U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD

INVESTIGATION REPORT 

CATASTROPHIC RUPTURE OF HEAT EXCHANGER

(SEVEN FATALITIES) 

TESORO ANACORTES REFINERY

ANACORTES, WASHINGTON

APRIL 2, 2010 

KEY ISSUES

 INHERENTLY SAFER DESIGN

 TESORO PROCESS SAFETY CULTURE

 CONTROL OF NONROUTINE WORK

 MECHANICAL INTEGRITY INDUSTRY STANDARD DEFICIENCIES

 REGULATORY OVERSIGHT OF PETROLEUM REFINERIES

REPORT 2010-08-I-WA 

MAY 2014
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Dedication 

This report is dedicated to the two women and five men 

who lost their lives as a result of the Tesoro Anacortes 

Refinery incident on April 2, 2010. 

Daniel Aldridge 

Matthew Bowen 

Matthew Gumbel 

Darrin Hoines 

Lew Janz 

Kathryn Powell 

Donna Van Dreumel 

 
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Table of Contents 

1.0 Executive Summary .......................................................................................................................... 1

1.1 Incident Summary .............................................................................................................................. 1

1.2 Key Findings ...................................................................................................................................... 2

1.2.1 Technical Findings ..................................................................................................................... 2

1.2.2 Organizational Findings ............................................................................................................. 4

1.2.3 Industry Codes and Standards Findings ..................................................................................... 7

1.2.4 Regulatory Findings ................................................................................................................... 8

1.2.5 Similar Findings in CSB Investigations of the Tesoro Anacortes and Chevron Richmond 

Refinery Incidents ................................................................................................................................ 11

1.3 Recommendations ............................................................................................................................ 13

2.0 Tesoro Refining & Marketing Company LLC ............................................................................ 15

2.1 Anacortes Refinery ........................................................................................................................... 15

2.2 Other Tesoro Refineries ................................................................................................................... 16

2.3 Tesoro Anacortes Refinery NHT Unit .............................................................................................. 17

2.3.1				Catalytic Reformer .................................................................................................................... 17

2.3.2 Naphtha Hydrotreater – A/B/C & D/E/F Feed/Product Heat Exchangers ................................ 17

3.0 Incident Description ....................................................................................................................... 20

3.1 Pre-Incident Operations .................................................................................................................... 20

3.2 Night of the Incident ......................................................................................................................... 21

3.3 The Incident ...................................................................................................................................... 22

4.0 Technical Analysis .......................................................................................................................... 26

4.1 High Temperature Hydrogen Attack ................................................................................................ 26

4.1.1				Predicting the Occurrence of HTHA ........................................................................................ 31

4.1.2 Conditions that increase HTHA susceptibility ......................................................................... 33

4.1.3 Inherently Safer Design ............................................................................................................ 34

4.1.4				HTHA Inspection Strategy Limitations .................................................................................... 36

4.2 Tesoro Heat Exchanger Failure ........................................................................................................ 37

4.2.1				NHT Heat Exchanger Construction .......................................................................................... 37

4.2.2				Post-Incident Metallurgical Analysis ........................................................................................ 40

4.3 Timing of the Incident ...................................................................................................................... 43

4.3.1				NHT Heat Exchanger Startup Conditions ................................................................................. 44

4.4 Process Conditions of the B and E Heat Exchangers ....................................................................... 45
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4.4.1 CSB Modeling of the NHT Heat Exchangers .......................................................................... 46

4.4.1.1 HTHA Occurred Below the Nelson Curve ...................................................................... 49

4.4.1.2 Estimate That a Portion of the B and E Heat Exchangers Operated Above the Nelson 

Curve..... ......................................................................................................................................... 50

4.4.1.3 Tesoro’s Replacement Heat Exchangers ......................................................................... 50

5.0 Organizational Deficiencies ........................................................................................................... 51

5.1 NHT Heat Exchanger Flanges – A History of Leaking .................................................................... 51

5.1.1				Incident Report That Demonstrates Normalization of Hazardous Conditions ......................... 52

5.1.2				TOP Investigation of Fires ........................................................................................................ 52

5.1.3				MOCs Did not Effectively Control Hazardous Conditions ...................................................... 53

5.1.4 Unsuccessful Tesoro Attempts to Prevent Heat Exchanger Flange Leaks ................................ 55

5.2 Hazardous Nonroutine Work ............................................................................................................ 57

5.2.1 CSB Investigation of Tosco Avon Refinery ............................................................................. 58

5.2.2				NHT Heat Exchanger Cleaning and Startup ............................................................................. 59

5.2.3				Tesoro Failure to Control Heat Exchanger Startup Hazards ..................................................... 59

5.3 Process Hazard Analyses Failed to Prevent or Reduce the Consequences ....................................... 63

5.3.1				Hazardous Nonroutine Operations ............................................................................................ 63

5.3.2 Access Was Not Controlled During Hazardous NHT Heat Exchanger Startup ....................... 64

5.3.3 Failure to Effectively Identify and Evaluate HTHA Hazards .................................................. 65

5.3.3.1 Insufficient Process Instrumentation ............................................................................... 68

5.3.4 HTHA Hazards Were Not Effectively Controlled ................................................................... 69

5.3.4.1 PHA Assumptions That Contributed to Ineffective Control of HTHA Hazards ............. 70

5.4 CSB Conclusions on Organizational Deficiencies ........................................................................... 73

6.0 Industry Codes and Standards ...................................................................................................... 75

6.1 API RP 941 Operating Limits and Material Selection for HTHA .................................................... 75

6.1.1				No Minimum Requirements to Prevent HTHA ........................................................................ 75

6.1.2				History of the Nelson Curves .................................................................................................... 75

6.1.3 Industry Critiques of Nelson Curves ........................................................................................ 76

6.1.4				Unreliable Carbon Steel Nelson Curve ..................................................................................... 78

6.1.4.1 ExxonMobil HTHA Incident Below the Carbon Steel Nelson Curve ............................. 79

6.1.4.2 Other Industry Reports of HTHA Damage to Equipment that Operated Below the 

Carbon Steel Nelson Curve ............................................................................................................. 79

6.1.5 Essential Adjustments Are Needed to API RP 941 .................................................................. 79

6.1.6				ANSI Z10, Exemplifies Standards Clarity ................................................................................ 81

6.2 API RP 580 Risk Based Inspection / API 581 Risk Based Inspection Technology ........................ 82
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7.0 Regulatory Oversight of Petroleum Refineries in Washington .................................................. 84

7.1 Background....................................................................................................................................... 85

7.2 L&I Division of Occupational Safety and Health (DOSH) .............................................................. 86

7.2.1 Causal Findings Analysis ......................................................................................................... 86

7.3 OSHA National Emphasis Program ................................................................................................. 92

7.3.1 Federal National Emphasis Program ........................................................................................ 92

7.3.2 Washington State National Emphasis Program ........................................................................ 93

7.3.3 Tesoro National Emphasis Program Audit ............................................................................... 95

7.3.3.1 Tesoro NEP Results Associated with the E Heat Exchanger .......................................... 95

7.4 Risk Reduction and Continuous Improvement ................................................................................. 97

7.5 Workforce Participation ................................................................................................................. 101

7.6 Funding and Regulator Competency .............................................................................................. 102

7.7 Similar Deficiencies in the Anacortes and Richmond Refinery Incidents ..................................... 102

7.7.1				Reliance on Inspection Instead of Inherently Safer Design in Mechanical Integrity Programs at 

Tesoro and Chevron Refineries .......................................................................................................... 103

7.7.2				Ineffective PHAs at Tesoro and Chevron ............................................................................... 104

7.7.3				Applicable API Standards Lack Minimum Requirements to Control Hazards ...................... 104

7.7.4				Weak Regulations and Ineffective Regulators ........................................................................ 104

7.8 Environmental Protection Agency and Chemical Accident Release Programs ............................. 105

7.8.1 Background ............................................................................................................................ 105

7.8.2 Enforcement of Inherent Safety in the United States ............................................................. 107

7.8.3 The EPA RMP Program ......................................................................................................... 107

7.8.4 The General Duty Clause ....................................................................................................... 108

7.8.5				The EPA’s Authority to Enforce Inherent Safety ................................................................... 110

7.8.6				The Role of Inherent Safety in Major Accident Prevention ................................................... 113

8.0 Recommendations ......................................................................................................................... 114

8.1 The U.S. Environmental Protection Agency .................................................................................. 114

8.2 Washington State Legislature, Governor of Washington ............................................................... 115

8.3 Washington State Department of Labor & Industries - Division of Occupational Safety and 

Health...............................................................................................................................118

8.4 American Petroleum Institute ......................................................................................................... 119

8.5 Tesoro Refining & Marketing Company LLC ............................................................................... 120

