protection Agency

°F degree Fahrenheit

HSE Health and Safety Executive

ISO Industrial Safety Ordinance

ISS Inherently Safer Systems

IST Inherently Safer Technology

KPI Key Process Indicator
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LEPC Local Emergency Planning Committee

LOPA Layers of Protection Analysis

MOC Management of Change

NEP National Emphasis Program

OEM U.S. EPA Office of Emergency Management

OSHA Occupational Safety and Health Administration

P&P Policy and Procedures

PHA Process Hazard Analysis

PMI Positive Materials Identification

psig Pounds Per Square Inch Gauge

PSM Process Safety Management

RISO City of Richmond Industrial Safety Ordinance

RLOP Richmond Lube Oil Project

RMP Risk Management Plan

SIP Shelter-In-Place

TML Thickness Monitoring Location

UK United Kingdom

USW United Steelworker International Union

wt. % Weight Percent
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Background and Findings

1. On August 6, 2012, the Chevron U.S.A. Inc. Refinery in Richmond, California (Chevron 

Richmond Refinery), experienced a catastrophic pipe rupture in the #4 Crude Unit (crude unit).

The ruptured pipe released a flammable hydrocarbon process fluid which then partially 

vaporized into a large vapor cloud that engulfed nineteen Chevron U.S.A. Inc. (Chevron) 

employees. At 6:33 pm, approximately two minutes after the release, the flammable portion of 

the vapor cloud ignited.i

 i

Surveillance footage provided by Chevron. Chevron clarified to CSB that video time is approximately 5 minutes 

out of sync. The video can be found at 

Eighteen of the employees safely escaped from the cloud just before 

ignition; one employee, a firefighter, was inside a fire engine that caught fire when the vapor 

cloud ignited (Figure 1). Because he was wearing full body fire-fighting protective equipment, 

he was able to make his way to safety. Six Chevron employees suffered minor injuries during 

the incident and subsequent emergency response efforts.

http://www.csb.gov/videoroom/detail.aspx?VID=69 (accessed February 8, 

2013). 
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Figure 1. The burned remains of the fire truck that was consumed by the fire. A firefighter 

was in the cab when the vapor cloud ignited. The fire truck was positioned approximately 

65 feet from the leak location.
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2. The ignition and subsequent continued burning of the hydrocarbon process fluid resulted in a 

large plume of unknown and unquantified particulates and vapor traveling across the Richmond, 

California, area (Figures 2 and 3). This resulted in a Community Warning System (CWS) Level 

3 alert,

i

and a shelter-in-placeii (SIP) was issued at 6:38 pm1 for the cities of Richmond, San 

Pablo, and North Richmond. It was lifted later that night at 11:12 pm after the fire was fully 

under control. In the weeks following the incident, nearby medical facilities received over 

15,000 members of the public seeking treatment for ailments including breathing problems, 

chest pain, shortness of breath, sore throat, and headaches. Approximately 20 people were 

admitted to local hospitals as inpatients for treatment.

Figure 2. Vapor cloud (white) over Richmond area and smoke (black) from Chevron 

Richmond Refinery fire as seen from San Rafael in Marin County.

2

 i

A Community Warning System Level 3 alert indicates that a facility within Contra Costa County has had a release 

that has offsite impact and is categorized by any of the following:

1. Off-site impact that may cause eye, skin, nose and/or respiratory irritation to the general population.

2. Fire, explosion, heat, or smoke with an off-site impact. Example: On a process unit/storage tank where 

mutual aid is requested to mitigate the event and the fire will last longer than 15 minutes.

3. Hazardous material or fire incident where the incident commander or unified command, through 

consultation with the Contra Costa Health Services Hazardous Material Incident Response Team, requests 

that sirens should be sounded. 

See http://cchealth.org/hazmat/pdf/incident_notification_policy.pdf (accessed April 9, 2013). ii Contra Costa County considers a shelter-in-place to include going inside a home or nearest building, closing doors 

and windows, and turning off heating, ventilation, and air conditioning. See http://cchealth.org/emergencies/shelterin-place.php (accessed February 6, 2013). 
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Figure 3. Initial vapor cloud formation (white cloud) and subsequent ignition (black smoke)

as seen from a pier in San Francisco, California.

3. The incident occurred from the piping referred to as the “4-sidecut” stream, one of several 

process streams exiting the C-1100 Crude Unit Atmospheric Column (Figure 4).

i A plot plan of 

the crude unit shows the leak location relative to C-1100 (Figure 5). As shown in Figure 6, light 

gas oil (the crude unit 4-sidecut process fluid) exits the atmospheric column via a 20-inch nozzle

and is split into a 12-inch line and an 8-inch line. The August 6, 2012, pipe rupture (Figure 7)

occurred on a 52-inch long componentii of the 4-sidecut 8-inch line (the 52-inch component).

The line operated at a temperature of 640 degrees Fahrenheit (°F)iii

 i

The atmospheric column separates crude oil feed into different streams through distillation. These streams are 

further processed in other units in the refinery.

and had an operating 

pressure of approximately 55 pounds per square inch gauge (psig) at the rupture location. At the 

ii The term “component” refers to a portion of piping between welds or flanges. It includes straight run piping and 

pipe fittings. 

iii The auto-ignition temperature for this process, the temperature at which a material will combust in the presence of 

sufficient oxygen without an ignition source, was also 640 °F. This number is based on the Chevron Light Gas Oil 

Material Safety Data Sheet. Chemical testing of 4-sidecut samples following the incident indicated lower autoignition temperatures; however, these samples may not have been representative of typical 4-sidecut process fluid. 
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time of the incident, light gas oil was flowing through the 8-inch line at a rate of approximately 

10,800 barrels per day (bpd).

i

Figure 4. C-1100 Crude Unit Atmospheric Column and Upstream Process Equipment.

 i

This is the equivalent of 315 gallons per minute (gpm). A barrel equals 42 gallons. 
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Figure 5. Overhead view of the equipment in the #4 Crude Unit showing the leak location, commonly 

referred to as a plot plan.
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Figure 6. 4-sidecut line configuration and rupture location.

8-inch

4-sidecut line

12-inch

4-sidecut line

52-inch

component

Rupture

Location
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4. The CSB commissioned Anamet, Inc., a materials engineering and laboratory testing company, 

to conduct testing of the 4-sidecut pipe, including the failed 52-inch component. The testing 

concluded that the rupture was due to pipe wall thinning caused by sulfidation corrosion,

3

5. Anamet’s metallurgical analysis found that the 52-inch component where the rupture occurred 

had experienced extreme thinning; the average wall thickness near the rupture location was 

approximately 40 percent thinner than a dime

which 

is discussed below.

i

(the thinnest American coin). Between 1976 and 

2012, the 52-inch piping component had lost, on average, 90 percent of its original wall 

thickness in the area near the rupture. The piping had an initial nominal wall thickness of 0.322-

inchii when it was installed in 1976.

Figure 7. Photo of rupture on 4-sidecut 52-inch component.

 i

The U.S. Mint reports that a dime has a thickness of 1.35 mm, or 0.053 inches. Information can be found at 

http://www.usmint.gov/about_the_mint/?action=coin_specifications (accessed February 14, 2013). ii This portion of the 4-sidecut line was constructed of 8-inch Schedule 40 carbon steel piping. 
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Sulfidation Corrosion

6. Sulfidation corrosion is a damage mechanismithat is well understood in the refining industry.

The sulfidation corrosion industry guidance document, American Petroleum Institute (API)

Recommended Practice (RP) 939-C Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion 

Failures in Oil Refineriesii

[Sulfidation] ...is not a new phenomenon, but was first observed in the 

late 1800s in a pipe still (crude separation) unit, due to the naturally 

occurring sulfur compounds found in crude oil. When heated for 

separation, the various fractions in the crude were found to contain sulfur 

compounds that corroded the steel equipment.

notes:

4

7. Sulfidation corrosion, also known as sulfidic corrosion,

5 is a damage mechanism that causes 

thinning in iron-containing materials, such as steel, due to the reaction between sulfur

compounds and iron at temperatures ranging from 450 °F to 800 °F.

6 This damage mechanism 

causes pipe walls to gradually thin over time. Sulfidation corrosion is common in crude oil 

distillationiii where naturally occurring sulfur and sulfur compounds found in crude oil feed, such 

as hydrogen sulfide,

iv

8. The reaction between sulfur and iron produces a layer of iron sulfide scale

are available to react with steel piping and equipment. Process variables 

that affect corrosion rates include the total sulfur content of the oil, the sulfur species present, 

flow conditions, and the temperature of the system. Virtually all crude oil feeds contain sulfur 

compounds and, as a result, sulfidation corrosion is a damage mechanism present at every 

refinery that processes crude oil. Sulfidation corrosion can cause thinning to the point of pipe 

failure when not properly monitored and controlled. 

v on the inside surface 

of piping.

7

 i

Piping damage mechanisms are any type of deterioration encountered in the refining and chemical process industry 

that can result in flaws/defects that can affect the integrity of piping (e.g. corrosion, cracking, erosion, dents, and 

other mechanical, physical or chemical impacts). See API 570. "Piping Inspection Code: In-Service Inspection, 

Rating, Repair, and Alteration of Piping Systems." 3rd ed., Section 3.1.1.5, November 2009.

This reaction can be compared to that of oxygen and iron which also produces a 

scale, commonly known as rust. The type of scale formed by sulfidation corrosion is dependent 

upon the components contained in the steel. Certain scales formed are protective and actually

reduce the reaction rate between sulfur compounds and iron, minimizing sulfidation corrosion 

ii API RP 939-C is one of several relevant American Petroleum Institute recommended practices and standards under 

evaluation by the CSB as part of this investigation. To the casual observer API RP 939-C appears to obligate the 

industry to take significant actions. However, the CSB concluded it was written to be permissive so that industry 

compliance with specific provisions would not be required. The complete findings from this evaluation will be 

included in the CSB’s Final Report. 

iii Distillation separates mixtures into broad categories of its components by heating the mixture in a distillation 

column where different products boil off and are recovered at different temperatures. See 

http://www.eia.gov/todayinenergy/detail.cfm?id=6970 (accessed April 4, 2013).

iv Hydrogen sulfide is the most aggressive sulfur compound that causes sulfidation corrosion. v Scale is a nonmetallic layer on the surface of metals and is often a result of corrosion.
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rates. For instance, sulfidation corrosion affecting steel alloys containing greater than two

weight percent (wt. %) chromium produces a protective scale that inhibits the reaction between 

the iron and sulfur compounds, thereby reducing corrosion rates.i

 With increasing percentages 

of chromium, the reaction is further slowed, greatly diminishing corrosion rates.8,ii For example, 

stainless steel (an 18 wt. % chromium alloy) is nearly 15 times more resistant to sulfidation 

corrosion than 9-Chrome (a 9 wt. % chromium alloy).9 Conversely, sulfidation corrosion rates 

are significantly higher in steels containing very little chromium. Carbon steel, the Chevron 4-

sidecut line material of construction, was manufactured with a maximum concentration of 0.40 

% chromium.

10 The scale formed on carbon steel is less protective and allows continued 

reaction between the sulfur compounds and iron.11

9. In addition to its inherently faster rate of sulfidation corrosion when compared with higher 

chromium steels, carbon steel also experiences significant variation in corrosion rates due to 

variances in silicon content, a component used in the steel manufacturing process. Carbon steel 

piping containing silicon content less than 0.10 wt. % can corrode at accelerated rates,

 Thus, carbon steel corrodes at a rate that is 

significantly faster than other materials of construction, such as high chromium steels. 

12

 i

At greater than two wt. % chromium, sulfur compounds react with the steel to form FeCr2S4 scale. This scale 

provides more protection than the FeS scale that forms on carbon steel piping. See Niccolls, E. H., J. M. 

Stankiewicz, J. E. McLaughlin, and K. Yamamoto. "High Temperature Sulfidation Corrosion in Refining." 17th 

International Corrosion Congress. Las Vegas: NACE International, 2008.

up to 

sixteen times faster than carbon steel piping containing higher percentages of silicon as shown in 

Figure 8. This figure shows how carbon steel corrosion rates can greatly vary depending on 

silicon content. 

ii It has also been found that chromium “poisons” the decomposition of sulfur compounds to hydrogen sulfide which 

also slows down the sulfidation corrosion rate. See Couper, A.S. “High Temperature Mercaptan Corrosion of

Steels.” 19th Annual Conference of the National Association of Corrosion Engineers. Pages 396t-401t, New York: 

March 1963. 
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Figure 8. This graph shows how corrosion rates increase in carbon steel containing 

decreasing percentages of silicon. This information can be found in Annex C of API RP 939-

C.i

10. The refining industry has been aware of increased rates of sulfidation corrosion in low-silicon

carbon steel piping since as early as 1974,

 

13

Sulfidation corrosion has caused severe fires and fatalities in the refining 

industry, primarily because it causes corrosion over a relatively large 

area, so failures tend to involve ruptures or large leaks rather than 

pinhole leaks. It can be insidious in that moderately high corrosion rates 

can go undetected for years before failure. Finally, process changes that 

increase the temperature or sulfur content can creep up over time and 

nearly 40 years before the August 6, 2012, incident 

and two years before the Chevron crude unit was constructed. Prior to the incident, Chevron

documented its understanding of the significant consequences of sulfidation corrosion. This is 

reflected in Chevron’s Corrosion Prevention and Metallurgy Manual, which states:

 i

The y-axis of this figure is in units of mils per year (mpy). A “mil” is 1/1000 inch.

Silicon Content (Weight %) 
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multiply corrosion rates so that what was thought to be a low corrosion 

rate system becomes corrosive enough to fail before the increased 

corrosion rate is recognized.

11. Carbon steel piping is manufactured to meet certain specifications, including American Society 

for Testing and Materials (ASTM) A53B,

14 ASTM A106,15 and API 5L.16 ASTM A53B and 

API 5L do not contain minimum silicon content requirements for carbon steel piping,17

12. In the mid 1980s, pipe manufacturers began to simultaneously comply with all three 

manufacturing specifications (ASTM A53B, ASTM A106, and API 5L) when manufacturing 

carbon steel piping. The majority of carbon steel piping purchased following this time period 

likely has a minimum of 0.10 wt. % silicon content. However, piping purchased and installed 

prior to the mid-1980s could still contain low silicon components that are susceptible to high, 

variable sulfidation corrosion rates.

while 

ASTM A106 requires the piping to be manufactured with a minimum silicon content of 0.10 

wt. %. As a result, manufacturers have used different levels of silicon in the carbon steel pipe 

manufacturing process. Thus, depending on the manufacturing specification for carbon steel 

susceptible to sulfidation corrosion, corrosion rates could vary depending on the silicon content 

within the steel.