8.6 Tesoro Anacortes Refinery ............................................................................................................. 121

8.7 United Steelworkers Local 12-591 ................................................................................................. 122

Appendix A AcciMap Causal Analysis ........................................................................................... 123
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Appendix B NHT A/B/C Heat Exchanger Startup Trend Data ................................................... 128

Appendix C CSB Simulation of the NHT Heat Exchangers ......................................................... 131

Appendix D Evaluation of Current Tesoro Programs to Identify and Control Damage 

Mechanism Hazards .................................................................................................... 137

Appendix E Inspection Techniques................................................................................................. 140

Appendix F CSB Chevron Reports Incorporated by Reference .................................................. 142

Appendix G Spectrum Inspection Reports ..................................................................................... 143

Appendix H Beta Laboratory Reports ............................................................................................ 144

Appendix I Metallurgical Review .................................................................................................. 145

Appendix J Additional HTHA Evaluation Report ....................................................................... 146
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List of Figures 

Figure 1. Schematic of the Tesoro Anacortes Refinery NHT Unit Heat Exchangers .................................. 2

Figure 2. Tesoro Anacortes Refinery ......................................................................................................... 15

Figure 3. Aerial View of the Tesoro Anacortes Refinery. ......................................................................... 16

Figure 4. Process Flow of NHT Unit ......................................................................................................... 18

Figure 5. Example of Fouling Deposits on the Inside of Heat Exchanger Tubes. ..................................... 20

Figure 6. Aerial View of CR/NHT Unit .................................................................................................... 21

Figure 7. CSB Animation of Operator Opening Long-Winded Valve on Night of Incident ..................... 22

Figure 8. Post-Incident View of D/E/F NHT Heat Exchanger Bank ......................................................... 23

Figure 9. CSB Animation of the Fire Following the NHT Heat Exchanger Failure .................................. 24

Figure 10. Six NHT Heat Exchangers in Two Banks of Three Heat Exchangers Each ............................ 25

Figure 11. Atomic Hydrogen Diffuses Through Steel.. ............................................................................. 27

Figure 12. Decarburization Process. .......................................................................................................... 28

Figure 13. Methane Fissures. ..................................................................................................................... 29

Figure 14. Methane Blisters.. ..................................................................................................................... 29

Figure 15. Microcrack Resulting from Linked-HTHA Fissures ................................................................ 30

Figure 16. Nelson Curves from Current API RP 941 ................................................................................ 32

Figure 17. Hierarchy of Controls. .............................................................................................................. 35

Figure 18. Fabrication Layout of the B and E Heat Exchangers................................................................ 37

Figure 19. Cross-Section of Sample NHT Heat Exchanger Weld ............................................................. 39

Figure 20. E Heat Exchanger Failure Schematic ....................................................................................... 40

Figure 21. Circumferential Weld Damage in the B Heat Exchanger. ........................................................ 41

Figure 22. Comparison of Damage Locations in the B and E Heat Exchangers. ...................................... 42

Figure 23. Temperature and Pressure Trends before the Anacortes Incident ............................................ 44

Figure 24. Temperature and Pressure Indicators for the NHT Heat Exchanger Banks ............................. 45

Figure 25. Model Results for Can 4. .......................................................................................................... 47

Figure 26. Model Results for the Weld Downstream of Can 4 .................................................................. 48

Figure 27. Model Results for the Coldest Region of the E Heat Exchanger .............................................. 49

Figure 28. Steam Station and Steam Lance. .............................................................................................. 54

Figure 29. Post-Incident Steam Lance ....................................................................................................... 56

Figure 30. Unit structure (left) and manual block valve (right) ................................................................. 60

Figure 31. DMHR and CSB Findings on Anacortes HTHA and Heat Exchangers (1990–2008) ............. 67

Figure 32. Temperature and Pressure Instruments on the NHT Heat Exchanger Banks ........................... 69

Figure 33. CSB Modeling Results of HTHA and the Nelson Curve at the Tesoro Anacortes Refinery ... 80
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Figure 34. Example of ANSI Z10 Obligations Formatting ........................................................................ 82

Figure 35. Gaps Within the Washington and Federal PSM Regulations ................................................... 92

Figure 36. AcciMap of April 2, 2010 Tesoro Anacortes Refinery Explosion and Fire ........................... 124

Figure 37. Location of the Two Outlet Temperature Measurements ....................................................... 128

Figure 38. Temperature Data During NHT A/B/C Heat Exchanger Bank Startup on Night of the Incident

 ............................................................................................................................................. 129

Figure 39. Temperature Data During NHT A/B/C Heat Exchanger Bank Startup on August 29, 2009 . 129

Figure 40. Temperature Data During NHT A/B/C Heat Exchanger Bank Startup on April 2, 2009 ...... 130

Figure 41. Temperature Data During NHT A/B/C Heat Exchanger Bank Startup on February 3, 2008. 130

Figure 42. NHT Heat Exchanger Configuration with Known Process Conditions Indicated .................. 132

Figure 43. NHT Heat Exchanger Fouling Distributions Analyzed .......................................................... 133

Figure 44. Visualization of Possible Tube-Side Fouling Distributions ................................................... 134

Figure 45. Calibration of HYSYS Model with Actual Process Data ....................................................... 135

Figure 46. Estimated Operating Conditions of the B and E Heat Exchangers ......................................... 136
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Acronyms and Abbreviations 

0F degrees Fahrenheit 

AcciMap Accident Map 

ALARP As Low As Reasonably Practicable 

AIHA American Industrial Hygiene Association 

ANSI American National Standards Institute 

API American Petroleum Institute 

API RP 571 API RP 571—Damage Mechanisms Affecting Fixed Equipment in the 

Refining Industry 

API RP 580 API RP 580—Risk-Based Inspection 

API RP 581 API RP 581—Risk-Based Inspection Technology 

API RP 941 API RP 941—Steels for Hydrogen Service at Elevated Temperatures and 

Pressures in Petroleum Refineries and Petrochemical Plants 

API RP1

 API Recommended Practices. API standards that communicate 

recognized industry practices. Recommended practices (RPs) may include 

both mandatory and non-mandatory requirements. 

 Shall: As used in a standard, “shall” denotes a minimum requirement in 

order to conform to the standard. 

 Should: As used in a standard, “should” denotes a recommendation or that 

which is advised but not required in order to conform to the standard. 

API Standard2

 API Standards include Specifications, Recommended Practices, Standards, 

and Codes. Standards combine elements of both specifications and 

recommended practices. “Standard” is also a broad term covering all API 

documents that have been developed in accordance with API procedures 

for standards development. 

API TR 941 API Technical Report 941—The Technical Basis Document for API RP 

941 

APOSC Assessment Principles for Offshore Safety Cases 

ASNT American Society for Nondestructive Testing 

AUBT Advanced Ultrasonic Backscatter Technique 

bpd Barrels Per Day 

CAA Clean Air Act 

 

1

 http://www.api.org/publications-standards-and-statistics/~/media/Files/Publications/FAQ/2011-ProceduresFinal.ashx API Procedures for Standards Development. 2011; p 3. 2

 Ibid at pp 2-3. 
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Cal/OSHA California Occupational Safety and Health Administration 

CCPS Center for Chemical Process Safety (American Institute of Chemical 

Engineers) 

CFR Code of Federal Regulations 

CSB U.S. Chemical Safety and Hazard Investigation Board 

CSHO Compliance Safety and Health Officer 

DCS Distributed Control System 

DOSH Division of Occupational Safety and Health (within Washington L&I) 

DMHR Damage Mechanism Hazard Review (also known as a corrosion review) 

EPA U.S. Environmental Protection Agency 

HAZ Heat Affected Zone 

HSE Health and Safety Executive 

HTHA High Temperature Hydrogen Attack 

IOW Integrity Operating Window 

IST Inherently Safer Technology 

L&I Washington State Department of Labor & Industries 

MOC Management of Change 

MOOC Management of Organizational Change 

MSDS Material Safety Data Sheet 

NDE Nondestructive Examination 

NDT Nondestructive Testing 

NEJAC National Environmental Justice Advisory Council 

NEP OSHA Petroleum Refinery Process Safety Management National 

Emphasis Program 

NHT Catalytic Reformer / Naphtha Hydrotreater Unit 

NIST National Institute of Standards and Technology 

OSHA U.S. Occupational Safety and Health Administration 

OSHAct Occupational Safety and Health Act of 1970, 29 U.S.C. 667 

PHA Process Hazard Analysis 

PQV PSM Program Quality Verification Inspection—referenced in OSHA’s 

1994 PSM Compliance Directive3

PSIA Pounds Per Square Inch Absolute 

 

3

 OSHA Instruction CPL 2-2.45A CH-1 September 13, 1994 Directorate of Compliance Programs, 29 CFR 1910.119, Process Safety 