13. Over 95 percent of the 144 refineries in operation in the U.S., including the Chevron Richmond 

Refinery,

i

were built before 1985,

18

14. The Chevron Richmond Refinery 4-sidecut piping circuit containing the 52-inch component that 

failed was constructed of ASTM A53B carbon steel, which had no minimum specification for 

silicon content. Post-incident testing of samples of the 4-sidecut piping from the Chevron 

Richmond Refinery identified silicon content ranging from 0.01 wt. % to 0.2 wt. %. Of twelve 

samples taken from the 8-inch and 12-inch 4-sidecut line, six had a silicon concentration of less 

than 0.10 wt. %. The 52-inch pipe component that ruptured on the day of the incident had a 

silicon content of only 0.01 wt. %. The elbow component directly upstream of the 52-inch 

component that failed had a silicon concentration of 0.16 wt. % and showed considerably less 

thinning (Figure 9).

and thus before piping manufacturers began producing

carbon steel in compliance with all three manufacturing specifications. Therefore, the original 

carbon steel piping in these refineries is likely to contain varying percentages of silicon content

and may experience highly variable sulfidation corrosion rates.

 i

The Chevron Richmond Refinery was constructed in 1902.
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Figure 9. 4-sidecut piping sample (E-017-8) analyzed by Anamet Labs showing the relative 

thickness of low silicon piping on the left and the high silicon piping on the right. The 

ruptured pipe component (left) contained 0.01 % silicon and the upstream elbow component 

(right) contained 0.16 % silicon.19 The initial nominal thickness of this piping was 0.322-

inch.
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Sulfidation Corrosion Inspection Techniques

15. As evidenced by the chemical analysis performed on the Chevron 4-sidecut piping post-incident, 

carbon steel piping components within a single circuiti

can contain varying percentages of 

silicon, resulting in a large variation in sulfidation corrosion rates by component. Historically, 

sulfidation corrosion monitoring techniques required the measurement of pipe thickness at only 

a minimal number of permanent Condition Monitoring Locations (CMLs)ii along the piping. 

These CMLs are most frequently placed on elbows and fittings.

iii However, due to details of the 

manufacturing process, carbon steel pipe fittings generally contain high percentages of silicon.20

When measurements are only taken at high-silicon containing fittings, the measurements can fail 

to identify high corrosion rates within a pipe circuit caused by low-silicon components. At the 

Chevron Richmond Refinery, the 4-sidecut piping had a total of 24 CMLsiv

16. Determining silicon content in existing carbon steel piping and equipment in the field is a 

difficult undertaking. To properly characterize the silicon content in each component in a piping 

circuit, every component must be inspected. This is known as 100 percent component 

inspection. Two techniques are currently used to determine silicon content in existing carbon 

steel piping circuits with unknown chemical composition: performing chemical analysis and 

pipe wall thickness measurements of every component. 

on piping and 

fittings. The CSB found that there were no CMLs placed on the low silicon piping component 

that failed. Chevron identified accelerated corrosion in the 52-inch component in a 2002 

inspection. However, no CML was added to ensure future monitoring, and the 52-inch 

component was not inspected again. Instead, the CSB found that Chevron relied on inspection 

data gained primarily from high silicon pipe-fitting components, such as elbow components. 

This inspection data did not reflect the corrosion rates of the lower-silicon components of the 4-

sidecut piping. Relying on the limited inspection data from the CMLs on the high silicon 

components, Chevron management denied multiple recommendations to replace the 4-sidecut 

line. As illustrated by the Chevron incident, inspection techniques alone may not accurately 

identify the most aggressive corrosion rates throughout an entire circuit of carbon steel piping. 

Low-silicon components can remain uninspected and unidentified until failures such as the 

August 6, 2012, Chevron incident occur. As will be discussed below, upgrading metallurgy is a 

more effective means of managing sulfidation corrosion.

 i

A piping circuit is a length of pipe and the fittings associated with a particular process service that operate at

similar conditions. A circuit usually begins and ends at either a branch or a piece of process equipment such as a 

vessel or a pump. Reference to piping by circuits allows piping to be grouped conveniently by proximity and 

operating service. Piping circuits may also be referred to as piping runs. ii A condition monitoring location (CML) is a designated area where periodic thickness examinations are conducted. 

Each CML represents as many as four inspection locations located circumferentially around the pipe. CMLs are 

also referred to as thickness monitoring locations (TMLs). CML was historically referred to as corrosion monitoring 

locations (CMLs) and that terminology is sometimes still used within the industry. iii A fitting is a piping component usually associated with a change in direction or diameter. 

iv Many of these CMLs were added during the 2011 turnaround. 
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17. Many field-portable instruments used for positive material identification cannot adequately 

identify silicon content.21 If original manufacturing quality assurance datai

are not available, as 

is generally the case with older plants, then chemical verification requires destructive testing. 

Metal shavings must be taken from each carbon steel piping component for chemical analysis in 

a laboratory.22

18. Carbon steel components containing low concentrations of silicon can also potentially be 

identified by performing thickness measurements of every component within a carbon steel 

circuit.

This method requires that the insulation be removed for access to the piping so 

that each individual piping component can be sampled and verified.

23 This practice is only useful if the piping circuit has been exposed to sulfidation 

corrosion for a long enough time period so that variances in corrosion rate caused by differences 

in silicon content may be detected. Chemical analysis is therefore the most accurate technique 

to identify low-silicon carbon steel components. As with chemical analysis, the thickness 

measurement method requires that each individual piping component be identified by removing 

insulation (so every weld seam can be located), a time consuming and costly undertaking, or by 

using non-destructive examination techniques. Thickness measurements on high temperature 

piping typically can only be done accurately and safely during unit turnarounds.ii

19. API Recommended Practice 939-C Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion 

Failures in Oil Refineries describes the challenges faced when attempting to thoroughly inspect 

carbon steel lines susceptible to sulfidation corrosion. The recommended practice states that 

older ASTM A53 piping, such as the Chevron piping that failed on August 6th, creates a “major 

inspection challenge”

 Although 

these various methods were available to detect the location of the field welds, Chevron had not

used them to identify the 4-sidecut pipe segment locations. 

24 and that “unless the refinery is fortunate enough to have located an 

inspection point on that particular [low silicon] section of pipe or fitting, it is very difficult to 

detect the thinning component.”25 It states that in some applications, carbon steel will appear to 

be adequate based on measured corrosion rates until failure occurs at some undocumented or 

unidentified low-silicon component.26

20. Unlike silicon concentration, the chromium concentration of steel can easily be verified in the 

field using portable positive material identification instruments. In addition, steel alloys 

containing at least 9 wt. % chromium are more resistant to sulfidation corrosion and do not run 

the risk of extreme variations in corrosion rates within components in the same piping circuit.iii

 i

Manufacturing quality assurance data, also known as mill data, provides the chemical composition of the steel.

This makes alloys with higher chromium content an inherently safer choice in high temperature 

ii A “turnaround” is a scheduled shutdown of a process unit to perform maintenance, repairs, upgrades, and 

inspection of process equipment. 

iii The protective scale, FeCr2S4, begins to be the dominant scale formed in steels containing a chromium content of 

five wt. %. The 5Cr steel alloy can be manufactured to contain anywhere from 4% to 6% chromium. Thus, “the 

sulfidation corrosion rate can vary dramatically in 5Cr steels even in the same operating environment.” See 

Niccolls, E. H., J. M. Stankiewicz, J. E. McLaughlin, and K. Yamamoto. "High Temperature Sulfidation Corrosion 

in Refining." 17th International Corrosion Congress. Las Vegas: NACE International, 2008.
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23 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

sulfidation corrosion environments.

i As shown in the Modified McConomy Curvesii from API 

RP 939-C (Figure 10), 9-Chromeiii corrodes 15 times faster than stainless steel,

iv and carbon 

steelv corrodes 125 times faster than stainless steel.27

Figure 10. Modified McConomy Curves from API RP 939-C.

 i

Steels with higher chromium content are inherently safer than carbon steel with respect to sulfidation corrosion. 

However, analysis is still required to ensure that the best material of construction is selected. ii Modified McConomy Curves are the set of curves API RP 939-C uses to predict sulfidation corrosion rates versus 

temperature for several steel alloys.

iii 9-Chrome contains 9 wt. % chromium.

iv Stainless steel contains 18 wt. % chromium. v ASTM A53B carbon steel contains a maximum of 0.40 wt. % chromium.

100.0
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Chevron Sulfidation Corrosion Knowledge and Expertise

21. Figure 11 shows a timeline of Chevron’s key sulfidation events. Chevron technical staff has 

considerable knowledge and expertise regarding sulfidation corrosion, specifically with respect to 

corrosion rate variations caused by differing silicon concentration in carbon steel piping. Chevron 

employees have authored industry papers on sulfidation corrosion and had significant influence in 

the development of the industry sulfidation corrosion recommended practice, API RP 939-C. This 

recommended practice, first published in 2009, was developed under Chevron leadership. At the 

approximate time of publication of API RP 939-C, Chevron Energy Technology Company 

(Chevron ETC)i created an internal document on the subject of sulfidation corrosion. Chevron 

ETC metallurgists released a formal report dated September 30, 2009 (nearly 3 years prior to the 

incident) to Chevron refinery-based reliability managers and chief inspectors entitled Updated 

Inspection Strategies for Preventing Sulfidation Corrosion Failures in Chevron Refineries. 

Figure 11. Chevron’s key sulfidation events between 1974 and 2013.

 i

The Chevron Energy Technology Company is a separate business unit within the Chevron Corporation that 

provides technology solutions and technical expertise for Chevron operations worldwide. See 

http://richmond.chevron.com/home/aboutchevronrichmond.aspx (accessed April 4, 2013)
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22. Sulfidation experts acknowledged in the Chevron ETC report that, “Until now, Chevron has not 

directly addressed the risk of low Si[licon] carbon steel...”i

Sulfidation corrosion failures are not common in Chevron or in the 

industry but they are of great concern because of the comparatively high 

likelihood of blowout or catastrophic failure [...] . This can happen 

because corrosion occurs at a relatively uniform rate over a broad area so 

a pipe can get progressively thinner until it actually bursts rather than 

leaking at a pit or local thin area. In addition the process fluid is often 

above its autoignition temperature. The combination of these factors 

means that sulfidation corrosion failures frequently result in large fires. 

[...] [S]everal case histories of sulfidation corrosion failures that have 

occurred in Chevron or in the industry several of which are blowouts.

and that the report lays out a program 

that “seeks to close these gaps, and to maximize the effectiveness of our inspection.” The report 

clearly indicates that Chevron understood both the potential consequence and the high likelihood of 

a rupture or catastrophic failure from sulfidation corrosion and calls out Chevron’s need for action:

This Chevron ETC report specifically recommends that inspectors perform 100 percent component

inspection on high temperature carbon steel piping susceptible to sulfidation corrosion. However, 

this 100 percent component inspection program was not implemented at the Richmond refinery 

prior to the August 6, 2012 incident. The Chevron ETC report defines a priority ranking system to 

help focus the inspection implementation efforts. The process conditions of the 4-sidecut stream 

placed it in the highest priority for inspection.

23. Chevron ETC technical experts issued a corporate newsletter in 2010 that again warned of the 

potential consequence of sulfidation failures. In this newsletter, the 100 percent component 

inspection recommendation from the 2009 report was reiterated for piping systems such as the 

crude unit 4-sidecut piping. The newsletter states:

Sulfidation corrosion failures ... are of great concern because of the 

comparatively high likelihood of “blowout” or catastrophic failure. This 

typically happens because corrosion occurs at a relatively uniform rate 

over a broad area, so a pipe can get progressively thinner until it actually 

bursts rather than leaking at a pit or local thin area. In addition, the 

process fluid is often above its autoignition temperature. The 

combination of these factors means that sulfidation corrosion failures 

frequently result in large fires. Chevron and the industry have 

experienced numerous failures from this mechanism and recent incidents 

have reinforced the need for revised inspection strategies and a robust 

PMI (Positive Materials Identification) program.

 i

A 2003 corporate technical newsletter recommended 100 percent component inspection of carbon steel piping 

susceptible to sulfidation corrosion following a 2002 Chevron Salt Lake City sulfidation corrosion incident.
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26 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

The Chevron ETC 100 percent component inspection recommendation for high risk piping systems, 

established in 2009, was not implemented at Richmond; therefore, the thin-walled low silicon 4-

sidecut piping component remained in service until it catastrophically failed on August 6, 2012.

24. Chevron and Chevron ETC metallurgists, materials engineers, and piping inspectors had expertise

regarding sulfidation corrosion. They educated personnel and advocated for identification and 

control of damage mechanisms, including sulfidation corrosion. However, they had limited

practical influence to implement their recommendations. These individuals did not participate in 

the crude unit Process Hazard Analysis (PHA)

i

and did not affect decisions concerning control of 

sulfidation corrosion during the crude unit turnaround process.

ii

 i

A process hazard analysis is a hazard evaluation to identify, evaluate, and control the hazards involved in a process. 

Facilities that process a threshold quantity of hazardous materials, such as the Chevron Richmond refinery, are 

required to conduct a process hazard analysis per the California Code of Regulations Title 8 Section 5189. Process 

Safety Management of Acutely Hazardous Materials (1992). PHAs are also required by the California Accidental 

Release Prevention Program and the federal EPA Risk Management Program. ii The turnaround process includes both the planning stage prior to the shutdown and the activities staged during the 

shutdown.
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Other Significant Sulfidation Occurrences 

25. The refining industry has experienced numerous sulfidation corrosion failures, primarily in 

piping.28 API RP 939-C identifies 45 sulfidation corrosion failures, one third of which were 

found to have occurred in carbon steel piping containing low levels of silicon.29

26. The August 6, 2012, Chevron Richmond Refinery 4-sidecut pipe rupture was not the first 

sulfidation corrosion-related incident to occur at a Chevron refinery. In 1988, a low silicon 

carbon steel (0.02 wt. % silicon) piping component failed at the Chevron’s former El Paso

Refineryi

27. In 2002, the Chevron Salt Lake City Refinery experienced a fire when process piping failed as a

result of sulfidation corrosion in a low silicon ASTM A53 carbon steel piping component.