Management of Highly Hazardous Chemicals -- Compliance Guidelines and Enforcement Procedures. 

https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=DIRECTIVES&p_id=1559 (accessed December 28, 2013). 
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PSIG Pounds Per Square Inch Gauge 

PSM Process Safety Management 

PSM Standard OSHA Process Safety Management of Highly Hazardous Chemicals 

Standard, 29 CFR §1910.119 

PWHT Post-Weld Heat Treatment 

RAGAGEP Recognized and Generally Accepted Good Engineering Practice 

RBI Risk-Based Inspection 

RMP Risk Management Plan (EPA), as defined in U.S.C. Section 42, Chapter 

85, Subchapter I, Part A, Section 7412(r) 

RP Recommended Practice (API) 

S-Scan Sectorial Scan 

SS Stainless Steel 

TOP Triangle of Prevention 

UK United Kingdom 

USW United Steelworkers Union 

UT Ultrasonic Technique 

WAC Washington Administrative Code 

WFMT Wet Fluorescent Magnetic Particle Testing 

 
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1.0 Executive Summary 

1.1 Incident Summary 

On April 2, 2010, the Tesoro Refining and Marketing Company LLC (“Tesoro”) petroleum refinery4 in 

Anacortes, Washington (“the Tesoro Anacortes Refinery”), experienced a catastrophic rupture of a heat 

exchanger in the Catalytic Reformer / Naphtha Hydrotreater unit (“the NHT unit”). The heat exchanger, 

known as E-6600E (“the E heat exchanger”), catastrophically ruptured because of High Temperature 

Hydrogen Attack (HTHA).5

 Highly flammable hydrogen and naphtha at more than 500 degrees 

Fahrenheit (oF) were released from the ruptured heat exchanger and ignited,6

 causing an explosion and an 

intense fire that burned for more than three hours. The rupture fatally injured seven Tesoro employees 

(one shift supervisor and six operators) who were working in the immediate vicinity of the heat exchanger 

at the time of the incident. To date this is the largest fatal incident at a US petroleum refinery since the 

BP Texas City accident in March 2005.7

 

The NHT unit at the Tesoro Anacortes Refinery contained two parallel groups, or banks, of three heat 

exchangers (A/B/C and D/E/F) used to preheat process fluid before it entered a reactor, where impurities 

were treated for subsequent removal. The E heat exchanger was constructed of carbon steel.8

 A 

schematic of the six heat exchangers is illustrated in Figure 1. 

At the time of the release, the Tesoro workers were in the final stages of a startup activity to put the 

A/B/C bank of heat exchangers back in service following cleaning. The D/E/F heat exchangers remained 

in service during this operation. Because of the refinery’s long history of frequent leaks and occasional 

fires during this startup activity, the CSB considers this work to be hazardous and nonroutine.9

 While the 

operations staff was performing the startup operations, the E heat exchanger in the middle of the 

operating D/E/F bank catastrophically ruptured. 

 

4

 Tesoro purchased all of the Shell Oil Company’s stock in the Shell Anacortes Refining Company in 1998. 

Approximately 350 employees are at the Anacortes refinery and 185 of them are operations and maintenance 

workers who are represented by the United Steelworkers union (USW). 5

 HTHA is a damage mechanism that results in fissures and cracking and occurs when carbon steel equipment is 

exposed to hydrogen at high temperatures and pressures. 

6

 The autoignition temperature of a material is defined as the temperature at which it will ignite spontaneously on 

contact with oxygen, without spark or flame. The Tesoro Material Safety Data Sheet (MSDS) for naphtha listed 

autoignition temperature as 437 oF. As the process temperature was more than 500 0F, autoignition was likely. 7

 The 2005 BP Texas City incident resulted in 15 fatalities and 180 injuries. 

8

 The portion of the E heat exchanger that failed was constructed of carbon steel. The details of the exchanger 

materials are addressed in Section 4.2.1, NHT Heat Exchanger Construction. 

9

 Nonroutine does not refer to the frequency at which the activity occurs. Nonroutine refers to whether the activity 

is part of the normal sequence of converting raw materials to finished products. Startup is considered a 

nonroutine activity. Center for Chemical Process Safety (CCPS), Guidelines for Risk Based Process Safety. 

2007; p 286. 
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Figure 1. Schematic of the Tesoro Anacortes Refinery NHT Unit Heat Exchangers. There are two 

banks of three heat exchangers: A/B/C bank and D/E/F bank. The E heat exchanger catastrophically 

ruptured on April 2, 2010. 

1.2 Key Findings 

1.2.1 Technical Findings 

1. The rupture of the E heat exchanger was the result of the carbon steel heat exchanger being 

severely weakened by a damage mechanism known as HTHA. The B heat exchanger did not fail, 

but was constructed with the same materials and operated under the same conditions as the E heat 

exchanger. The B heat exchanger was also severely weakened by HTHA damage. HTHA is a 

damage mechanism that results in fissures and cracking and occurs when carbon steel equipment 
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is exposed to hydrogen at high temperatures and pressures.10 The resulting damage severely 

degrades the mechanical properties of the steel.11 (Section 4.1) 

2. HTHA can accumulate in high-stress areas in carbon steel, such as non-post-weld heat-treated 

welds. The welds of the B and E carbon steel heat exchangers were not post-weld heat-treated. 

The high stress areas near the welds of these heat exchangers were found to contain HTHA 

damage. The rupture location of the E heat exchanger was along these high-stress weld regions 

and was attributable to cracks caused by HTHA. (Sections 4.1.2 and 4.2.1) 

3. In 1970, the American Petroleum Institute (API) published API Recommended Practice (RP) 941 

Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and 

Petrochemical Plants. This document provides Nelson curves to predict the occurrence of HTHA 

in various materials of construction as a function of temperature and hydrogen partial pressure.12 

The Nelson curves are predicated on past equipment failure incidents and are plotted based on 

self-reported process conditions that are ill-defined and lack consistency. (Section 4.4.1.1) 

4. The CSB performed computer reconstruction13 of the process conditions within the NHT heat 

exchangers. The results of the computer reconstruction show that the portion of the carbon steel 

E heat exchanger that ruptured was estimated to have operated below the applicable Nelson 

curve. This was considered the safe region of operation where HTHA could not occur. 

Therefore, the carbon steel Nelson curve methodology is inaccurate, cannot be depended on to 

prevent HTHA equipment failures, and cannot be reliably used to predict the occurrence of 

HTHA equipment damage. (Section 4.4.1.1) 

5. The hottest portion of the B and E heat exchangers was clad with stainless steel, which improved 

resistance to HTHA. On the basis of CSB computer reconstruction of the process conditions in 

the heat exchangers, the CSB estimates that this stainless steel-clad portion of the heat exchangers 

operated at process conditions that were at times above the carbon steel Nelson curve. However, 

the unclad portion where the rupture of the E heat exchanger occurred, and where HTHA existed 

in the B and E heat exchangers, was estimated to have operated below the Nelson curve. 

(Sections 4.2.1 and 4.4.1.2) 

 

10 McIntyre, Vogelsange, Progress in Corrosion- The First 50 Years of the EFC; Maney Publishing 2009; Section 

12.5.1. 11 Shih, H.M. and Johnson, H.H. A Model Calculation of the Nelson Curves for Hydrogen Attack; Acta 

Metallurgica, Volume 30. 1982; pp 537-545. 

12 Hydrogen partial pressure is a calculated parameter. It is the pressure that would be exerted by a single 

component of a gas mixture. For example, the hydrogen partial pressure of a 500 psia gas mixture in a vessel 

that contains 50 mol% hydrogen and 50 mol% propane equals 250 psia. 

13 The CSB modeled the exchanger process conditions using Aspen HYSYS® and Aspen Exchanger Design and 

Rating. The model required the use of several assumptions, such as fouling distribution, because of a lack of 

both process and fouling data gathered by Tesoro. As a result, all model results are estimates. Due to limitations 

in historical data, modeling estimates were limited to 2007-2010. See Appendix C for a detailed description of 

the modeling assumptions and results. 
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6. It is very difficult to inspect for HTHA because the damage might not be detected; it can be 

microscopic and may be present only in small localized areas of equipment. In addition, 

equipment must already be damaged by HTHA for equipment inspection to identify HTHA. 

Successful identification of HTHA is highly dependent on the specific techniques employed and 

the skill of the inspector, and there are few inspectors who have this expertise. Inspection is 

therefore not sufficiently reliable to ensure mechanical integrity and prevent HTHA equipment 

damage. (Section 4.1.4) 

7. Equipment inspections and post-weld heat treating rely on procedures and human 

implementation, which are low on the hierarchy of controls14 and thus are weaker safeguards to 

prevent HTHA failures than the use of materials that are less susceptible to HTHA damage. 