Chevron communicated the incident throughout the company in a technical newsletter. Chevron 

experts found that despite regular monitoring of the line for 30 years in compliance with industry 

standards, their inspection program failed to prevent the failure. Corrosion rates at the 

unmonitored failure location were found to be five times greater than corrosion rates at the 

monitored piping locations. The monitored locations were constructed of high silicon ASTM 

A106 piping (Figure 12). Chevron also found that in the years preceding the failure, both the 

temperature

in El Paso, Texas. In addition, two sulfidation corrosion incidents occurred at the 

Chevron Pascagoula refinery in Pascagoula, Mississippi: one in 1993 and one in 1988 on a lowsilicon carbon steel component.

ii

 i

The El Paso Refinery is now owned by Western Refining.

and hydrogen sulfide concentration in the process had been increasing. Each of 

these factors increased corrosion rates and contributed to the failure. In 2003, following this 

incident, Chevron experts recommended that refineries inspect every piping component (100 %

component inspection) in all high-risk piping systems: those operating above 550 °F and 

containing hydrogen sulfide.

ii The temperature in the line had been increased by over 170 °F throughout the life of the unit. During the two years 

prior to failure, temperatures of the line exceeded the measurement capabilities of the temperature measurement 

device and so the actual temperature increase cannot be determined. 
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28 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

Figure 12. Schematic of failed piping from the Chevron Salt Lake Refinery. Similar to the 

Chevron Richmond Refinery incident, the failed piping contained low amounts of silicon and 

corroded significantly faster than adjacent piping components.

28. In January 2007, a failure due to sulfidation corrosion caused a serious fire in the Chevron 

Richmond Refinery crude unit resulting in a CWS Level 3 alert, initiating a shelter-in-place for 

the surrounding community. A carbon steel piping spooli

failed catastrophically during 

operation (Figure 13). The carbon steel piping contained a low percentage of silicon (<0.005 

wt. %). The process fluid ignited, injuring a nearby worker. Chevron informed Contra Costa 

Health Services’ Hazardous Materials Programii

 i

A piping spool is a small, removable section of piping. In some cases, a piping spool is installed or removed in 

order to provide a temporary connection or complete disconnection between two piping circuits.

(Contra Costa County) in a letter that the 

metallurgy had been upgraded following this incident as an inherently safer solution. However,

the CSB learned that this upgrade was limited to only the immediate piping spool that failed.

The inherently safer, more corrosion resistant metallurgy was not implemented more broadly in 

crude unit high temperature service as a result of this incident.

ii Contra Costa Health Services’ Hazardous Materials program is designed to respond to emergencies and monitor 

hazardous materials within Contra Costa County. See http://cchealth.org/hazmat/ (accessed April 17, 2013). 
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29 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

Figure 13. Failed piping component that resulted in the 2007 Richmond crude unit fire. This 

carbon steel piping was found to contain less than 0.005 percent silicon.

29. Following the August 6, 2012, incident, personnel at the Chevron El Segundo, California, 

refinery, a near duplicate of the Richmond refinery, inspected their refinery’s crude unit 4-

sidecut piping. Significant thinning was discovered in the line; the piping from the atmospheric 

crude column to the pumps was removed and substituted with 9-Chrome, an upgraded and

inherently safer material of construction.

30. On November 9, 2009, the Silver Eagle refinery in Woods Cross, Utah, experienced a 

catastrophic piping failure due to sulfidation corrosion in a 10-inch pipe, while conducting a 

temporary operation at higher than normal operating temperature. The pipe was located on the 
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30 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

bottom of a reactor in the de-waxing unit. The failed pipe released hydrogen which 

subsequently exploded, damaging over 100 homes in the nearby neighborhood.

31. On October 6, 2011, an explosion and fire resulted from a catastrophic piping failure at a 

Canadian refinery in Regina, Saskatchewan, injuring 52 workers. The piping component that 

failed was substantially thinner than neighboring components. Prior to the incident, the 

company’s inspection data indicated that wall thickness in the overall piping system was within 

acceptable limits. However, the specific component that failed was not inspected. Although 

Canadian authorities are still investigating, metallurgical testing has indicated that hydrogen 

sulfide corrosion contributed to the catastrophic failure.

32. In February 2012, the BP refinery crude unit in Cherry Point, Washington, suffered a failure due 

to sulfidation corrosion, causing a large fire. This incident demonstrates that even when 

applying inherently safer concepts to reduce the potential for major hazards, it is still vital to 

fully understand all processes and piping configurations and incorporate a rigorous inspection 

program. The piping that failed was constructed of 9-Chrome. The line was used only during 

start-up operations and otherwise remained in-service and non-flowing. Such lines that do not 

have regular process flow yet remain in contact with process fluids are commonly referred to as 

“dead legs.” The failure location was a high-point in the piping connected to the top of an 

operating process line. Hydrogen sulfide evolved from the process fluid and collected in the 9-

Chrome piping. The concentrated vapor-phase hydrogen sulfide severely corroded the 9-

Chrome, causing the failure. CMLs were located on adjacent elbow components; however, no 

CMLs were placed on the straight-run piping component where the failure occurred. The Cherry 

Point sulfidation failure demonstrates that even with more corrosion-resistant, inherently safer 

metallurgy, failure from sulfidation corrosion still may occur if piping is not effectively 

inspected or piping configurations are not adequately evaluated. In addition it is important to 

conduct a thorough analysis to determine the best material of construction for the process 

conditions.
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Process Hazard Analysis

33. Chevron personnel analyze numerous deviationsi

34. Sometimes referred to as a corrosion review, a damage mechanism hazard review analyzes risks 

presented by all process failure mechanisms such as corrosion and cracking. Common process 

failure mechanisms are described in API 571: Damage Mechanisms Affecting Fixed Equipment 

in the Refining and Petrochemical Industries.

for each portion of a process when conducting 

a Process Hazard Analysis (PHA). These include conditions such as changes in flow and

temperature and pressure extremes. Specifically of interest, one of the deviations analyzed was 

“leak/rupture” of the particular vessel or pipe. For each deviation, the team’s responsibility was 

to identify causes, consequences, safeguards, and recommendations. The 4-sidecut line was 

analyzed in the most recent crude unit PHA. Corrosion was not identified as a potential cause of 

a leak/rupture in the piping (emphasis added).

30 Such a review ensures that potential hazards 

caused by process conditions, process materials, and external mechanisms are properly 

identified, analyzed, and systems are put in place to control or eliminate the hazard. Despite 

Chevron knowledge and expertise of potential damage mechanisms (such as sulfidation 

corrosion), the CSB found these hazards are only identified in a PHA if the participants 

conducting the PHA happen to have personal knowledge of the relevant mechanism. The 

Chevron PHA teams do not typically seek assistance from corrosion experts.ii

 The inclusion of a 

damage mechanism hazard review as part of the PHA is not required by the state of California,

the California Division of Occupational Safety and Health (Cal/OSHA),iii Contra Costa County, 

the City of Richmond,iv

 i

Deviations using guide words (such as no, more, less, as well as) and process parameters (such as flow, pressure, 

temperature) are analyzed in PHAs. See Center for Chemical Process Safety (CCPS). “Guidelines for Hazard 

Evaluation Procedures.” 2nd ed., Page 132, 1992. 

or Chevron standards. Because Chevron does not conduct, and is not 

required to conduct, a formal damage mechanism hazard review, damage mechanisms are only 

identified when the PHA team happens to have some knowledge of the mechanism. As a result, 

many damage mechanisms which occur in various processes are not properly addressed. 

ii The Crude Unit Business Improvement Network (BIN) Leader, a crude unit expert, reviews portions of the PHA 

with the PHA team. However, this review did not identify the potential for sulfidation corrosion failures in the 4-

sidecut piping. A rigorous review of corrosion and damage mechanisms present in the crude unit was not performed 

during the PHA process. 

iii The state of California, under an agreement with the federal Occupational Safety and Health Administration, or 

OSHA, operates an occupational safety and health program in accordance with Section 18 of the Occupational 

Safety and Health Act of 1970. See http://www.osha.gov/dcsp/osp/stateprogs/california.html (accessed April 17, 

2013). The Department of Industrial Relations administers the California Occupational Safety and Health Program, 

commonly referred to as Cal/OSHA. The program applies to all public and private sector places of employment in 

the state, with some exceptions. See http://www.dir.ca.gov/dosh/dosh1.html (accessed April 17, 2013). 

iv The City of Richmond adopted an ordinance on Industrial Safety, Richmond Municipal Code Chapter 6.43 (also 

known as the RISO), on December 18, 2001, “for the purposes of protecting public health and safety by prevention 

of accidental release of hazardous materials and to assure protection of the environment.” Richmond Municipal 

Code §6.43.040 (February 5, 2013). There are two facilities, including Chevron, that are located in the City of 

Richmond and subject to this ordinance. More information about the RISO is provided later in the report. 
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32 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

35. During a hazard analysis process such as a PHA, the evaluation team has to determine the 

likelihood of a hazardous consequence occurring. Then the team must identify safeguards which 

will reduce the risk of the hazard to an acceptable level. A recognized methodology for 

consistently and objectively making these determinations could include the use of quantitative, 

semi-quantitative, or qualitative tools.

31 Chevron does not employ a prescribed methodology for 

determining the likelihood that an incident will occur or whether a safeguard will be effective. 

Instead, Chevron relies upon the judgment of the people on the PHA team, who base their 

conclusions upon their collective experiences, beliefs, and areas of expertise. In its 2009 crude 

unit PHA, Chevron simply cited non-specific, judgment-based qualitative safeguards such as: 

utilizing metallurgy to minimize corrosion, having effective maintenance and inspection 

programs, and providing pipe wall corrosion allowances.

i

36. Following the August 6th incident, Cal/OSHA inspected the Chevron facility and issued 

citations. Only one citation related to PHAs, and it was not associated with evaluating the 

effectiveness of safeguards. Rather, the emphasis was that Chevron’s PHA did not adequately 

account for hazards caused by other units associated with the crude unit. The citation stated 

“The Employer [Chevron] failed to perform an effective Process Hazard Analysis [PHA] of the 

crude unit. Specifically, it failed to identify, evaluate, and control potential hazards caused by 

upstream and downstream units that provide and receive feed from the crude unit.”

The effectiveness of these safeguards 

was neither evaluated nor documented; instead the safeguards were merely listed in the PHA.

Had the adequacy of these safeguards been verified, improved safeguards intended to protect 

against sulfidation-induced failure of carbon steel piping could have been recommended. 

32

 i

Corrosion allowance refers to extra wall thickness added as a safety factor to the design of a piece of equipment 

beyond that needed solely for mechanical considerations such as design temperature and pressure. This extra 

thickness is provided to accommodate for expected loss of wall thickness due to corrosion over the life of the 

equipment.

 Had the 

Cal/OSHA regulation required documentation of the effectiveness of safeguards, Chevron would 

have been obligated to conduct this analysis and Cal/OSHA inspectors could rely on the 

regulation for support during inspections. 
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Operational Changes

37. The original design of the 4-sidecut circuit included equipment which had the effect of removing 

dissolved hydrogen sulfide, the most aggressive sulfur compound associated with sulfidation 

corrosion, from the 4-sidecut light gas oil process fluid. As a result, the 4-sidecut equipment 

was effective in reducing the sulfidation corrosion rate. This allowed the 4-sidecut equipment to 

be constructed of carbon steel. In 1991, this 4-sidecut equipment was taken out of service. No 

management of changei

38. Crude oil feedstock used at the Chevron Richmond Refinery is obtained from a variety of 

different sources that are blended before processing. These various crudes have different 

compositions, such as varying sulfur compounds and concentrations. These crudes can have 

differing corrosion effects on process equipment and piping. There is an increasing trend in 

crude oil refining to process less expensive “opportunity crudes” because they can provide 

significant cost savings to the company.

(MOC) was performed to analyze the effect of the elimination of this 

hydrogen sulfide-removing equipment on 4-sidecut corrosion rates. Such an MOC would have

ensured that the increase in sulfur concentration on the carbon steel 4-sidecut piping was 

reviewed prior to removing the equipment.

ii However, these crudes may contain more undesirable 

characteristics such as high sulfur content, high naphthenic acid content, or very heavy 

hydrocarbons33

 i

Management of change requires that employers have procedures to manage changes to process chemicals, 

technology, equipment, and procedures. The procedures must address the technical basis for the change, the impact 

on safety and health, and training required for employees affected by the change.

that a refinery may not have been originally designed to process. Refinery 

equipment may not be the proper material of construction to achieve the design life of the 

equipment when exposed to the different operating conditions. Additional mitigation may be 

needed to reduce risk. In 1984, the Chevron Richmond Refinery crude oil feed contained 

approximately 85 volume % Alaskan North Slope (1 wt. %) crude oil. As the refinery began 

running more high-sulfur content crudes, the sulfur content in the 4-sidecut line steadily 

increased (Figure 14), as discussed below. 

ii Crude oil costs can account for up to 90% of the operating costs in a refinery. See Qu, Dingrong, Xiaohui Liu, Xiu 

Jiang, Zhenggui Lan, and Guangbin Shan. “Setting Critical Operational TAN and Sulfur Level for Crude 

Distillation Units.” Corrosion 2011 Conference & Expo. Paper No. 11362. NACE International, 2011. 
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34 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

Figure 14. Graph shows the percentage increase from 1984 values of the sulfur content in 

the 4-sidecut. 

39. When Chevron introduces a new crude, an MOC is generated to evaluate the potential impact on

the refinery.

i

40. The CSB found that increased Chevron Richmond usage of non-domestic crude feed stock over 

time resulted in higher sulfur content in the process fluid passing through the 4-sidecut piping.

Specifically, the percentage of sulfur in the Richmond refinery crudes increased nearly 85% 

between 1984 and 2012, including a significant jump of 32% from 1998 to 1999. This increase 

in sulfur content corresponded with a simultaneous increase in the usage of non-domestic crude 

feed at the Richmond refinery.

 While Chevron stayed under its established crude unit design basis for total wt. %

sulfur of the blended feed to the crude unit, the sulfur composition significantly increased over 

time. Historic data indicates that the sulfur in the 4-sidecut stream has increased from 0.8 to 1.6 

wt%. This increase in sulfur composition likely increased corrosion rates in the 4-sidecut line.

Chevron did not conduct an MOC analyzing the impact that increases in sulfur composition 

would have on corrosion in the crude unit. Chevron also did not change its corrosion monitoring 

programs in response to the increased sulfur content. 

 i

Chevron MOCs on new crudes considered general operational issues but did not analyze corrosion effects from 

sulfidation corrosion. 
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35 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

41. Sulfidation corrosion rates increase in piping circuits as temperature and sulfur content increase. 

Accordingly, the 4-sidecut sulfidation corrosion rate increased between 1984 and 2012 due to 

the increase in sulfur content in the line. The CSB found that for the 26-year period from the 

installation of the piping in 1976 through 2002, the 52-inch 4-sidecut component had lost 

approximately 33 percent of its wall thickness. From the single inspection of the 52-inch 

component in 2002 to the incident in 2012 – just ten years – an additional 57 percent of the 

original component nominal wall thickness was lost near the rupture location due to sulfidation 

corrosion.i

42. API RP 939-C states that refinery feed stock changes reduce the relevance of past inspection 

data when predicting future corrosion rates: 

In addition to the sulfur content increase, the 4-sidecut draw temperature increased 

from 625 °F in 1992 to 680 °F in 2002. Corrosion rates and remaining life calculations based on 

past sulfur content and temperatures may not accurately reflect current corrosion rates if process 

conditions have changed. Inspection based on historical corrosion rates may be too infrequent to 

detect an increase in corrosion caused by adverse changes in process conditions, potentially 

leading to equipment failure.

Oil refineries that processed a consistent diet of a particular crude oil or 

crude blend could often base future predictions on past experience. 

However, over the past 20+ years, global economics have resulted in 

many refineries processing tens of different crudes in any given year;

thus, minimizing the accuracy, or even feasibility, of predictions based 

on historical data. Additionally, the verification of the actual corrosion 

rate experienced while processing a specific crude oil is very difficult.34

43. API 570 Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping 

Systems, the API standard for inspecting piping, recommends companies to incorporate process 

changes into inspection programs. The standard states: 

The owner/user is ... responsible for implementing an effective MOC 

process that will review and control changes to the process and to the 

hardware. An effective MOC process is vital to the success of any 

piping integrity management program in order that the inspection group

will be able to anticipate changes in corrosion or other deterioration 

variables and alter the inspection plan to account for those changes. The 

MOC process shall include the appropriate materials/corrosion 

experience and expertise in order to effectively forecast what changes 

might affect piping integrity. The inspection group shall be involved in 

the approval process for changes that may affect piping integrity. 

 i

The 4-sidecut 52-inch component had an original wall thickness of 0.322 inches. Metallurgical analysis found the 

thinnest portion of the 52-inch 4-sidecut component was 0.03 inches. 
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36 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

Changes to the hardware and the process shall be included in the MOC 

process to ensure its effectiveness [emphasis added].

35

Chevron failed to comply with the requirements of API 570 when it did not conduct an 

MOC to thoroughly evaluate the change of increasing sulfur weight percentage in crude 

oil feed and to assess how it might affect corrosion rates within the 4-sidecut piping 

circuit. After the August 6, 2012, incident, Cal/OSHA inspected the Chevron 

Richmond Refinery and issued citations.i

Chevron Sulfidation Corrosion Inspection and Mitigation

However, Cal/OSHA did not issue any 

citations for failing to perform an MOC when sulfur composition in the crude oil feed 

was increased.

44. In the ten years prior to the incident, a small number of Chevron personnel with knowledge and 

understanding of sulfidation corrosion made at least six recommendations (listed in the 

following six paragraphs and included in Figure 15) to increase inspections or upgrade the 

metallurgy in the 4-sidecut piping. The recommendations made by these personnel were not 

implemented by Chevron management.

Figure 15. Key events at the Richmond refinery between 1998 and 2013.

 i

Cal/OSHA citations issued January 30, 2013.
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37 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

45. In August 2002, a Chevron Richmond Refinery employee performed a study analyzing

sulfidation corrosion rates in the crude unit and identifying potentially vulnerable areas. The 

employee discovered that the 4-sidecut operating temperature had been increased and concluded

that this increase would cause more hydrogen sulfide to evolve, leading to increased sulfidation 

corrosion rates. As a result of these findings, the employee recommended increased inspection 

of the 4-sidecut piping and noted that this piping might need to be upgraded from carbon steel to 

5-Chrome, a steel alloy that is more resistant to sulfidation corrosion. In 2002, proactively 

following up on this study, the crude unit inspector conducted additional piping inspection and 

identified accelerated corrosion in the 52-inch 4-sidecut component. The inspector 

recommended upgrading this piping during the next shutdown in 2007. In the inspector’s 2002 

accomplishments, Chevron management acknowledged this effort to prevent a significant 

incident; it was characterized as “a save.” However, during the 2007 turnaround the 

recommendation was not implemented, and because a CML was not added to the inspection 

program, the 52-inch component was not inspected after 2002.

46. In February 2006, a team consisting of a materials and corrosion engineer, an inspector, a 

process engineer, a metallurgist, and a design engineer issued a Corrosion Mitigation Plan for 

the Chevron Richmond Refinery crude unit. The report specifically identified the 4-sidecut

piping to be at risk for high temperature sulfidation corrosion. The report described that low 

silicon carbon steel can corrode faster than carbon steel manufactured with higher silicon 

content, and recommended that 100 percent inspection be performed on the 4-sidecut line using 

continuous monitoring technology. During the 2007 crude unit turnaround, continuous 

monitoring probes were only installed on a segment of the 4-sidecut line that did not include the 

52-inch component that ultimately failed. The 100 percent inspection recommended in the 2006 

Corrosion Mitigation Plan was not performed.

47. During the 2007 turnaround, the crude unit inspector recommended that the refinery upgrade the 

entire 4-sidecut piping with 5-Chrome. The recommendation was based on findings obtained 

during the 2002 crude unit turnaround, where the crude unit inspector found that the 52-inch 4-

sidecut component had lost one-third of its wall thickness due to corrosion. However, after 

evaluation, this recommendation was not accepted by the turnaround planning team. Basing its

decision on limited inspection data, Chevron determined that the 8-inch portion of the 4-sidecut

piping that ran from the atmospheric column to the pump, the portion which included the 52-

inch component, had sufficient wall thickness to last to the next turnaround scheduled for Fall

2011.

i

 i

This decision was made without reinspecting or evaluating the thickness of the thinned 52-inch component 

identified in 2002 that prompted the recommendation. 

The piping downstream of the pump, which operates at a higher pressure, was 

determined not to have sufficient wall thickness to last to the next turnaround. This piping was 

removed and replaced with 9-Chrome, an upgraded and inherently safer metallurgy. The 52-

inch component of the 8-inch piping between the atmospheric column and the pump was not 

replaced during the 2007 turnaround even though it had been identified as thinned in 2002.
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38 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

Furthermore, a permanent CML was not placed on the 52-inch component, and it was not 

entered into the inspection database. As a result, the component was not inspected again.

48. In September 2009, Chevron ETC corrosion experts released a formal technical report 

discussing sulfidation corrosion and the specific issues associated with carbon steel, including 

the potential for high corrosion rates in carbon steel piping containing low percentages of 

silicon. In its report, Chevron ETC issued recommendations for inspection and provided

guidelines for prioritizing piping circuits susceptible to sulfidation corrosion so that high-risk 

lines could be evaluated first. It was recommended that 100 percent component thickness testing 

be completed on all high priority lines one time to identify thin, low-silicon components to

establish a baseline of corrosion rate and risk for failure. Following the release of the report, the 

Chevron Richmond Refinery materials group completed the risk-ranking of the carbon steel 

piping in the Richmond Lube Oil Project (RLOP) and in the crude unit, two units known to be 

susceptible to sulfidation corrosion. The group identified the crude unit 4-sidecut line as a high 

risk line per the report ranking guidance. Instead of completing the 100 percent component 

inspection, the 4-sidecut was recommended for replacement with 9-Chrome. However, the 

replacement recommendation was denied because the available, limited inspection data indicated 

the piping would last until the next turnaround. Subsequently, the alternative 100 percent 

component inspection was also never performed.

49. Five months prior to the incident in March 2012, a Chevron corporate review of Richmond 

identified that inspection of all carbon steel components susceptible to sulfidation corrosion was 

not being performed at the Richmond refinery. In addition to identifying that CMLs were not in 

the proper locations, this corporate review found that critical inspection recommendations were 

being submitted to the shutdown planning process, but were being denied. Chevron corporate 

identified that Richmond refinery leadership needed to review and implement the 2009 Chevron 

ETC report recommendations.

50. Chevron conducts “Intensive Process Reviews” prior to turnarounds. This process involves 

knowledgeable individuals including Business Improvement Network leaders, process engineers, 

metallurgical engineers, design engineers, and turnaround planners. The purpose of the review is 

to identify key unit issues that should be addressed and repaired during the unit turnaround. Prior 

to the 2011 crude unit turnaround, Chevron personnel conducted an Intensive Process Review of

the crude unit and specifically recommended that the 4-sidecut carbon steel piping “should be 

upgraded to 5 Cr [5-Chrome]... due to sulfidation.” Although the Intensive Process Review

identified sulfidation problems in the 4-sidecut line, this activity was ineffective. The 4-sidecut 

piping was not upgraded during the 2011 crude unit turnaround. 

51. In preparation of the work list for the 2011 crude unit turnaround, the crude unit inspector and 

crude unit metallurgist recommended that the 4-sidecut line be replaced with an upgraded 

metallurgy, 9-chrome, the metallurgy recommended in the Chevron new construction guidelines 

for piping in high temperature and high sulfur service. The recommendation was based on the 
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39 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

high priority ranking of the 4-sidecut line, corrosion history, and both Chevron and industry

recommended best practice. However, the turnaround management team determined that the 

inspection data available for the 4-sidecut piping, from CMLs on elbow components which are 

less prone to sulfidation corrosion, did not support a material upgrade during the 2011 

turnaround.

i, ii

 i

This decision was made without reinspecting or evaluating the thickness of the 52-inch component identified in 

2002. 

 The lack of data on the more susceptible 4-sidecut straight-run piping components 

was not considered.

ii A portion of the 4-sidecut 12-inch line was replaced during the 2011 turnaround with carbon steel due to thinning 

caused by sulfidation corrosion.
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40 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

Inherently Safer Systems

52. The Center for Chemical Process Safety (CCPS) is a corporate membership organization that 

identifies and addresses process safety needs within the chemical, pharmaceutical, and 

petroleum industries.36 Chevron is a corporate member of CCPS.37 The CCPS book Inherently 

Safer Chemical Processes, 2nd ed. defines inherently safer design as the process of identifying 

and implementing inherent safety in a specific context that is permanent and inseparable.38 In 

the book Guidelines for Engineering Design for Process Safety, 2nd ed., CCPS states “inherently 

safer design solutions eliminate or mitigate the hazard by using materials and process conditions 

that are less hazardous.”39

53. Inherently safer technologies are relative; a technology can only be described as inherently safer 

when compared to a different technology with regard to a specific hazard or risk.40 A 

technology may be inherently safer with respect to one risk but not safer from another risk. For 

this reason, it is important to carry out a comprehensive, documented hazard analysis to 

determine the individual and overall risks in a process and assess how the risks can be 

effectively minimized to control hazards. An inherently safer systems review details a list of 

choices offering various degrees of inherently safer implementation. The review should include 

risks of personal injury, environmental harm, and lost production, as well as evaluating

economic feasibility.41

54. It is simpler, less expensive, and more effective to introduce inherently safer features during the 

design process of a facility rather than after the process is already operating.

42

55. After a 2007 incident caused by a pipe failure in the Richmond refinery crude unit, Chevron 

implemented an “Inherently Safer Solution” by upgrading the piping to metallurgy that was less 

susceptible to sulfidation corrosion. However, the change was implemented intuitively without 

a supporting inherent safety review or failure mechanism hazard review to provide a detailed 

documented technical rationale for the metallurgy selection. Without such a review, the material 

selected cannot be analyzed to determine if it is the best inherently safer solution for the process 

in order to minimize risk. 

Process upgrades, 

rebuilds, and repairs are additional opportunities to implement inherent safety concepts.

Conducting a comprehensive hazard review to determine risks and identify ways to eliminate or 

reduce risks is an important step in implementing an inherently safer process. Chevron training

programs on inherently safer systems reflect this approach, stating “we have the greatest 

opportunity to eliminate or minimize hazards during the development phase of new projects or 

major revamps of existing facilities.”
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41 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

56. Following the August 6, 2012, incident, the 4-sidecut piping circuit at the Richmond refinery 

was upgraded from carbon steel to 9-Chrome.

i However, Chevron did not produce a 

documented inherently safer hazard review before commencing the rebuild of the crude unit.

The crude unit at the Chevron El Segundo refinery is nearly identical in construction and design 

to the Richmond refinery crude unit. Chevron informed the CSB that piping downstream of the 

4-sidecut pumps in the 4-sidecut piping circuit at the El Segundo refinery was upgraded in 2001ii

57. An effectiveness ranking of techniques used to control hazards and the risk they represent can be 

described as a hierarchy of controls. The further up the hierarchy, the more effective the risk 

reduction achieved (Figure 16). All concepts in the hierarchy of controls should be included in 

the process of risk assessment and reduction. Upgrading metallurgy to a more corrosion 

resistant material may be a high ranking, inherently safer choice for certain corrosion 

mechanisms, such as sulfidation corrosion. Holding other variables constant, upgrading the 

material of construction may reduce the severity of corrosion and the likelihood of a failure.

from carbon steel to stainless steel. As stated previously, after the August 6, 2012, Richmond 

incident, the 4-sidecut piping upstream of the 4-sidecut pumps at the El Segundo refinery was

upgraded from carbon steel to 9-Chrome. Had a comprehensive inherently safer systems review

been conducted at the Richmond refinery following the August 6th incident, a different 

metallurgy, such as stainless steel which was installed at the Chevron El Segundo Refinery, may

have been identified as inherently safer than 9-Chrome with respect to sulfidation corrosion.

Figure 16. Hierarchy of controls. The boxes reflect inherently safer controls from left to 

right, based on Process Plants: A Handbook for Inherently Safer Design Second Edition; 

Kletz, Trevor Amyotte, Paul; CRC Press 2010.

58. Chevron employees have recommended implementing inherently safer designs through the 

MOC process, incident investigations, technical reports, and recommendations from employees 

in the past. However, the CSB has not identified any documented, thorough analysis of the 

proposed inherently safer solutions. In addition, Chevron has repeatedly failed to implement 

proposed inherently safer recommendations. For example, following the discovery of significant 

4-sidecut piping sulfidation corrosion in 2002, a Chevron inspector issued the following 

recommendation to replace the piping in the 2007 turnaround:

 i

After the 2012 incident, the Richmond refinery stated that stainless steel was susceptible to chloride stress 

corrosion cracking and should not be used.

ii Chevron verbal estimate for date of piping installation. No MOC was conducted to review and document this 

change.
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42 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

The #4 sidecut piping from C-1100 to P-1149/A to E-1113 was RT (xray) inspected for hot H2S [sulfidation] corrosion. The piping is actively 

corroding, particularly on the section on the discharge line from the 

pumps near the exchanger; the line upstream of the P-1149/A pumps is 

corroding as well. Corrosion rates indicate that the piping has 4 years of 

remaining life until the refinery throwaway thickness of 0.14” [inch] is 

reached. The carbon steel piping is currently running at temperatures 

between 650 °F on the pump suction line to 641 °F on the line just before 

E1113; the upper limit for carbon steel piping in this service is 550 °F. A 

materials upgrade to 5 chrome would raise the upper limit to between 

650-750 °F. Additionally, the ABCR piping loop from the same sidecut 

draw line off of the column to P-1148/A to E-1111 is also carbon steel 

and operates at the same temperatures, rendering the ABCR piping 

system to E-1111 susceptible to hot H2S corrosion as well.