(Section 4.1.2) 

8. Inherently safer design is a better approach to prevent HTHA. API has identified high chromium 

steels that are significantly more resistant to HTHA than carbon steel. The B and E heat 

exchangers were not constructed from these inherently safer materials. (Sections 4.1.3 and 4.1.4) 

1.2.2 Organizational Findings 

9. The startup of the NHT heat exchangers was hazardous nonroutine work. Leaks routinely 

developed that presented hazards to workers conducting the startup activities. Process Hazard 

Analyses (PHAs) 15 at the refinery repeatedly failed to ensure that these hazards were controlled 

and that the number of workers exposed to these hazards was minimized. (Section 5.2.3) 

10. The Shell Anacortes Refining Company was owned and operated by the Shell Oil Company 

(“Shell Oil”) prior to 1998. The 1996 Shell Oil NHT unit PHA simply cited ineffective, nonspecific, judgment-based, qualitative safeguards to prevent equipment failure from HTHA. 

However, the effectiveness of these safeguards was neither evaluated nor documented; instead the 

PHA merely listed general safeguards. Had the adequacy of the safeguards been verified, 

improved safeguards intended to protect against HTHA failure could have been recommended. 

The 2001 and 2006 Tesoro PHA revalidations did not address or modify the analysis performed 

 

14 An effectiveness ranking of techniques used to control hazards and the risk they represent can be described as a 

hierarchy of controls – the higher up (further left) on the hierarchy, the more effective the risk reduction achieved 

(Figure 17). 

15 A PHA is a hazard evaluation to identify, evaluate, and control the hazards of a process. Facilities that process a 

threshold quantity of hazardous materials, such as the Tesoro Anacortes Refinery, are required to conduct a PHA 

per the Washington Administrative Code (WAC) Title 296 Chapter 67, Safety standards for process safety 

management of highly hazardous chemicals (1992). See: http://apps.leg.wa.gov/wac/default.aspx?cite=296-67

(accessed September 29, 2013) PHAs are also required by the federal EPA Risk Management Program. 
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in the 1996 Shell Oil PHA. The Tesoro 2010 NHT unit PHA failed to identify HTHA as a hazard 

for the shell of the B and E heat exchangers.16 (Sections 5.3.4.1, 5.3, and Appendix D) 

11. For the 15 years before the April 2010 incident, assumptions used by PHA teams at the Anacortes 

refinery contributed to ineffective safeguards, ineffective hazard identification, and ineffective 

control of hazards to prevent equipment failures from HTHA damage, such as the E heat 

exchanger in the NHT unit.17 (Section 5.3.4.1 and Appendix D) 

12. Shell Oil completed a PHA in 1995 related to process modifications that could increase the 

hydrogen partial pressure in the NHT heat exchangers. However, when managing this change no 

consideration, evaluation, or recommendations were made to address the potential for HTHA 

damage to the NHT heat exchangers. (Section 5.3.4 and Appendix D) 

13. Shell Oil and Tesoro periodically performed damage mechanism hazard reviews (DMHRs), 

called corrosion reviews. However, these reviews did not identify HTHA as a credible failure 

mechanism for the B and E heat exchangers. These reviews were weakened by primarily relying 

on design operating parameters for these heat exchangers rather than data from actual process 

operating conditions.18 (Section 5.3.3 and Appendix D) 

14. Tesoro did not monitor actual operating conditions of the B and E heat exchangers within the 

NHT heat exchanger banks, even though it would have been technically feasible to do so. Rather, 

corrosion experts hired by Tesoro primarily relied on design operating conditions that when 

evaluated using the Nelson curve indicated lower susceptibility to HTHA damage than the 

operating conditions estimated by CSB models.19 The use of the design temperatures contributed 

to the incorrect conclusion that the heat exchangers were not susceptible to damage from HTHA. 

As a result, Tesoro was not aware that the hottest section of the B and E heat exchangers (Can 

 

16 The term “shell” in this context refers to the pressure containing carbon steel wall of the heat exchanger. The 

2010 Tesoro NHT unit PHA did identify HTHA as a possible hazard for the tube side of the B and E exchangers. 

Heat exchangers of this design have process flow through two sides, separated by mechanical design. Heat is 

transferred from one side to the other to exchange heat. Flow on the inside of the tubes through the heat 

exchanger is commonly referred to as “tube-side,” while flow on the outside of the tubes is called “shell-side.” 

The B and E exchangers had HTHA damage to the pressure containing portion on the shell-side. The 2010 

Tesoro NHT unit PHA did not identify HTHA as a hazard where HTHA occurred on the shell-side of the 

exchanger. 

17 Tesoro issued a new PHA procedure in 2012 that removed the list of assumptions that had previously limited the 

PHA teams’ analyses. Now, the PHA procedure requires that all assumptions can and should be challenged at 

any point in the PHA process. Furthermore, if a credible challenge is made, the assumption is eliminated for the 

duration of the study. This change to Tesoro’s PHA procedure should help ensure that process safety hazards 

and proposed safeguards are more effectively evaluated in the future. 18 Design operating conditions include estimated and calculated conditions used to design the exchangers and the 

thermal profile developed. 

19 Tesoro hired corrosion experts to evaluate damage mechanisms at the Anacortes refinery. These external experts 

were not Tesoro employees. 
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4)20 at times likely operated above the carbon steel Nelson curve. If Tesoro had measured or 

otherwise technically evaluated the actual operating conditions of these heat exchangers, existing 

company procedures required HTHA inspection.21 Although HTHA may have been identified, 

inspection for HTHA is not sufficiently reliable. (Sections 5.3.3.1, 4.1.4, and Appendix D) 

15. Tesoro procedures did not prohibit or effectively limit the use of additional personnel during the 

nonroutine hazardous startup of the NHT heat exchangers. The heat exchanger startup procedure 

specifies the use of only one outside operator to perform startup operations of the NHT heat 

exchanger banks. However on the day of the incident, a supervisor requested five additional 

operators to assist with the startup of the A/B/C heat exchanger bank. (Section 5.2.3) 

16. The NHT heat exchangers frequently leaked flammable hydrocarbons during startup, sometimes 

resulting in fires. Tesoro management had been complacent about these hazardous leaks and did 

not always investigate the cause of the leaks. Tesoro did take some actions to prevent the leaks, 

but these actions did not effectively prevent the leaks before the April 2010 incident. Additional 

operators, such as those present during the April 2010 heat exchanger startup, were frequently 

needed during startup of the NHT heat exchanger banks to respond to potential hydrocarbon leaks 

or fires. This past practice contributed to the presence of the six additional workers in the unit 

during the April 2010 incident. (Sections 5.1 and 5.2) 

17. The NHT heat exchanger banks were designed with large, difficult-to-manipulate manual block 

valves on different levels of the NHT heat exchanger structure. These valves were used to start 

up the NHT heat exchanger banks and typically required numerous adjustments to maintain 

temperature specifications. The difficulties with valve operation during startup typically resulted 

in the need for additional operator assistance. This past practice contributed to the presence of 

some of the six additional workers in the NHT unit during the April 2010 incident.22 

(Section 5.2.3) 

18. The CSB found several indications of process safety culture deficiencies at the Tesoro Anacortes 

Refinery. Refinery management had normalized the occurrences of hazardous conditions, 

including frequent leaks from the NHT heat exchangers, by using steam to mitigate leaks, 

ineffectively identifying methods to prevent leaks from the heat exchanger flanges and gaskets, 

 

20 The general construction of each heat exchanger shell consisted of a series of four steel sections, called “Cans” 

welded to form a cylinder (exchanger shell). This construction required a longitudinal weld to form each “Can” 

or section, and three circumferential welds to join the four sections end to end. The temperature profile is such 

that Can 1 is the coolest and temperature increase towards the hottest section at Can 4. 21 Tesoro’s inspection procedure would have required HTHA inspection if operating conditions were found to be 

within 25 pounds per square inch absolute (psia) or 25 oF of the Nelson curve. 

22 The new design of the NHT heat exchangers has eliminated the need to clean the exchangers while the unit is 

operating. Post-incident, Tesoro performed a study to evaluate hazardous equipment that is cycled more 

frequently than the unit. This study took two months to complete and resulted in 53 recommendations. One of 

the recommendations is intended to ensure that a hazard review is conducted before cycling equipment that was 

not included in this study. 
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commonly requiring additional operators during NHT heat exchanger startups, and exceeding the 

staffing levels that procedures specified. (Section 5.0) 

19. The refinery process safety culture required proof of danger rather than proof of effective safety 

implementation. For years, technical experts used design parameters to evaluate the B and E heat 

exchangers for HTHA susceptibility. Data for actual operating conditions were not readily 

available, and these technical experts were not required to prove safety effectiveness in reaching 

their conclusion that the B and E heat exchangers were not susceptible to HTHA damage. 