INFORMATION

Replace the existing #4 sidecut piping noted above from C-1100 through 

P-1149/A to E1113 and P-1148/A to E-1111 (approximately 700’[feet]

of 12”, 10”, 8” and 6”piping, plus some 4”and 3” at the P-1149/P-1148 

suction/discharge headers). Upgrade the pipe material from carbon steel 

to 5 chrome. 

Recommendation

To implement this recommendation, Chevron initiated an MOC in 2006 to replace the piping

during the 2007 Turnaround. However, the MOC supporting documents had a narrowed scope 

to only replace the section of piping from P-1149/A pumps to the E-1113 heat exchanger

because Chevron reduced the work scope during the 2007 turnaround planning process. The 

Description of Change in the MOC stated:

Existing line is carbon steel in a hot service that operates in the range 

where high temperature sulfadation [sic] occurs. The line has been uti

inspected and found to be nearing tminii

Contradicting this Description of Change detailing a replacement of the entire 4-sidecut piping 

circuit, the MOC Summary Review and attached documentation only authorized replacement of

the piping from the P-1149’s to E-1113. The MOC states:

requiring replacement. Due to 

the higher temperature 9CR [9-Chrome] would be the prefered [sic] 

material.

 i

UT is an abbreviation used to indicate ultrasonic thickness testing inspection technique.

ii Tmin is an abbreviation used to indicate minimum required piping wall thickness.
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43 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

4 S/C piping has been operating hotter in recent years. The hotter 

temperatures 550 °F are in the high temperature sulfadation [sic] range. 

Additionally the section of 4 S/C piping from P-1149' s to E-1113 has 

been found to be nearing tmin.

The section of pipng [sic] from P-1149’s to E-1113 will be replaced with 

9 Cr [9-Chrome] piping.

As a result, the portion of the piping containing the 52-inch component that failed on August 6th

remained in service. Although the recommendation was intended to more broadly apply 

inherently safer materials of construction, the final implementation by the MOC limited the 

application of this more corrosion resistant metallurgy.i

59. In 2007, the Chevron Richmond Refinery conducted training to teach employees about the 

importance of complying with the City of Richmond’s Industrial Safety Ordinance (RISO)

Again, the inherently safer, more 

corrosion resistant, metallurgy was not implemented more broadly in crude unit high 

temperature service. Other examples are discussed above in the section entitled Chevron 

Sulfidation Corrosion Inspection and Mitigation.

ii

inherent safety guidance. The training states “we should always strive to implement inherently 

safer strategies to the greatest extent feasible.” However, Chevron did not regularly or 

rigorouslyiii apply inherently safer design strategies in opportunities including PHAs, MOCs, 

incident investigation recommendations, and during turnarounds.

iv

60. Chevron uses an inherently safer design checklistv

 i

As discussed earlier, only the section of piping downstream of the pumps was replaced with 9-Chrome.

for PHAs to meet inherently safer systems 

analysis requirements of the RISO. The checklist, provided by Contra Costa County, is intended 

to aid identification of opportunities to implement inherently safer design during the PHA 

process. The checklist was intended to stimulate discussion and analysis of potential

opportunities to implement inherently safer design. Contra Costa County’s guidance on the IST 

checklist states that some items may need to be reviewed by a team that is outside the PHA team 

in order to involve people with the required expertise. Chevron utilized the Contra Costa 

County inherently safer technologies checklist (IST Checklist) during the 2009 crude unit PHA.

ii The RISO will be discussed in more detail in the Regulatory Oversight section below. iii Chevron does not utilize inherent safety guidewords or checklists during the MOC or incident investigation 

process. Inherently safer guidewords help direct the inherently safer review process. Examples of guidewords 

include minimization, substitution, moderation, and simplification. These words may be applied to materials, 

product inventory, process controls, process piping, and siting, among others. See Center for Chemical Process 

Safety (CCPS). “Inherently Safer Chemical Processes – A Life Cycle Approach.” 2nd ed., Table 8.3, 2009. 

iv As stated in the Regulatory Oversight section below, Chevron is only required to conduct inherently safer design 

strategies during PHAs and for the construction of new processes. 

v Contra Costa County’s guidance document entitled “Attachment C: Inherently Safer Systems Checklist” is 

provided as a tool for facilities to utilize during the PHA process. The actual use of the checklist is not required. 

See http://cchealth.org/hazmat/pdf/iso/attachment_c.pdf (accessed April 17, 2013). 
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44 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

However, only three permissively wordedi

inherently safer system recommendations were made, 

none of which addressed sulfidation corrosion or piping metallurgy. In addition, Chevron 

performed the checklist analysis using the same individuals who conducted the PHA despite

Contra Costa County’s guidance to involve other personnel with additional expertise.

Performing a superficial analysis, Chevron failed to adequately consider inherently safer systems 

like improved metallurgy for corrosion resistance. For instance, the checklist prompted: “Use 

corrosion resistant material?” In response, Chevron stated that “vessel specifications and piping 

classifications include a conservative wall thickness and an appropriate corrosion allowance for 

each service.” No mention is given to improving metallurgy to reduce corrosion. There is also 

no documented analysis regarding potential materials with enhanced corrosion resistance. There

was no documentation of the inherently safer technologies analysis, and no inherently safer 

alternatives were documented. The checklist as applied by Chevron was a “check-the-box” 

exercise. Chevron Richmond PHAs were thus not an effective means of driving inherent safety.

The table below gives a sample of the IST checklist questions along with the associated Chevron 

responses.

ii

Contra Costa County Checklist Question

 

Chevron IST Analysis

Use Corrosion resistant materials? Vessel specifications and piping classifications 

include a conservative wall thickness and an 

appropriate corrosion allowance for each service.

Use smallest diameter piping? Piping sizes are the smallest possible for the capacity 

of the unit.

Substitute less hazardous raw materials? Raw materials in use are of minimal hazard.

Dilute hazardous raw materials? Raw materials currently dilute where applicable.

Minimize off-site impacts? #4 Crude Unit is located at a distance from public 

areas.

Easy operation of valves designed to prevent 

inadvertent error? In general, valves are arranged in a logical manner.

Increasing wall strength?

Piping classifications include a conservative wall 

thickness and an appropriate corrosion allowance for 

each service.

61. Contra Costa County inspected the Chevron Richmond Refinery in 2011, auditing Chevron’s 

implementation of the county’s inherently safer systems analysis requirements in the PHA 

process. The inspectors determined that Chevron’s PHAs “follows the requirements specified 

by ... ISS [inherent safety systems] guidelines.” This approval by Contra Costa County

 i

All began with “consider” and two began with “consider evaluating” which does not require any action by 

Chevron.

ii The comprehensive list of IST checklist questions and Chevron’s corresponding answers are provided separately 

on the CSB website. 
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45 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

conveyed to Chevron that the regulator considered that Chevron’s minimal analysis of 

opportunities to implement inherently safer design, its “check-the-box” exercise, was sufficient.

62. Effectively implementing inherently safer technology provides an opportunity for preventing 

major chemical incidents. The August 6, 2012, incident at Chevron and other incidents43

63. It is essential that MOCs incorporate hazard analyses and the assessment of opportunities to 

implement inherently safer systems. This process can be assisted through the use of guidewords 

to trigger the thought process. CCPS states that “by including inherent safety guidewords in a 

management of change program, the MOC protocol recognizes inherent safety as both a driving 

force for - and as an opportunity during - implementation.”

throughout the refining industry highlight the difficulty in preventing failure caused by 

sulfidation corrosion in low silicon carbon steel piping solely through inspection, a procedural 

safeguard that is low on the hierarchy of controls. Using inherently safer design concepts to 

avoid issues such as variation in corrosion rate in carbon steel piping due to hard-to-determine 

silicon content will reduce future similar failures in refineries. Chevron and other process 

plants’ implementation of inherently safer systems to the greatest extent feasible would provide 

a higher degree of protection from incidents like the one that occurred on August 6, 2012.

44

64. Layer of Protection Analysis (LOPA) is a well-recognized hazard analysis methodology that is 

intended to determine if a sufficient number of safeguards or layers of protection exist to protect 

against a particular hazard or accident scenario.

45 As the potential consequence of a particular 

scenario increases, the number of safeguards or protection layers must increase to reduce the risk 

of the scenario to what is considered an acceptable or tolerable level.46 LOPA can be used to 

help an organization decide if the risk of a scenario or hazard has been reduced to a level that is 

“as low as reasonably practicable” (ALARP).47 ALARP is a risk reduction goal, where risk 

reduction efforts are continued until the incremental effort to further reduce risk becomes grossly 

disproportionate to the level of additional risk reduction.

48 By rigorously reviewing accident or 

hazard scenarios, evaluating the potential consequence of the scenario, and identifying the 

safeguards or layers of protection necessary to drive risk to as low as reasonably practicable, 

LOPA becomes an effective organizational tool for implementing a Process Safety Management 

(PSM) mechanical integrity program.49 LOPA also helps an organization decide which 

safeguards to focus on during operation, maintenance, and training.i, 50 In addition, the LOPA 

methodology includes provisions allowing an organization to determine the availabilityii and

effectiveness of a safeguard or layer of protection in reducing the risk of a potential scenario.51

 i

Chevron is a member of CCPS and peer-reviewed the CCPS LOPA publication. See Center for Chemical Process 

Safety (CCPS). “Layer of Protection Analysis – Simplified Process Risk Assessment,” page xiv, 2001. ii The probability that a system will be able to perform its designated function when required for use. Another term 

frequently used is Probability of Failure on Demand (PFD). Availability = 1 - PFD. See Center for Chemical 

Process Safety (CCPS), “Guidelines for Safe Automation of Chemical Processes,” page XIX, 1993.
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46 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

Regulatory Oversight

65. The Contra Costa County Industrial Safety Ordinance (ISO) requires that regulated facilitiesi

66. The purpose of the ISO is to “prevent accidental release of hazardous chemicals; improve 

accident prevention by soliciting participation from industry and the community; require 

industry to submit a Safety Plan; and conduct audits of the plan and inspections of the industrial 

plants.”

within the county implement safety programs to prevent chemical incidents. Since the ISO took 

effect in January 1999, Contra Costa County has continued to make improvements to the 

implementation of the prevention program’s elements.

52

67. Although the City of Richmond is located in Contra Costa County, the county does not have 

jurisdiction over industrial facilities located within the city limits. Thus, the ISO is not 

enforceable within the City of Richmond. On December 18, 2001, the City of Richmond 

adopted its own industrial safety ordinance (RISO), based on the ISO.

ii, 53 The RISO covers the 

two facilities located within the City of Richmond: Chevron and General Chemical West 

Richmond Works.54 Pursuant to an agreement between the two parties, Contra Costa County

inspects these two facilities and implements the RISO for the City of Richmond.

55

68. The ISO and RISO contain identical provisions that address the use of inherent safety concepts.

Each defines “inherently safer systems” as “feasible alternative equipment, processes, materials, 

lay-outs and procedures meant to eliminate, minimize, or reduce the risk of a major chemical 

accident or release by modifying a process rather than adding external layers of protection.”56

For all covered processes, the stationary source shall consider the use of 

inherently safer systems in the development and analysis of mitigation 

items resulting from a process hazard analysis and in the design and 

review of new processes and facilities. The stationary source shall select 

and implement inherently safer systems to the greatest extent feasible. If 

a stationary source concludes that an inherently safer system is not 

feasible, the basis for this conclusion shall be documented in meaningful 

detail.

Both regulations also require that:

57

 i

The ISO applies to oil refineries and chemical plants within the county jurisdiction that are required to submit a 

Risk Management Plan to EPA and are program level 3 stationary sources as defined by the California Accidental 

Release Prevention (CalARP) Program. There are seven facilities covered by the ISO, five of which are refineries. 

See http://cchealth.org/hazmat/iso/ (accessed April 17, 2013). ii At the time of the August 6th incident, the RISO did not include amendments made to the ISO in 2006. The 2006 

amendments required an expansion of human factors programs, expanded management of organizational change 

reviews, security vulnerability analyses, and safety culture assessments. These amendments were subsequently 

adopted by the City of Richmond in February 2013. See http://cchealth.org/hazmat/iso/ (accessed on April 9, 2013).
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47 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

69. The apparent intent of the ISO and RISO regulations is to require companies to evaluate their 

processes in order to identify opportunities to implement inherently safer systems. However, the 

plain language contained within these regulations conflicts with this intent. Both regulations 

contain the following permissive language: “the stationary source shall consider the use of 

inherently safer systems...”58

70. The language within the ISO and RISO regulations also requires effective action to implement 

inherently safer systems “to the greatest extent feasible.”

This language does not require companies to conduct a 

comprehensive analysis and implement inherently safer systems even where feasible. It only 

requires such an analysis be considered. The regulations allow companies to merely engage in 

an activity contemplating the potential use of inherently safer systems. 

59 If an inherently safer system is not 

implemented, the regulations require that the basis for this decision be “documented in 

meaningful detail.” 60 However, these regulations do not require documentation supporting the 

adequacy of existing “inherently safer” 61

71. The inherently safer systems requirements of the ISO and RISO are only triggered by the 

conduct of a PHA or the construction of a new process.

claims. Chevron’s compliance with the RISO is 

indicative of this deficiency. In its inherently safer systems checklist, Chevron simply 

concluded that its systems were inherently safer to the extent that no modifications were 

necessary. However, the company offered no documentation to substantiate these claims. Had 

the ISO and RISO regulations required analysis of inherently safer systems regardless of what 

the site already had in place, Chevron may have implemented the inherently safer 

recommendations made by technical staff to replace the 4-sidecut with an inherently safer 

metallurgy. 

62

72. The Contra Costa County PHA guidance document presents four categories of risk reduction:

Rebuilds, repairs, MOCs, and the 

implementation of incident investigation corrective actions do not require the analysis and 

application of inherently safer systems.

i

inherent, passive, active, and procedural (Figure 15).

ii It states that all four categories should be 

used in the development of recommendations from process hazard analyses.63 It reiterates the 

CCPS statement that all may contribute to the overall safety of a process, but that inherent safety 

is the most effective.64 It goes on to state “The inherent and passive categories should be 

implemented when feasible for new processes and facilities and used during the review of 

Inherently Safer Systems for existing processes if these processes could cause incidents that 

could result in a Major Chemical Accident or Release.”65

 i

The guidance document uses CCPS definitions for the identified categories of risk reduction.

This wording in the guidance 

ii Inherent risk reduction involves eliminating the hazard by using materials and process conditions that are nonhazardous. Passive risk reduction is defined as minimizing the hazard through process and equipment design 

features that reduce the frequency or consequence of the hazard without active functioning of any device. Active 

risk reduction includes using controls, alarms, safety instrumented systems, and mitigation systems to detect and 

respond to process deviations from normal operation. Procedural risk reduction achieves the lowest level of risk 

reduction and involves using policies, operating procedures, training, administrative means, emergency response, 

and management approaches to prevent incidents and minimize the effects of an incident.
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48 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

document demonstrates the importance Contra Costa County places on risk reduction and 

prevention such as metallurgy upgrades; however, as a guidance document, it is non-mandatory.

73. The California Division of Occupational Safety and Health (Cal/OSHA) has jurisdiction over 

employee safety in California.66 Cal/OSHA is a division of the California Department of 

Industrial Relations and has operated a state plan industrial health and safety program since 1973

under a delegation from the U.S. Occupational Safety and Health Administration (OSHA).

Cal/OSHA conducts inspections of California workplaces in response to industrial accidents, 

safety complaints, or as part of an inspection program targeting specific industries.67

Consideration of inherently safer processes is not currently a required component of any 

Cal/OSHA (or federal OSHA) standard or regulation.i

74. The State of California has promulgated process safety regulations similar to OSHA68 for the 

prevention or minimization of the consequences of the accidental release of acutely hazardous 

chemicals.69 These regulations require that covered employers perform a PHA to identify, 

evaluate and control hazards involved in the process using recognized methodologies.70

75. California regulations, however, do not provide for a specific review of the effectiveness of the 

proposed safeguards to control the hazards identified in the PHA using recognized 

methodologies such as Layers of Protection Analysis (LOPA).71

76. The Energy Institute, an industry technical working group

Additionally, California 

regulations do not have any requirements for the use of inherently safer systems analysis and the 

hierarchy of controls for establishing safeguards for identified process hazards. Cal/OSHA, like 

federal OSHA, also does not require damage mechanism hazard reviews as part of the PHA 

process. 

ii organized in the United Kingdom 

(UK), with contributions from regulators including the UK’s Health and Safety Executive 

(HSE),iii as well as other entities,iv developed a document in 2008v that provides guidance on 

damage mechanism hazard reviews in the UK’s offshore petrochemical industry. The guidance 

states that effective management of corrosion will contribute to equipment integrity and reduce 

risk from safety and environmental hazards.72 In addition, during the design of a process, a 

corrosion review can be used to eliminate risks and achieve inherent safety.73

 i

This is also the case for US EPA Risk Management Program and the California Accidental Release Prevention 

Program regulations.

 The guidance also 

iiThe Energy Institute is the leading chartered professional membership body supporting individuals and 

organizations across the energy industry. With a combined membership of over 13,500 individuals and 300 

companies in 100 countries, it provides an independent focal point for the energy community and a powerful voice 

to engage business and industry, government, academia and the public internationally. See 

http://www.energyinst.org/about-us (accessed April 17, 2013). iii HSE is an independent regulator that is tasked with securing the health, safety and welfare of workers within the 

UK. See http://www.hse.gov.uk/aboutus/index.htm (accessed April 17, 2013). 

iv Chevron Energy Technology Company (ETC) was one of roughly 30 entities recognized in the guidance 

document as providing contributions to the institute that were “key to the development of this publication...”. See 

http://www.energyinstpubs.org.uk/pdfs/815.pdf (accessed April 17, 2013). v Ibid. 
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49 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

notes that damage mechanism hazard reviews should provide a structured framework for 

identifying risks associated with corrosion and developing suitable risk reduction measures.74

These reviews should cover failure mechanisms including, but not limited to corrosion, 

environmental cracking, erosion, and mechanical damage, such as vibration induced fatigue.75

Finally, this guidance states that a formal, documented quantitative and logic based assessment

should be used when conducting corrosion reviews.

76

77. Under a rule issued by the U.S. Environmental Protection Agency (EPA),

77 a facility with a 

tank, drum, pipe, or other processi

that contains an extremely hazardous toxic or flammable 

substance listed at 40 CFR §68.130 in an amount above the “threshold quantity” specified for 

that substance, is required to conduct a hazard assessment as well as develop a prevention 

program and an emergency response program. These requirements are documented in a Risk 

Management Plan (RMP) that is submitted to EPA. Covered facilities must implement the RMP 

and update their RMPs periodically or when certain changes occur. The goal of EPA’s Risk 

Management Program is to prevent accidental releases of substances that can cause serious harm 

to the public and the environment from short-term exposures, and to mitigate the severity of 

releases that do occur.78

78. The EPA RMP program provisions build on the planning and preparedness groundwork laid by 

the Emergency Planning and Community Right-to-Know Act of 1986 (EPCRA). EPCRA 

establishes requirements for federal, state, and local governments, as well as industry, regarding 

emergency planning and “Community Right-to-Know” reporting on hazardous toxic chemicals.

EPCRA “help[s] increase the public’s knowledge and access to information on chemicals at 

individual facilities, their uses, and releases into the environment.”79 According to the U.S. 

EPA’s Chemical Emergency Preparedness and Prevention Office,ii

Both EPCRA and the CAA [Clean Air Act] section 112(r) Risk 

Management Program encourage communication between facilities and 

the surrounding communities about chemical safety and chemical risks.

Regulatory requirements, by themselves, will not guarantee safety from 

chemical accidents. Information about hazards in a community will 

allow local emergency officials and the public to work with industry to 

prevent accidents.

transparency between 

industry and the public will improve community safety:

80

 i

“Process” means “any activity involving a regulated substance including any use, storage, manufacturing, handling, 

or on-site movement of such substances, or combination of these activities...” 40 CFR §68.3 (1997). ii In 2004, the U.S. EPA’s Chemical Emergency Preparedness and Prevention Office was merged with the Superfund 

Emergency Response Program and Oil Spill Prevention Program to form the Office of Emergency Management, or 

OEM. OEM works with other EPA partners, federal, state, and local agencies, and industry to prevent accidents and 

maintain and provide superb response capabilities. See http://www.epa.gov/oem/about.htm (accessed April 17, 

2013). 
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The CCPS also notes that governments and advocacy organizations have been 

successful in driving performance improvement by using public disclosure to 

make safety information available to the public.81

79. Under the RMP program’s hazard assessment requirement, a facility must prepare a worst-case 

release scenario analysis82 and complete a five-year accident history.83 A covered facility must 

also develop and implement an emergency response program that includes procedures for 

informing the public and local agencies about accidental releases and procedures and measures 

for emergency response after an accidental release.84

80. Workforce involvement is a key element of process safety and effective chemical accident 

prevention. In the Center for Chemical Process Safety publication, Guidelines for Risk Based 

Process Safety, it lists workforce involvement as one of 20 essential management systems 

necessary to reduce process safety risks and prevent chemical accidents.

Officials and the public, including local 

emergency planning committees (LEPCs) can use this information to understand the chemical 

hazards in the community and then work with industry to address and mitigate those 

hazards. With both EPCRA and the Risk Management Program, the regulatory purpose and 

substantive provisions emphasize the importance of transparency, sharing of process safety data, 

and public participation to prevent chemical accidents. The CSB notes that post-incident, during 

the decision-making related to piping repairs to the crude unit, the public, worker 

representatives, regulators, and governmental bodies played a key role driving transparency, 

accountability, and improved risk reduction. 

85

...workers are potentially the most knowledgeable people with respect to 

the day-to-day details of operating the process and maintaining the 

equipment and facilities and may be the sole source for some types of 

knowledge gained through their unique experiences. Workforce 

involvement provides management a mechanism for tapping into this 

valuable expertise.

 CCPS states that:

86

This CCPS publication discusses general areas of workforce involvement in risk assessments, 

inspections, audits, and performance reviews. The CCPS notes that participation leads to 

empowerment, management responsiveness, and process safety performance improvement.

87

The OSHA PSM Standard emphasizes the importance of participation by workers and their 

representatives. It requires employers to develop a written plan of action, consult with 

employees, and make available all process safety information. 88 In previous investigation 

reports, the CSB has identified that workers and their representatives play a very important role 

in major incident prevention. For example, in the BP Texas City oil refinery investigation

report, the CSB recommended that BP and the United Steelworkers International Union (USW) 

establish a joint program to report incidents and near misses, and to ensure that 

recommendations made during investigations were implemented. The CSB also recommended 
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51 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

that API and the USW work together to develop a safety standard addressing leading and 

lagging process safety indicators. i

81. In July 2012, the CSB held a public hearing on process safety indicatorsii to explore how 

companies and regulators use process safety metrics to manage risks and drive continuous safety 

improvements. During this hearing the CSB stated that, following the 2005 BP Texas City 

accident, both the CSB and Baker Paneliii

82. Process safety management systems are critical for reducing process safety incidents. Process 

safety indicators are a significant element of these systems. Indicators measure the strengths and 

weaknesses of process safety management systems, to achieve and maintain safe and reliable 

operations.

reports noted the lack of focus by BP on process safety 

and inadequate performance measurement indicators. The CSB also noted that one goal of 

process safety indicators is to drive continuous process safety improvement, and that regulators

can utilize these indicators to focus inspections, audits, and investigations. 

89 Properly selected and managed indicators will identify the successes and point out 

the flaws of the system.90

83. In 2008, the CCPS published a guidance document for the development of leadingiv and laggingv

process safety indicators to assist industry in avoiding catastrophic chemical incidents.91 While 

process safety indicators are an important tool for major accident prevention, the simple activity 

of identifying and recording process safety metrics will not drive process safety improvement. 

CCPS notes that these metrics must be “collected, analyzed, communicated, understood, and 

acted upon.”92

84. The UK HSE has published a guidance document to help chemical and major hazard industries 

develop process safety indicators. HSE states that: 

 

Most systems and procedures deteriorate over time, and system 

failures discovered following a major incident frequently 

surprise senior managers, who sincerely believed that the 

controls were functioning as designed. Used effectively, process 

 i

Process safety indicators are also referred to as safety performance indicators, metrics, key process indicators 

(KPI), performance measures, indicators, etc... ii See http://www.csb.gov/assets/1/19/CSB_20Public_20Hearing.pdf (accessed April 17, 2013). 

iii See http://www.bp.com/liveassets/bp_internet/globalbp/globalbp_uk_english/SP/STAGING/local_assets/assets/pd

fs/Baker_panel_report.pdf (accessed April 12, 2013).

iv Leading indicators are measurements that predict future performance to ensure that safety protection layers and 

operating discipline are being maintained, including unsafe behaviors or insufficient operating discipline equipment 

selection, engineering design, specification of inspection frequency, and technique. See Center for Chemical 

Process Safety (CCPS), Guidelines for Process Safety Metrics, Page 20. 2010. v Lagging indicators are facts about previous events, such as process safety incidents, that meet the threshold of 

severity and should be reported as part of the process safety metric. See Center for Chemical Process Safety

(CCPS), “Guidelines for Process Safety Metrics,” 2010; Page 20.
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52 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

safety indicators can provide an early warning, before 

catastrophic failure, that critical controls have deteriorated to an 

unacceptable level. 93

85. The public can play an important role in monitoring safety management systems. In its recent 

guidelines, the CCPS promoted the sharing of process safety indicators with the public:

Sharing performance metrics and results broadly can engage the 

public as a partner in holding the organization accountable for 

process safety performance. Making metrics and performance 

public can be an especially powerful way of maintaining upper 

management commitment since it will likely be the CEO or other 

senior managers who will be called to account by the public if 

goals are not met or performance declines. Communicating 

process safety successes also demonstrates to employees and the 

public that positive change can be, and are being, made within an 

organization. 94
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Recommendations

Under 42 U.S.C. 7412(r)(6)(C)(ii), the U.S. Chemical Safety and Hazard Investigation Board is charged 

with “recommending measures to reduce the likelihood or the consequences of incidental releases and 

proposing corrective steps to make chemical production, processing, handling and storage as safe and free 

from risk of injury as possible ....” The CSB makes recommendations based on the findings and 

conclusions of the investigation. Recommendations are made to parties that can affect change to prevent 

future incidents, which may include the company, contractors, industry organizations responsible for 

developing good practice guidelines, regulatory bodies, and/or organizations that have the ability to 

broadly communicate lessons learned from the incident, such as trade associations or professional 

societies.

Chevron U.S.A (Urgent)

2012-03-I-CA-R1

At all Chevron U.S. refineries, engage a diverse team of qualified personnel to perform a documented 

damage mechanism hazard review. This review shall be an integral part of the Process Hazard Analysis

cycle and shall be conducted on all PSM-covered process piping circuits and process equipment. The 

damage mechanism hazard review shall identify potential process damage mechanisms and consequences 

of failure, and shall ensure safeguards are in place to control hazards presented by those damage 

mechanisms. Analyze and incorporate into this review applicable industry best practices, Chevron 

Energy Technology Company findings and recommendations, and inherently safer systems to the greatest 

extent feasible. 

2012-03-I-CA-R2

At all California Chevron U.S. refineries, report leading and lagging process safety indicators, such as the 

action item completion status of recommendations from damage mechanism hazard reviews, to the 

federal, state, and local regulatory agencies that have chemical release prevention authority.
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Mayor and City Council, 

City of Richmond, California

2012-03-I-CA-R3

Revise the Industrial Safety Ordinance (ISO) to require that Process Hazard Analyses include

documentation of the recognized methodologies, rationale and conclusions used to claim that safeguards

intended to control hazards will be effective. This process shall use established qualitative, quantitative, 

and/or semi-quantitative methods such as Layers of Protection Analysis (LOPA). 

2012-03-I-CA-R4

Revise the Industrial Safety Ordinance (ISO) to require the documented use of inherently safer systems 

analysis and the hierarchy of controls to the greatest extent feasible in establishing safeguards for 

identified process hazards. The goal shall be to drive the risk of major accidents to As Low As 

Reasonably Practicable (ALARP). Include requirements for inherently safer systems analysis to be 

automatically triggered for all Management of Change and Process Hazard Analysis reviews, prior to the 

construction of new processes, process unit rebuilds, significant process repairs, and in the development 

of corrective actions from incident investigation recommendations.