(Section 5.0) 

1.2.3 Industry Codes and Standards Findings 

20. API RP 941 - Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum 

Refineries and Petrochemical Plants is written permissively such that there are no minimum 

requirements to prevent HTHA failures. Currently API RP 941 uses the term “should” 27 times 

and the word “shall” only once. As used in a standard, “shall” denotes a minimum requirement to 

conform to the standard, while “should” denotes a recommendation that is advised but not 

required to conform to the standard. API RP 941 does not require users to verify actual operating 

conditions when establishing operating limits or to confirm that the selection of construction 

materials will prevent HTHA. (Section 6.1.1) 

21. API RP 941 provides industry guidance to predict the occurrence of HTHA in various materials 

of construction by using the Nelson curves. The Nelson curves are predicated on past equipment 

failure incidents and are plotted based on self-reported process conditions that are ill-defined and 

lack consistency. The API Technical Report 941 notes, “The concept of a simple boundary 

between safe and unsafe operating conditions in hydrogen for common alloys, of the type 

depicted by the Nelson curves should not be expected.” 23 (Sections 4.1.1 and 6.1.3) 

22. The CSB has learned of at least eight recent refinery incidents where HTHA reportedly occurred 

below the carbon steel Nelson curve. In 2011, API issued an industry alert on HTHA in refinery 

service.24 The API alert noted multiple incidents of carbon steel equipment at operating 

conditions where carbon steel was previously thought to be resistant to HTHA. These refinery 

incidents and the subsequent API response strongly suggest an industry-wide problem with the 

carbon steel Nelson curve. (Section 6.1.4.2) 

23. The CSB found that the carbon steel Nelson curve is inaccurate and cannot be relied on to prevent 

HTHA equipment failures or accurately predict HTHA equipment damage. (Section 6.1.4) 

 

23 API Technical Report 941. The Technical Basis Document for API RP 941. 2008; p 47. 

24 See: http://www.api.org/publications-standards-and-statistics/hidden-pages/industry-alert (accessed January 19, 

2014). 
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24. API RP 941 does not require industry to use inherently safer materials to prevent HTHA failures. 

(Section 6.1.1) 

25. API RP 581: Risk-Based Inspection Technology allows users to calculate a damage factor to 

determine the HTHA susceptibility of various materials of construction. Tesoro hired damage 

mechanism experts to help ensure that damage mechanism hazards were properly identified. API 

RP 581 does not require users to verify actual operating conditions when determining applicable 

damage mechanisms. The calculation for carbon steel using the design conditions applied in 

damage mechanism reviews results in the conclusion that the B and E heat exchangers had a 

“Low Susceptibility” to HTHA. The API RP 581 calculation is therefore unreliable for 

preventing HTHA failure or predicting the probability of HTHA damage in carbon steel 

equipment. (Section 6.2) 

26. API RP 581: Risk-Based Inspection Technology is written permissively, so that there are no 

minimum requirements to prevent HTHA failures. There are 19 uses of “shall” in RP 581, but 

none is substantive—nearly all the uses of “shall” are in formulas or requirements for damage 

factor or inspection effectiveness calculations that are themselves non-mandatory. There are 

three uses of “shall” in the HTHA section, but they are again used for calculations that are not 

required, preceded by language such as “the following procedure may be used” or if HTHA is 

detected, “fitness for service should be performed.” An instructive example of the 

permissiveness of API RP 581 is the important guidance that the document provides for 

conditions that would make equipment susceptible to HTHA damage. However, if the equipment 

is identified as meeting the criteria that would indicate HTHA is a credible damage mechanism, 

according to API RP 581 guidance, the equipment “should” be evaluated for HTHA 

susceptibility.25 (Section 6.2) 

1.2.4 Regulatory Findings 

27. Despite the fact that the nation’s roughly 150 petroleum refineries represent only a small fraction 

of the thousands of chemical processing facilities throughout the United States, the CSB has 

noted a considerable frequency of significant and deadly incidents at refineries over the last 

decade. In 2012 alone, the CSB tracked 125 significant incidents at US petroleum refineries.26 

(Section 7.1) 

28. The draft CSB Chevron Regulatory Report recommends that the state of California improve the 

oversight of petroleum refineries by supplementing the existing process safety management 

regulations with more rigorous features such as requiring companies to reduce risks to as low as 

reasonably practicable, or ALARP; requiring the effective implementation of safeguards and the 

 

25 API RP 581, Risk-Based Inspection Technology. 2008; pp 252-258. 

26 These incidents were reported to the Department of Energy or the National Response Center and were examined 

by the CSB Incident Screening Department. The CSB has concluded that incidents that result in disruptions to 

the national energy supply, produce serious injuries, or receive high levels of media attention are all significant. 
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use of the hierarchy of controls; and providing for the development of a more well-funded, 

technically competent regulator. In the draft Chevron Regulatory Report, the CSB concluded that 

the existing regulatory regimes for onshore petroleum refineries in the United States and 

California: (Appendix F) 

a. Rely on a safety and environmental management system framework that is primarily activitybased rather than goal-based risk reduction to as low as reasonably practicable (ALARP) or 

equivalent. 

b. Are static, unable to adapt to innovation and advances in the management of major hazard 

risks. 

c. Place the burden on the regulator to verify compliance with the regulations rather than 

shifting the burden to industries by requiring duty holders to effectively manage the risks they 

create and also ensure regulator acceptance of their plans for controlling those risks. 

d. Do not effectively incorporate lessons learned from major accidents; nor do they have the 

regulatory authority to require duty holders to address newly-identified safety issues resulting 

from such incidents. 

e. Do not effectively collect or promote industry use of major accident performance indicators 

to drive industry to reduce risks to ALARP. 

f. Do not require the use or implementation of inherently safer systems analysis or hierarchy of 

controls. 

g. Do not effectively involve the workforce in hazard analysis and prevention of major 

accidents. 

h. Do not provide the regulator with the authority to accept or reject a company’s hazard 

analysis, risk assessment, or proposed safeguards; and 

i. Do not employ the requisite number of staff members with the technical skills, knowledge, 

and experience necessary to provide sufficient direct safety oversight of petroleum refineries. 

29. The Washington State Department of Labor and Industries (L&I), which oversees workplace 

safety in the state, does not have sufficient personnel resources to verify that process safety 

management (PSM) requirements are being implemented adequately. L&I enforces state PSM 

requirements that are based on the federal OSHA PSM standard for hazardous chemical facilities. 

However, the state of Washington has only four PSM specialists in its compliance section to 

regulate and inspect nearly 270 PSM-covered facilities, including five petroleum refineries. Of 

these four specialists only one has a technical background. (Section 7.2) 

30. Washington L&I completed an audit of the Tesoro NHT unit under the refinery National 

Emphasis Program (NEP) in March 2009, one year before the incident. The Tesoro Anacortes 

NEP audit is noteworthy, as it was the only audit conducted pursuant to the federal OSHA NEP 

that focused on a unit that subsequently experienced a catastrophic accident that the CSB has 

investigated. The heat exchanger that failed, the E heat exchanger, was a fundamental component 
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of the Tesoro NEP audit. However, no citable mechanical integrity or other process safety 

management deficiencies related to the heat exchanger were found. (Section 7.3.3.1) 

31. Shell Oil and Tesoro PHAs conducted on the NHT unit cited non-specific, judgment-based 

qualitative safeguards that in light of the April 2010 incident were not effective. Following the 

April 2010 incident the L&I Division of Occupational Safety and Health (DOSH) issued citations 

to Tesoro relating to its PHA program, but they were not associated with evaluating the 

effectiveness of safeguards such as the robustness of the HTHA prevention program. If the 

Washington PSM standard had required an evaluation and documentation of safeguard 

effectiveness, Shell Oil and Tesoro would have been obligated to conduct such an analysis. 