2012-03-I-CA-R5

Ensure the effective implementation of the damage mechanism hazard review program (2012-03-I-CAR1 and 2012-03-I-CA-R2), so that all necessary mechanical integrity work at the Chevron Richmond 

Refinery is identified and recommendations are completed in a timely way.
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Board of Supervisors

Contra Costa County, California

2012-03-I-CA-R6

Revise the Industrial Safety Ordinance (ISO) to require that Process Hazard Analyses include

documentation of the recognized methodologies, rationale and conclusions used to claim that safeguards

intended to control hazards will be effective. This process shall use established qualitative, quantitative, 

and/or semi-quantitative methods such as Layers of Protection Analysis (LOPA). 

2012-03-I-CA-R7

Revise the Industrial Safety Ordinance (ISO) to require the documented use of inherently safer systems 

analysis and the hierarchy of controls to the greatest extent feasible in establishing safeguards for 

identified process hazards. The goal shall be to drive the risk of major accidents to As Low As 

Reasonably Practicable (ALARP). Include requirements for inherently safer systems analysis to be 

automatically triggered for all Management of Change and Process Hazard Analysis reviews, prior to the 

construction of new processes, process unit rebuilds, significant process repairs, and in the development 

of corrective actions from incident investigation recommendations.

2012-03-I-CA-R8

Monitor and confirm the effective implementation of the damage mechanism hazard review program 

(2012-03-I-CA-R1 and 2012-03-I-CA-R2), so that all necessary mechanical integrity work at the Chevron 

Richmond Refinery is identified and recommendations are completed in a timely way. 
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California State Legislature, 

Governor of California

2012-03-I-CA-R9

Revise the California Code of Regulations, Title 8, Section 5189, Process Safety Management of Acutely 

Hazardous Materials, to require improvements to mechanical integrity and process hazard analysis 

programs for all California oil refineries. These improvements shall include engaging a diverse team of 

qualified personnel to perform a documented damage mechanism hazard review. This review shall be an

integral part of the Process Hazard Analysis cycle and shall be conducted on all PSM-covered process 

piping circuits and process equipment. The damage mechanism hazard review shall identify potential 

process damage mechanisms and consequences of failure, and shall ensure safeguards are in place to 

control hazards presented by those damage mechanisms. Require the analysis and incorporation of 

applicable industry best practices and inherently safety systems to the greatest extent feasible into this

review. 

2012-03-I-CA-R10

For all California oil refineries, identify and require the reporting of leading and lagging process safety 

indicators, such as the action item completion status of recommendations from damage mechanism hazard 

reviews, to state and local regulatory agencies that have chemical release prevention authority. These 

indicators shall be used to ensure that requirements described in 2012-03-I-CA-R9 are effective at 

improving mechanical integrity and process hazard analysis performance at all California oil refineries 

and preventing major chemical incidents. 

2012-03-I-R11

Establish a multi-agency process safety regulatory program for all California oil refineries to improve the 

public accountability, transparency, and performance of chemical accident prevention and mechanical 

integrity programs. This program shall:

1. Establish a system to report to the regulator the recognized methodologies, findings, conclusions 

and corrective actions related to refinery mechanical integrity inspection and repair work arising 

from Process Hazard Analyses, California oil refinery turnarounds and maintenance-related 

shutdowns;

2. Require reporting of information such as damage mechanism hazard reviews, notice of upcoming 

maintenance-related shutdowns, records related to proposed and completed mechanical integrity 

work lists, and the technical rationale for any delay in work proposed but not yet completed; 
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57 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

3. Establish procedures for greater workforce and public participation including the public reporting 

of information; and

4. Provide mechanisms for federal, state and local agency operational coordination, sharing of data

(including safety indicator data), and joint accident prevention activities. The California 

Department of Industrial Relations will be designated as the lead state agency for establishing a 

repository of joint investigative and inspection data, coordinating the sharing of data and joint 

accident prevention activities.

2012-03-I-CA-R12

Require that Process Hazard Analyses required under California Code of Regulations, Title 8, Section 

5189 Section (e) include documentation of the recognized methodologies, rationale and conclusions used 

to claim that safeguards intended to control hazards will be effective. This process shall use established 

qualitative, quantitative, and/or semi-quantitative methods such as Layers of Protection Analysis (LOPA). 

2012-03-I-CA-R13

Require the documented use of inherently safer systems analysis and the hierarchy of controls to the 

greatest extent feasible in establishing safeguards for identified process hazards. The goal shall be to 

drive the risk of major accidents to As Low As Reasonably Practicable (ALARP). Include requirements 

for inherently safer systems analysis to be automatically triggered for all Management of Change and

Process Hazard Analysis reviews, prior to the construction of new process, process unit rebuilds, 

significant process repairs and in the development of corrective actions from incident investigation 

recommendations.

2012-03-I-CA-R14

Monitor and confirm the effective implementation of the damage mechanism hazard review program 

(2012-03-I-CA-R9 and 2012-03-I-CA-R10), so that all necessary mechanical integrity work at all 

California Chevron Refineries is identified and recommendations are completed in a timely way. 
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The U.S. Environmental Protection Agency

2012-03-I-CA-R15

Jointly plan and conduct inspections with Cal/OSHA, California EPA and other state and local regulatory 

agencies with chemical accident prevention responsibilities to monitor the effective implementation of the 

damage mechanism hazard review and disclosure requirements under 2012-03-I-CA-R9 and R10 above. 

The Board of Supervisors, Contra Costa County, California, 2012-03-I-CA-R16;

The Mayor and City Council, City of Richmond, California, 2012-03-I-CA-R17;

The California Air Quality Management Divisions, 2012-03-I-CA-R18;

The U.S. Environmental Protection Agency, 2012-03-I-CA-R19; and

The California Environmental Protection Agency, 2012-03-I-CA-R20;

Participate in the joint regulatory program described in recommendation 2012-03-I-CA-R11. This 

participation shall include contributing relevant data to the repository of investigation and inspection data 

created by the California Department of Industrial Relations and jointly coordinating activities.
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Additional Issues Currently Under Investigation

The following section highlights additional issues which the CSB has identified to date in its investigation 

of the Chevron Richmond Refinery fire and major hydrocarbon release that occurred on August 6, 2012.

These issues relate to the ongoing CSB investigation of the management and regulation of health and 

safety at refineries. The CSB final report will make additional recommendations consistent with this 

interim report and will present additional detailed findings and analyses in a final report on the incident, 

to be released later in 2013.

Regulatory Oversight

The CSB noted in its BP Texas City (BPTC) Final Investigation Report (issued in March 2007) the 

importance of having a well-resourced, competent regulator consisting of individuals with the necessary 

training, education, and experience to conduct planned comprehensive and robust inspections of facilities 

with the goal of preventing catastrophic accidents. In a 1992 compliance directivei

the federal 

Occupational Safety and Health Administration (OSHA) stated that the primary enforcement model for 

the Process Safety Management of Highly Hazardous Chemicals (PSM) standard would be planned, 

comprehensive, and resource-intensive Program Quality Verification (PQV) inspections to help prevent 

catastrophic accidents.95

Spurred in part by the CSB’s recommendations, OSHA issued the Petroleum Refinery Process Safety 

Management National Emphasis Program (NEP) on June 7, 2007.

However, the CSB report noted that for the 10-year period prior to the Texas 

City incident, federal OSHA had conducted no planned PQV inspections in oil refineries. Regular 

planned inspections appropriately emphasize the prevention of accidents that are potentially catastrophic.

Issuing fines and prosecuting companies post-incident are not acceptable substitutes for prevention. As a 

result, CSB recommended in its report that OSHA strengthen the planned enforcement of the OSHA 

Process Safety Management (PSM) standard by developing more highly trained and experienced 

inspectors to conduct more comprehensive inspections similar to those under OSHA’s PQV program at 

facilities presenting the greatest risk of a catastrophic accident.

ii The NEP was a federal program that 

established guidelines for inspecting petroleum refineries to assure compliance with the PSM standard, 29 

CFR §1910.119.96 Unlike the PQV approach to inspections, which “employs a broad, open-ended 

inspection strategy and uses a more global approach to identify compliance deficiencies...,”97 the NEP 

“provide[d] a specific tool to evaluate compliance with the [PSM] standard...[which] identifies a 

particular set of requirements from the PSM standard from which CSHOs [Compliance Safety and Health 

Officers] are to review documents, interview employees, and verify implementation for specific 

processes, equipment, and procedures.”98

 i

Compliance directives are the main method OSHA uses to communicate plans, inspection methods, and 

compliance expectations to their Compliance Safety and Health Officers (CSHOs) for enforcing a new regulation. 

While the CSB called for an ongoing comprehensive inspection 

ii Originally Directive Number CPL 03-00-004. Extended August 18, 2099 as Directive Number CPL 03-00-010 to 

allow more time to complete NEP inspections under the original CPL 03-00-004.
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60 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

program, inspections being conducted pursuant to the NEP were terminated in 2011. The CSB 

recommendation to OSHA remains Open.

i

OSHA State Plan Statesii were strongly encouraged but not required to implement the NEP. California’s 

Division of Occupational Safety and Health (Cal/OSHA) did not adopt the NEP “because of its dedicated 

PSM Unit.”99 Cal/OSHA informed the CSB that federal OSHA approved this decision in 2007. In lieu of 

conducting NEP inspections, Cal/OSHA’s PSM Unit has conducted and continues to conduct a full range 

of programmed, accident, complaint, and referral inspections of PSM-covered facilities in the state of 

California pursuant to the California Labor Code, Title 8 regulations, and Cal/OSHA’s Policy and 

Procedures (P&P) Manual C-17 “Process Safety Management,”iii

Between 2006 and August 6, 2012, Cal/OSHA conducted three planned inspections of the Chevron 

Richmond facility, totaling only 150 inspector hours of effort. None of these inspections resulted in 

citations or fines. In contrast, according to statistics provided by OSHA, federal NEP refinery inspections 

conducted between 2007 and the end of 2011 lasted roughly 1,000 inspector hours each and resulted in an 

average of 11.2 violations and $76,821 in penalties per inspection. OSHA noted that hours spent on a 

typical federal refinery NEP inspection were 40 times greater than the average OSHA inspection. These 

numbers indicate a major disparity in thoroughness and comprehensiveness between the planned

inspections conducted by Cal/OSHA and the NEP inspections conducted by OSHA and other OSHA 

State Plan States.

to ensure these facilities are complying 

with PSM requirements. 

The safety case is a rigorous prescriptive and goal-setting regulatory regime that is highlighted by its 

adaptability and requirements for continuous improvements in risk reduction for high hazard industrial 

facilities. The approach is used widely overseas but is not used currently for U.S. process industries. The 

CSB is currently examining whether the implementation of the safety case regime could be a more 

effective regulatory tool for Cal/OSHA in its effort to ensure that California refineries are identifying and 

controlling hazards and ultimately driving risk to as low as reasonably practicable (ALARP). Utilizing 

the safety case requires effective implementation by an independent, competent, well-funded regulator. 

Experience and competence of the regulator in technical areas such as chemical engineering, human 

factors, and process safety are necessary to provide effective auditing and regulatory oversight for 

prevention. To ensure effective implementation of the safety case, industry standards and guidelines must 

be rigorous and up-to-date as well. The CSB notes that relevant and applicable industry standards and 

guidelines – such as API RP 939-C – currently contain voluntary and permissive language. The CSB will 

be examining the need for more effective good practice standards and guidelines containing the necessary 

requirements to prevent catastrophic accidents. 

 i

Open - Awaiting Response or Evaluation/Approval of Response (O - ARE/AR) - The recipient has not submitted a 

substantive response, or the evaluation by CSB staff of a response is pending, or the Board has not yet acted on staff 

recommendation of status. ii Section 18 of the Occupational Safety and Health Act of 1970 encourages States to develop and operate their own 

job safety and health programs, referred to informally as an OSHA State Plan. OSHA approves and monitors State 

plans and provides up to 50 percent of an approved plan's operating costs. iii Issued June 6, 1994. Revised August 1, 1994 and May 19, 2007.
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61 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

In addition to the issues discussed above, the CSB will also be examining the need for the reporting of 

leading and lagging process safety indicators to the regulator; the regulator’s effective use of these 

process safety indicators; workforce and stakeholder involvement in regulatory oversight of refineries; 

and the thoroughness of Contra Costa County’s safety auditing of the Chevron facility.

Emergency Planning and Reporting

According to information provided by Contra Costa Emergency Medical Services, 15,213 individuals 

sought emergency medical attention between August 6 and August 23, 2012, due to the Chevron refinery 

major hydrocarbon release and fire. 

CSB Investigation Team members visited local hospitals the week of the incident to better understand the 

impact on the surrounding community. Officials at Doctor’s Medical Center (DMC) in San Pablo, 

California, informed the CSB that in the days following the incident they were inundated with emergency 

room visits and found it difficult to handle the influx due to a lack of funding and staffing. Officials at 

both DMC and Kaiser Permanente Hospital (KP) in Richmond told the CSB that they lacked specific 

knowledge of the chemicals released as a result of the incident, complicating efforts to evaluate and treat 

individuals. 

The California Code of Regulations (CCR) requires that owners and operators of hazardous waste 

facilities make “arrangements to familiarize local hospitals with the properties of hazardous waste 

handled at the facility and the types of injuries or illnesses which could results from fires, explosions, or 

releases at the facility.”100

Following the incident, Contra Costa County’s Community Warning System (CWS) notified the 

surrounding community of a hazardous material incident and ordered a shelter-in-place (SIP). The CWS 

uses sirens, the news media, and phone calls to residents in order to initiate the SIP. Contra Costa County 

issued the SIP on August 6, 2012, at 6:38 pm for the cities of Richmond, San Pablo, and North 

Richmond, California, and lifted the SIP later that evening at 11:12 pm. However, the CSB has learned 

that some phone calls notifying residents of the SIP did not occur until over four hours after the release.

 The CSB is currently evaluating ways to ensure that hospitals have the 

information necessary to properly evaluate and treat individuals that may be exposed to releases from 

facilities in Contra Costa County. 