(Section 7.4) 

32. In the 2006 Tesoro NHT unit PHA, Tesoro discontinued a review of its corrosion control program 

and a specific mechanical integrity checklist associated with the corrosion program after 

concluding that they were “not a legal requirement.” The state of Washington PSM regulation 

did not require this review. Tesoro conducted the optional review ineffectively and then 

terminated it when the company determined that it was not strictly required. An enhanced 

regulatory system with goal-setting attributes would require continual risk reduction and 

performance of an effective DMHR. This review is not just an activity but must meet the goal of 

preventing equipment failures. (Sections 5.3.4 and 7.2.1) 

33. Under the existing US and Washington regulatory systems, including the PSM standard and the 

U.S. Environmental Protection Agency (EPA) Risk Management Program (RMP), there is no 

requirement to reduce risks to a specific risk target such as ALARP. While the Clean Air Act 

(CAA) directed the EPA to promulgate the RMP regulations “to provide, to the greatest extent 

practicable, for the prevention and detection of accidental releases of regulated substances,”27

there is no RMP ALARP requirement. Under both the PSM and RMP regulations, an employer 

must “control” hazards when conducting a PHA of a covered process. However, there is no 

requirement to address the effectiveness of the controls or to use the hierarchy of controls. Thus, 

a PHA can satisfy the regulatory requirements even though it might inadequately identify or 

control major hazards. In addition, there is no requirement to submit PHAs to the regulator, and 

the regulator is not responsible for assessing the quality of the PHA or the effectiveness of 

proposed safeguards, resulting in a regulatory system that is often reactive and frequently 

becomes involved in examining the details of process safety programs only after a major process 

accident. (Section 7.4) 

 

27 42 U.S.C. §7412(r)(7)(B)(i) (1990). 
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1.2.5 Similar Findings in CSB Investigations of the Tesoro Anacortes and Chevron 

Richmond Refinery Incidents 

34. The CSB conducted an investigation of the August 6, 2012, Chevron Richmond Refinery 

incident. That incident was also the result of a metallurgical failure caused by a well-known 

damage mechanism called sulfidation corrosion, and Chevron process safety programs failed to 

effectively control the hazard before the major incident that endangered the lives of 19 Chevron 

employees. The CSB identified a number of similar causal findings common to both the April 

2010 Tesoro Anacortes Refinery incident and the August 2012 Chevron Richmond Refinery 

incident. (Section 7.7) 

35. Mechanical integrity programs at both Tesoro and Chevron emphasized inspection strategies 

rather than the use of inherently safer design to control the damage mechanisms that ultimately 

caused the major process safety incidents. These inspections were unreliable and failed to 

prevent the incidents. Since the Richmond and Anacortes incidents, both Chevron and Tesoro 

have upgraded the materials of construction for the equipment that failed, using inherently safer 

design that significantly reduced the risk of the applicable damage mechanism hazards. 

(Section 7.7.1) 

36. Both Tesoro and Chevron PHAs were ineffective in identifying the significant hazards of HTHA 

and sulfidation corrosion, respectively. Rather than performing rigorous analyses of damage 

mechanisms during the PHA process, both companies simply cited non-specific, judgment-based 

qualitative safeguards to reduce the risk of damage mechanisms. The effectiveness of these 

safeguards was neither evaluated nor documented; instead, the PHA merely listed general 

safeguards. (Section 7.7.2) 

37. The Anacortes and Richmond refineries relied on API standards to assist in the selection of 

construction materials for the Tesoro NHT heat exchangers and the Chevron piping circuit, 

specifically API RP 941 and API RP 939-C Guidelines for Avoiding Sulfidation (Sulfidic) 

Corrosion Failures in Oil Refineries. The documents provide guidance on how to avoid HTHA 

and sulfidation corrosion failures, respectively, but neither document establishes minimum 

requirements to evaluate and minimize the risks of equipment failure from the damage 

mechanism hazard. (Section 7.7.3) 

38. Neither the Washington nor the California process safety regulations were successful in 

preventing major process safety incidents. Neither set of regulations required DMHRs, reduction 

of risk to ALARP, evaluation of effectiveness of controls, or use of the hierarchy of controls. In 

addition, there is no requirement to submit PHAs to the regulator, and the regulator is not 

responsible for assessing the quality of the PHA or the proposed safeguards. Furthermore, neither 

Washington nor California required the use of inherently safer design to the greatest extent 

practicable. A regulatory system that contains more robust goal-setting attributes would help to 

ensure that all of the refineries in these states rigorously apply process safety concepts that focus 
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more effectively on prevention. The new regulatory framework would also emphasize the 

implementation of inherently safer designs and the hierarchy of controls to prevent major process 

safety incidents. (Section 7.7.4) 

39. Both Washington and California have significant weaknesses in the staffing of PSM inspectors. 

Both Washington L&I (the Washington PSM regulator) and the California Occupational Safety 

and Health Administration (Cal/OSHA) (the California PSM regulator) lack sufficient technically 

experienced and qualified staff members to verify that PSM requirements are being implemented 

adequately. It is essential that regulators of high-hazard facilities are independent, well funded, 

well staffed, and technically qualified. These individuals must be able to communicate 

effectively with refinery personnel and to monitor the adequacy of refinery process safety 

practices. (Section 7.7.4) 

40. Both the Chevron and Tesoro incidents could have been prevented if inherently safer equipment 

construction materials had been used. Although inherently safer technology (IST) is the most 

effective major accident prevention approach in the hierarchy of controls it is not enforced by the 

EPA through the General Duty Clause or other provisions of the Clean Air Act. The EPA has the 

authority to require the application of IST through the General Duty Clause. Furthermore, the 

Clean Air Act provides the authority for the EPA to develop and implement new regulations 

requiring the use of inherently safer systems analysis and the hierarchy of controls to establish 

more effective safeguards for identified process hazards to prevent major accidents. (Section 7.8)
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1.3 Recommendations 

As a result of the findings and conclusions of this report, the CSB makes recommendations, summarized 

below, to the following recipients: 

The U.S. Environmental Protection Agency 

Revise the Chemical Accident Prevention Provisions under 40 CFR Part 68 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. Until this revision is in effect, enforce through the 

Clean Air Act’s General Duty Clause the use of inherently safer systems analysis and the hierarchy of 

controls to the greatest extent feasible when facilities are establishing safeguards for identified process 

hazards. In addition, effectively participate in the oversight of the process safety culture program at the 

Tesoro Anacortes Refinery. 

_________________________________________________________________ 

Washington State Legislature, Governor of Washington 

Augment the existing process safety management regulatory framework with the more rigorous safety 

management attributes identified in this report for petroleum refineries in the state of Washington. 

_________________________________________________________________ 

Washington State Division of Occupational Safety and Health – Labor 

and Industries 

Perform verifications at all Washington petroleum refineries to ensure prevention of equipment failure 

because of HTHA and that effective programs are in place to manage hazardous nonroutine work. In 

addition, effectively participate in the oversight of the process safety culture program at the Tesoro 

Anacortes Refinery. 

_________________________________________________________________ 

American Petroleum Institute

Revise API RP 941 and API RP 581 to prohibit the use of carbon steel equipment in HTHA-susceptible 

service and require verification of actual operating conditions. Make additional revisions to API RP 941 

to establish minimum requirements to prevent HTHA failures and to require the use of inherently safer 

design. 

_________________________________________________________________ 
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Tesoro Refining & Marketing Company LLC 

Participate with API in the API RP 941 revisions to establish minimum requirements to prevent HTHA 

failures and to require the use of inherently safer design. Following the API RP 941 revisions, develop 

and implement a plan to meet the new API RP 941 requirements. Improve process safety management 

programs for damage mechanism hazards to require the hierarchy of controls and the use of inherently 

safer design. 

_________________________________________________________________ 

Tesoro Anacortes Refinery

Implement a process safety culture program that will assess and continually improve any identified 

process safety culture issues at the Tesoro Anacortes Refinery. 

_________________________________________________________________ 

United Steelworkers Local 12-591

Effectively participate in the process safety oversight committee to continually improve any identified 

process safety culture issues at the Tesoro Anacortes Refinery. 

_________________________________________________________________ 

Section 8.0 details the recommendations. 

 
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2.0 Tesoro Refining & Marketing Company LLC 

Tesoro Corporation was founded in 1968 as a petroleum exploration and production company. In 1969, 

Tesoro began operating its first refinery near Kenai, Alaska. A Fortune 100 company, Tesoro now 

operates six refineries in the western United States. These refineries have a combined capacity of 

approximately 850,000 barrels per day (bpd).28

2.1 Anacortes Refinery 

Tesoro purchased the Anacortes refinery from Shell Oil Company in August 1998. Located 

approximately 70 miles north of Seattle (Figure 2 and Figure 3), the Tesoro Anacortes refinery has a total 

crude-oil capacity of 120,000 bpd. The refinery has been in operation since 1955.29 

The Anacortes refinery primarily supplies gasoline, jet fuel, and diesel to markets in Washington and 

Oregon. It also manufactures heavy fuel oils, liquefied petroleum gas, and asphalt. Approximately 350 

employees and 50 contractors work at the refinery.30 

Figure 2. Tesoro Anacortes Refinery 

 

28 See http://tsocorp.com/about-tesoro/locations/ and http://tsocorp.com/about-tesoro/company-history/ (accessed 

January 4, 2014). 

29 Statement of Basis for the Final Air Operating Permit – Final, July 26, 2010, p 6. 

30 The United Steelworkers (USW) represents approximately 185 of the operations and maintenance workers at the 

refinery. See http://www.usw.org/media_center/releases_advisories?id=0521, (accessed November 9, 2013). 
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Figure 3. Aerial View of the Tesoro Anacortes Refinery. 

2.2 Other Tesoro Refineries 

Beginning in the late 1990s, Tesoro made a series of refinery acquisitions. In 1998, Tesoro acquired 

refineries in Kapolei, Hawaii31 (from BHP Americas), and Anacortes, Washington (from Shell Oil 

Company). In 2001, the company purchased refineries in Mandan, North Dakota, and Salt Lake City, 

Utah (both from Amoco). In 2002, Tesoro acquired the Golden Eagle refinery in Martinez, California 

 

31 Tesoro no longer owns this refinery. 
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(from Ultramar, now Valero), and in 2007 Tesoro acquired its Los Angeles refinery (from Shell Oil) and 

USA Gasoline retail stations (from Chevron).32 Tesoro purchased its Carson, California, refinery in 2013 

(from BP).33

2.3 Tesoro Anacortes Refinery NHT Unit 

The April 2, 2010, incident occurred in the Tesoro Anacortes Refinery Catalytic Reformer / Naphtha 

Hydrotreater unit (“the NHT unit”), which includes a naphtha hydrotreating process unit. Hydrotreating 

is a process that removes sulfur, nitrogen, and oxygen impurities from petroleum feedstock and 

intermediate products by reacting with hydrogen in the presence of a catalyst. Hydrotreating serves two 

purposes: 34

1. It improves the quality and environmental impact of products, especially quality specifications 

mandated by law (for example, benzene reduction in motor gasoline). 

2. It protects sensitive and costly downstream catalysts from contamination. 

The Tesoro NHT unit was originally constructed in 1972 with a rated capacity of 24,800 bpd. 

Modifications and upgrades resulted in a rated capacity at the time of the incident of 40,550 bpd, a 64% 

capacity increase. 

2.3.1 Catalytic Reformer 

Catalytic reforming is a chemical process used to convert petroleum refinery naphtha,35 typically having 

low-octane ratings,36 into high-octane liquid products called reformates. The Catalytic Reformer uses a 

system of fixed bed catalytic reactors to increase the octane rating of gasoline blending stock. The 

reformate product is then sent to gasoline component storage for use in fuel blending. The reforming 

reaction generates hydrogen, which is used in the NHT. 

2.3.2 Naphtha Hydrotreater – A/B/C & D/E/F Feed/Product Heat Exchangers 

The removal of sulfur, nitrogen, and oxygen impurities in the NHT unit requires heating the naphtha to 

over 600 °F at greater than at 600 pounds per square inch gauge (psig) and mixing it with hydrogen. The 

initial portion of this heating took place in the NHT unit’s E-6600 A/B/C and D/E/F feed and product 

 

32 See http://www.tsocorp.com/TSOCorp/AboutUs/CompanyHistory/061236, (accessed April 24, 2013). 

33 See http://tsocorp.com/about-tesoro/company-history/ (accessed January 4, 2014). 34 Hydrocarbon Publishing Company, Worldwide Refinery Processing Review (Individual Technology), 

Hydrotreating summary. 2Q 2012, Item No. B1014 

35 Naphtha is a fraction of crude oil that boils between approximately 85 0F and 400 0F. It includes hydrocarbons 

ranging from C5 to C12. Naphtha comprises approximately 15-30 weight % of raw crude oil. See Prestvik, R.; 

Moljord, K.; Grande, K.; Holmen, A. Compositional Analysis of Naphtha and Reformate. In G.J. Antos & A.M. 

Aitani (Eds.), Catalytic Naphtha Reforming (p. 2). New York, NY: Marcel Dekker, Inc. 

36 Octane rating represents gasoline-burning efficiency. The higher the octane rating, the less likely it is for gasoline 

to knock, or produce harmful, small explosions that reduce efficiency, in an engine. See Van Dyke, K. (1997). 

Fundamentals of Petroleum (4th ed.) (p 318). Austin, Texas: The University of Texas at Austin. 
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(effluent) heat exchangers,37 as depicted in Figure 4. (These heat exchangers are referenced throughout 

this report as the NHT heat exchangers.) 

Figure 4. Process Flow of NHT Unit 

The function of the NHT A/B/C and D/E/F heat exchangers is to conserve energy by using the hot NHT 

reactor effluent to heat the cooler reactor feed and thus reduce the energy input needed for the reactor 

furnace. The cool NHT liquid naphtha feed is pumped from storage and/or other active units and mixed 

with a stream of hydrogen-rich gas, becoming a combined liquid and gas feed stream. The resulting 

liquid-gas mixture is then fed to the tube-side38 of two parallel groups, or banks of three heat exchangers 

(A/B/C and D/E/F) to be heated by the shell-side39 fluid. As the liquid-gas mixture inside of the tubes is 

 

37 The A/B/C and D/E/F exchangers are single-pass shell and tube heat exchangers. A heat exchanger allows heat 

to be transferred from one process fluid to another. One fluid gets hotter while the other gets cooler. A shell and 

tube–type heat exchanger consists of a large pressure vessel exterior (shell) with a group (bundle) of small thinwalled pipes (tubes) that reside inside the shell. One process fluid flows through the tubes, and the other process 

fluid flows through the shell, over the tubes. Heat is transferred (exchanged) from one to the other through the 

walls of the tubes. 

38 “Tube-side” refers to process fluid that flows inside of heat exchanger tubes. 

39 “Shell-side” refers to process fluid that flows inside of the heat exchanger shell and on the outside of the tubes. 
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heated, the liquid portion vaporizes completely. Now liquid free, the naphtha and hydrogen vapors enter 

a furnace where they are further heated and then fed to the NHT reactor. The reactions to remove sulfur, 

nitrogen, and oxygen take place in this reactor. The hot reactor effluent40 is then fed through the shellside of the heat exchangers to preheat the incoming tube-side feed. The impurity-free naphtha is then fed 

to other processes in the refinery. 

 

 

40 Effluent is flow exiting a vessel or piece of equipment. 
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3.0 Incident Description 

3.1 Pre-Incident Operations 

During normal operation at the Tesoro Anacortes Refinery, the A/B/C and D/E/F heat exchangers were all 

in use. Because of the original Shell Oil Company design and the process operating conditions, the heat 

exchangers would foul during operation; that is, they would develop a buildup of process contaminant 

byproducts both inside of the heat exchanger tubes, as illustrated in Figure 5, and outside of the tubes. 

The fouling inhibited heat transfer between the tube-side and shell-side process fluid, thus reducing the 

heat transfer efficiency. 

Figure 5. Example of Fouling Deposits on the Inside of Heat Exchanger Tubes. Fouling greatly 

reduces heat transfer between the shell-side and tube-side process fluids.41 

Because the heat exchangers fouled, they required periodic cleaning so that process temperature 

requirements could be maintained. Cleaning was typically required after about six months of continuous 

operation. When performing this cleaning, one bank of heat exchangers was taken out of service while 

the other bank continued operating. The cleaned heat exchangers would then be placed back into service 

by slowly introducing the hot naphtha and hydrogen feed into the heat exchangers. Because of a long 

history of frequent leaks and occasional fires when putting these heat exchangers back into service 

(Section 5.1), startup, shutdown, and cleaning activities were a hazardous nonroutine operation.42 By 

employing this nonroutine operation, Shell Oil and Tesoro avoided a total shutdown of the NHT unit. 

On March 28, 2010, five days before the incident, the A/B/C heat exchanger bank was taken offline so 

that the fouled tubes in each heat exchanger could be cleaned. The D/E/F heat exchanger bank and the 

 

41 Photograph of fouled tube from http://www.tekleen.com/it/water-filtration-101/ (accessed December 4, 2013). 

42 Nonroutine does not refer to the frequency at which the activity occurs. Nonroutine refers to whether the activity 

is part of the normal sequence of converting raw materials to finished products. Startup and shutdown of 

equipment are considered a nonroutine activity. Center for Chemical Process Safety (CCPS), Guidelines for Risk 

Based Process Safety. 2007; p 286. 
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rest of the NHT unit remained in operation. On March 31, 2010, the three-day maintenance cleaning 

activity was completed and the equipment was reassembled and prepared for operation. 

3.2 Night of the Incident 

On the evening of April 1, 2010, Tesoro initiated startup of the A/B/C heat exchanger bank. The NHT 

unit was staffed in a typical manner, with one inside board operator who monitored the console and one 

outside operator. An aerial view of the unit is shown in Figure 6. 