It is essential that responders, community residents, and hospitals in the areas surrounding industrial 

facilities be aware of what hazardous materials exist at these facilities, what specific chemicals are 

released into the community in the event of an incident, and what is known about the potential acute and 

chronic health impacts. The CSB will be analyzing ways to strengthen current regulations and policies to 

ensure there is proper emergency planning and reporting for industrial facilities in Contra Costa County

and the state of California.
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Emergency Response

OSHA provides guidance on emergency response in its Hazardous Waste Operations and Emergency 

Response standard, known as HAZWOPER, under 29 CFR §1910.120 (p) and (q). Under 29 CFR 

§1910.120(q)(6), the HAZWOPER standard contains requirements for training and qualification of all 

individuals involved in emergency response related to their roles and responsibilities.

Good safety practice dictates that individuals responding to emergencies should have the technical 

knowledge to give input into shutdown decisions, set up an incident command structure, establish 

boundary limits, and evaluate the “hot zone.” Access to the hot zone must be strictly limited to personnel 

with higher degrees of specific training, experience, and appropriate personal protective equipment; all 

others must be removed to a safe location away from chemical hazards. Hot zone boundaries must be 

established to anticipate the possible escalation of releases and the positioning of firefighting equipment 

such as fire trucks.

The CSB will be looking at the sufficiency of regulatory requirements, industry standards, and good 

practices, in addition to evaluating emergency response decision-making following the leak and 

subsequent pipe rupture (including the training and qualification of responders) to determine whether 

improvements are needed in these areas.

Safety Culture

The Center for Chemical Process Safety (CCPS) defines process safety culture as the “combination of 

group values and behaviors that determines the manner in which process safety is managed.”101

The CSB notes that on August 6, 2012, following discovery of the leak on the 4-sidecut piping, Chevron 

hoped to forestall a shutdown by installing a leak repair clamp.

As the 

CSB noted in its BP Texas City Report, safety culture can be influenced by management changes, 

historical events, and economic pressures. After reviewing evidence and decisions made relating to 

materials of construction and mechanical integrity within the crude unit at the Chevron refinery, as well 

as the response to the leak on August 6, 2012, the CSB has determined that issues relating to safety 

culture are relevant to this incident. The CSB will examine the Chevron Richmond Refinery’s approach 

to safety, its safety culture and any organizational deficiencies, to determine how to best prevent future 

incidents.

i

 Chevron’s mechanical integrity 

management system has not been fully successful in detecting and replacing deteriorated piping 

components prior to failure, resulting in the company’s frequent use of leak repair clampsii

 i

Chevron’s leak repair clamp vendor was called out to the scene of the leak to help determine potential clamping 

options.

to externally 

stop process fluid leaks. Chevron’s reliance on such clamps to mitigate process piping component leaks 

identifies serious questions about its mechanical integrity program. The CSB determined that Chevron 

ii Leak repair clamps are mechanical devices designed and installed to stop a leak from a piping component such as 

piping, valves, flanges, and instrumentation. These devices are typically intended to provide a temporary repair 

while a process continues operation until a plant shutdown takes place and a permanent repair can be made.
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63 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

has more than 100 clamps on hydrocarbon and other process piping components at the Richmond 

refinery. The leak repair clamp is typically relied upon to prevent further leaking until the next unit 

turnaround, when the deteriorated piping component can be repaired. However, Cal/OSHA citations 

following the August 6, 2012, fire in the crude unit identified that Chevron has not always replaced these

clamps during unit turnarounds and these devices then remain in service significantly longer than 

originally intended. The CSB determined that Chevron has leak repair clamps in place on piping 

components containing hazardous flammable process fluids including applications where the process 

material is above the autoignition temperature. Some of these leak repair clamp applications are in 

locations where a permanent repair would not have required a unit shutdown. The CSB will further 

evaluate the frequent use of leak repair clamps by Chevron and the potential that the deviance of a weak 

mechanical integrity management system has been normalized.

i

 i

Normalization of deviance is a long-term phenomenon in which individuals or work teams gradually accept a lower 

standard of performance until the lower standard becomes the norm. It is typically the result of conditions slowly 

changing and eroding over time. See Center for Chemical Process Safety (CCPS), Recognizing Catastrophic 

Incident Warning Signs in the Process Industries, Page 4. 2012.
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64 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

BY THE

U.S. Chemical Safety and Hazard Investigation Board

Rafael Moure-Eraso

Chair

Mark Griffon

Member 

Beth Rosenberg

Member

Date of Approval April __, 2013. 
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65 U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

References

1. Chevron U.S.A. Inc. "30 Day Follow-Up Notification Report." September 5th, 2012.

2. KTVU roof cam footage. See http://www.ktvu.com/videos/news/ktvu-timelapse-exclusive-timelapsevideo-of-smoke/vdCJ7/ (accessed April 10, 2013).

3. Anamet, Inc. "Metallurgical Evaluation of Samples from the Chevron U.S.A. Inc., Richmond #4 Crude 

Unit 8-Inch and 12-Inch 4-Sidecut Piping Involved in the August 6, 2012, Hydrocarbon Release and 

Fire." Prepared for: The Chemical Safety and Hazard Investigation Board (CSB), February 11, 2013. 

4. API RP 939-C. "Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries.” 

1st ed., Section 4, May 2009. 

5. Ibid at Section 3.1.6. 

6. Ibid at Section 6.2.2.1. 

7. NACE International Task Group 176. "Overview of Sulfidic Corrosion in Petroleum Refining." NACE 

International Publication 34103. Item No. 24222, 2004.

8. API RP 939-C. "Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries.” 

1st ed., May 2009. 

9. Ibid.

10. ASTM Standard A53/A53M-12. "Standard Specification for Pipe, Steel, Black and Hot-Dipped, ZincCoated, Welded and Seamless." 2012.

11. Niccolls, E. H., J. M. Stankiewicz, J. E. McLaughlin, and K. Yamamoto. "High Temperature 

Sulfidation Corrosion in Refining." 17th International Corrosion Congress. Las Vegas: NACE 

International, 2008.

12. API RP 939-C. "Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries.” 

1st ed., Section 6.2.3.2, May 2009. 

13. API Publication 943. “High-Temperature Crude Oil Corrosivity Studies.” September 1974.

14. ASTM Standard A53/A53M-12. "Standard Specification for Pipe, Steel, Black and Hot-Dipped, ZincCoated, Welded and Seamless." 2012.

15. ASTM Standard A106/A106M–11."Standard Specification for Seamless Carbon Steel Pipe for HighTemperature Service." 2011. 

16. API Specification 5L. "Specification for Line Pipe." 45th ed., December 2012.

17. ASTM Standard A53/A53M-12. "Standard Specification for Pipe, Steel, Black and Hot-Dipped, ZincCoated, Welded and Seamless." 2012.

18. http://www.eia.gov/tools/faqs/faq.cfm?id=29&t=6 (accessed February 14, 2013).
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19. Anamet, Inc. "Metallurgical Evaluation of Samples from the Chevron U.S.A. Inc., Richmond #4 

Crude Unit 8-Inch and 12-Inch 4-Sidecut Piping Involved in the August 6, 2012, Hydrocarbon 

Release and Fire." Prepared for: The Chemical Safety and Hazard Investigation Board (CSB), 

February 11, 2013. 

20. API RP 939-C. "Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries." 

1st ed., Section 7.1.5, May 2009.

21. Ibid.

22. Ibid.

23. Ibid.

24. Ibid at Section 9.

25. Ibid at Section 7.1.5.

26. Ibid at Section 6.2.3.2.

27. Ibid at Section 7.1.5.

28. Ibid at Section 9.

29. Ibid at Section 9.

30. API RP 571. “Damage Mechanisms Affecting Fixed Equipment in the Refining Industry.” 2nd ed., 

April 2011. 

31. Center for Chemical Process Safety (CCPS). “Layer of Protection Analysis – Simplified Process Risk 

Assessment.” 2001. 

32. Division of Occupational Safety and Health, State of California, Citation of Notification of Penalty, 

Inspection Number 314331877, CSHO ID A0572, Citation 4 Item 1, January 30, 2013.

33. http://www.opportunitycrudes.com/marketupdates/index.php?topics=opcrudetypes (accessed 

February 14, 2013).

34. API RP 939-C. “Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries." 

1st ed., Section 4, May 2009.

35. API 570. "Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration of Piping 

Systems." 3rd ed., Section 4.3.1.2, November 2009.

36. www.aiche.org/ccps/about (accessed February 14, 2013).

37. www.aiche.org/ccps/community/members (accessed February 14, 2013).

38. Center for Chemical Process Safety (CCPS). “Inherently Safer Chemical Processes – A Life Cycle 

Approach.” 2nd ed., Section 2.2, 2009. 
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39. Ibid at Section 5.1.1. 

40. Ibid at Section 5.2.

41. Ibid at Page 184.

42. Kletz, Trevor, and Paul Amyotte. “Process Plants: A Handbook for Inherently Safer Design.” 2nd 

ed., Section 1.1, Page 14, 2010.

43. API RP 939-C. “Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries." 

1st ed., May 2009.

44. Center for Chemical Process Safety (CCPS). “Inherently Safer Chemical Processes – A Life Cycle 

Approach.” 2nd ed., Page 21, 2009. 

45. Ibid at Page 11.

46. Ibid.

47. Ibid at Page 26.

48. Ibid at Page 46.

49. Ibid at Page 27.

50. Ibid at Page 26.

51. Ibid at Page 80

52. http://cchealth.org/hazmat/iso/faq.php (accessed February 14, 2013).

53. City of Richmond Municipal Code Chapter 6.43, RISO. December 18, 2001. 

http://www.ci.richmond.ca.us/archives/66/113%20N.S.%20amending%20Richmond%20Municipal

%20Code%20Chapter%206.43%20to%20improve%20industrial%20safety-conformed.pdf (accessed 

April 11, 2013).

54. http://cchealth.org/hazmat/iso/ (accessed April 11, 2013).

55. City of Richmond Municipal Code Chapter 6.43, RISO. Section 6.43.060 “Administration” December 

18, 2001. http://www.ci.richmond.ca.us/archives/66/113%20N.S.%20amending%20Richmond%20

Municipal%20Code%20Chapter%206.43%20to%20improve%20industrial%20safety-conformed.pdf

(accessed April 11, 2013).

56. Contra Costa County, California, Ordinance Code. Title 4 – Health and Safety. Division 450 –

Hazardous Materials and Wastes. Chapter 450-8: Risk Management. Section 450-8.014 

“Definitions” (2010). http://library.municode.com/index.aspx?clientId=16286 (accessed February 

15, 2013). See also City of Richmond Municipal Code §6.43.050(g) (February 5, 2013). 

57. Ibid at Section 450-8.016 subpart (d)(3) “Process Hazard Analysis/Action Items.” See also City of 

Richmond Municipal Code §6.43.090(d)(3) (February 5, 2013). 
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58. Ibid.

59. Ibid.

60. Ibid.

61. Ibid.

62. Ibid.

63. Contra Costa County Industrial Safety Ordinance Guidance Document. Section D: Process Hazard 

Analysis / Action Items. Subpart D.1.3. Process Hazard Analysis Recommendations and 

Mitigations. Published June 15, 2011. http://cchealth.org/hazmat/pdf/iso/section_d.pdf (accessed 

March 20, 2013). 

64. Ibid at Subpart D.1. Inherently Safer Systems. 

65. Ibid.

66. http://www.dir.ca.gov/dosh/enforcementpage.htm (accessed February 15, 2013). 

67. Ibid.

68. 29 CFR §1910.119 – Process Safety Management of Highly Hazardous Chemicals (2002).

69. California Code of Regulations. Title 8. Section 5189 - Process Safety Management of Acutely 

Hazardous Materials http://www.dir.ca.gov/title8/5189.html (accessed February 15, 2013). 

70. Ibid at (e)(1). 

71. Layer of Protection Analysis: Simplified Process Risk Assessment. Center for Chemical Process 

Safety of the American Institute of Chemical Engineers. 2001.

72. Energy Institute. “Guidance for Corrosion Management in Oil and Gas Production and Processing.” 

Section 1.1, May 2008. 

73. Ibid at Section 4.2.

74. Ibid. 

75. Ibid at Section 1.2.3.

76. Ibid at Section 4.3. 

77. 40 CFR Part 68, known as the “Chemical Accident Prevention Provisions.”

78. U.S. Environmental Protection Agency, “General Guidance on Risk Management Programs for 

Chemical Accident Prevention (40 CFR Part 68).” Page i. March 2009.

http://www.epa.gov/oem/docs/chem/Intro_final.pdf (accessed April 3, 2013).

79. http://www.epa.gov/oem/content/lawsregs/epcraover.htm (accessed April 3, 2013).
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80. Chemical Emergency Preparedness and Prevention Office, “RMPs Are on the Way! How LEPCs and 

Other Local Agencies Can Include Information from Risk Management Plans in Their Ongoing 

Work.” November 1999. http://www.epa.gov/osweroe1/docs/chem/lepc-rmp.pdf (accessed April 

17, 2013). 

81. Center for Chemical Process Safety (CCPS), Guidelines for Process Safety Metrics, Page 103. 2010.

82. 40 CFR §68.25. 1999.

83. 40 CFR §68.42. 1999.

84. 40 CFR §68.95(a)(1) 1996. 

85. Center for Chemical Process Safety (CCPS). “Guidelines for Risk Based Process Safety.” Page liv. 

2007.

86. Ibid at Page 124.

87. Ibid at Page 125.

88. 29 CFR §1910.119 (c) 2012.

89. Center for Chemical Process Safety (CCPS), Guidelines for Process Safety Metrics, Page 109. 2010.

90. Ibid.

91. Process Safety Leading and Lagging Metrics ...You Don’t Improve What You Don’t Measure, 

http://www.aiche.org/ccps/resources/overview/process-safety-metrics/recommended-process-safetymetrics (accessed April 12, 2013).

92.Center for Chemical Process Safety (CCPS), Guidelines for Process Safety Metrics, Page 97. 2010.

93.Health and Safety Executive (HSE), Developing Process Safety Indicators a Step-by-Step Guide for 

Chemical and Major Hazard Industries, HSE Guidance Series/HSG Series, HSG254, Page 4. 2006.

94.Center for Chemical Process Safety (CCPS), Guidelines for Process Safety Metrics, Page 109. 2010.

95. OSHA Instruction CPL 02-02-045 (1992). Updated in 1994.

96. CPL 03-00-004, Section VII. Federal Program Change. 2007. 

97. Ibid at Section X(D)(1). 

98. Ibid.

99. Department of Industrial Relations, Division of Occupational Safety and Health, California, Process 

Safety Management District Office. “Mission Statement: Goals Reached in 2011 & Strategic Plan 

for 2012.” 

100. 22 CCR §66265.32(a)(4)(2004). 
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101. Center for Chemical Process Safety (CCPS). “Guidelines for Risk Based Process Safety.” 2007.