Source: Google Earth 

Figure 6. Aerial View of CR/NHT Unit 

The inside NHT operator and the outside NHT operator began the process of placing the heat exchangers 

back in service. The inside operator used a step-by-step task list for the startup process, physically 

checking off the steps on a hardcopy of the procedure while maintaining radio communication with the 

outside operator. Interviews conducted by the CSB indicate that the startup of the heat exchangers was a 

very difficult assignment for only a single outside operator. The startup procedure required manipulation 

of several isolation block valves as illustrated in Figure 7, which necessitated a significant amount of 

manual effort to open. 
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Figure 7. CSB Animation of Operator Opening Long-Winded Valve on Night of Incident. Valves on 

heat exchanger structure had to be opened concurrently when performing the heat exchanger bank 

startup 

These valves had to be gradually and concurrently opened, so the operator could not simply stay by each 

valve until it was fully opened or closed. Also, four steam lances were staged and ready for use during 

the startup to mitigate any leaks or fires that might occur.43 These valves and steam lances were located 

at different positions in the vicinity of the A/B/C and D/E/F heat exchangers. At approximately 10:30 

p.m., six additional Tesoro employees (five operators and one supervisor)44 joined the outside operator, at 

the request of the supervisor, to assist in bringing the A/B/C heat exchanger bank online. The startup 

procedure did not specify defined roles for these six additional personnel. 

3.3 The Incident 

The operators continued the A/B/C heat exchanger bank startup as planned. Two leaks from the heat 

exchangers were reported during the startup. These leaks did not stop operations however, because leaks 

during startup of these heat exchangers were frequent and had become a “normal” part of the startup. 

Furthermore, based on past operating experience, these leaks were expected to cease when the heat 

exchangers reached typical operating temperature. 

 

43 Three of the four steam lances were likely in use at the time of the incident. See Section 5.0 for additional 

discussion on the use of steam lances. 

44 The five additional operators that assisted in the NHT heat exchanger startup were assigned to the Crude, 

Utilities, Vacuum Flasher, ROSE, and CFH/DHT units. 
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At 12:30 a.m. on April 2nd, while the seven outside personnel were still performing A/B/C heat exchanger 

bank startup operations, the E heat exchanger on the adjacent, in-service bank catastrophically ruptured. 

The pressure containing “shell” of the heat exchanger separated at weld seams,45 as depicted in Figure 8, 

expelling a large volume of very hot hydrogen and naphtha.46

Figure 8. Post-Incident View of D/E/F NHT Heat Exchanger Bank 

The naphtha and hydrogen likely autoignited upon release into the atmosphere, creating a large fireball as 

depicted in Figure 9. 

 

45 The failure occurred at both circumferential and longitudinal weld seams from fabrication of the exchanger. 

46 The naphtha began to condense to liquid in the B and E heat exchangers. The material in the process was above 

its atmospheric boiling temperature, so it vaporized when released to atmospheric conditions. 
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Figure 9. CSB Animation of the Fire Following the NHT Heat Exchanger Failure. The hot naphtha 

and hydrogen likely autoignited upon release to the atmosphere. The fire engulfed the entire heat 

exchanger structure. 

The operator in the NHT control room told the CSB that he felt the impacts of the rupture at his desk 350 

feet away. The CSB determined that at the time of the incident two of the outside operators were likely 

on the top level of the heat exchanger structure (Figure 10), and the remaining five operators were most 

likely at ground level. All seven outside operations personnel were badly burned, and within 22 days of 

the incident, all succumbed to their injuries. 
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Figure 10. Six NHT Heat Exchangers in Two Banks of Three Heat Exchangers Each 

 
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4.0 Technical Analysis 

4.1 High Temperature Hydrogen Attack 

Post-incident metallurgical analysis determined that the carbon 

steel E heat exchanger ruptured because it was in a highly 

weakened state because of high temperature hydrogen attack 

(HTHA). The HTHA damage mechanism occurs when steel 

equipment is exposed to hydrogen at high temperatures and partial 

pressures. The resulting damage severely degrades the mechanical 

properties of the carbon steel.47

HTHA occurs when atomic hydrogen diffuses into the steel walls of 

process equipment, as illustrated in Figure 11. The hydrogen 

reacts48 with carbon in the steel, producing methane gas,49 as 

depicted in Figure 12. This reaction removes carbon from the steel, 

a process commonly referred to as “decarburization.”50 

 

47 Shih, H.M. and Johnson, H.H. A Model Calculation of the Nelson Curves for Hydrogen Attack; Acta 

Metallurgica, Volume 30. 1982; pp 537-545. 

48 Sources differ on whether atomic hydrogen directly reacts with carbon in steel to produce methane or whether 

the hydrogen recombines inside the steel to form molecular (diatomic) hydrogen before reacting with carbon to 

form methane. 

49 API Technical Report 941. The Technical Basis Document for API RP 941. 2008; pp 7-8. 50 Weiner, L.C. Kinetics and Mechanism of Hydrogen Attack of Steel. Corrosion, 1961, Volume 17, pp 109-115. 
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Figure 11. Atomic Hydrogen Diffuses Through Steel. In HTHA, molecular hydrogen dissociates at the 

vessel wall to form atomic hydrogen, which diffuses through the steel. 
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Figure 12. Decarburization Process. When the atomic hydrogen encounters free carbon inside of the 

steel, hydrogen and carbon react to produce methane gas. 

Methane, a much larger molecule than atomic hydrogen, cannot diffuse out of the steel. Rather, it 

accumulates inside the vessel walls,51 exerting force on the surrounding steel. As more methane gas is 

formed, the methane pressure increases. The very high pressure exerted by the methane gas inside the 

steel can form fissures, as illustrated in Figure 13 or blisters in the steel, as shown in Figure 14.52 

 

51 API Technical Report 941. The Technical Basis Document for API RP 941. 2008; pp 7-8. 

52 Allen, R.E., Jansen, R.J., Rosenthal, P.C., and Vitovec, F.H., The Rate of Irreversible Hydrogen Attack of Steel 

at Elevated Temperatures. 26th Midyear meeting of AIChE. May 9, 1961. 
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Figure 13. Methane Fissures. When methane molecules cannot diffuse out of the steel, they 

accumulate inside of the steel, creating high pressure that forms fissures in steel. 

Figure 14. Methane Blisters. Accumulation of methane in steel can also form blisters in the metal. 
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As more fissures are formed, they can link, forming microcracks in the steel.53 The linkage of fissures 

into microcracks is shown in Figure 15. Microcracks can also link to form larger cracks, which greatly 

weaken the steel and can lead to rupture of the vessel.54 This process occurred in the E heat exchanger at 

the Tesoro Anacortes Refinery. 

Source: API RP 941, Figure 2 

Figure 15. Microcrack Resulting from Linked-HTHA Fissures. This image from API RP 941 shows 

fissures formed as a result of HTHA linked together to form a microcrack. Decarburized regions 

appear lighter in color (because of an absence of carbon) than unaffected regions. 

 

 

53 Lai, George. High Temperature Corrosion and Materials Applications. Materials Park: ASM International, 

2007. 54 Ibid. 
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4.1.1 Predicting the Occurrence of HTHA 

Industry relies on a graph in API RP 941 Steels for Hydrogen Service at Elevated Temperatures and 

Pressures in Petroleum Refineries and Petrochemical Plants to predict the occurrence of HTHA in 

various steels. The lines in that graph are known as Nelson curves, developed in 1949 by George 

Nelson,55 who created these curves based on observed industry experience with HTHA. The curves have 

been adjusted over the years based on additional industry experience.56 The most recent version of the 

API RP 941 Nelson curves is shown in Figure 16. Industry uses these curves as a line of demarcation to 

predict HTHA. At temperatures above each curve, HTHA is possible for that material of construction, 

and at temperatures below the curve, the 

prediction is that HTHA will not occur for that 

material. 

The Nelson curves predict HTHA based on 

process temperature, hydrogen partial pressure,57

and material of construction. Carbon steel is 

represented by the lowest curve, indicating that 

this material is the most susceptible to HTHA 

when compared to the other materials of 

construction shown in Figure 16. For a given 

material of construction, the Nelson curve 

indicates that a higher temperature increases the 

probability that HTHA will occur.58,59 

 

55 G. A. Nelson, Hydrogenation Plant Steels. 1949 Proceedings, Volume 29M, API; pp. 163 -174. 56 API Technical Report 941. The Technical Basis Document for API RP 941. 2008; p 127. 

57 Hydrogen partial pressure is a calculated parameter. It is the pressure that would be exerted by a single 

component of a gas mixture. For example, the hydrogen partial pressure of a 500 psia gas mixture in a vessel that 

contains 50 mole percent (mol%) hydrogen and 50 mol% propane equals 250 psia. 

58 For most materials included on the Nelson curves, increasing hydrogen partial pressure also increases the 

probability of HTHA. However, in some areas for some materials, the Nelson curves do not predict a higher 

probability of HTHA when hydrogen partial pressure is increased. 

59 Low carbon steels, which contain very little alloying additions of chromium and molybdenum, are the most 

susceptible to HTHA. Chromium-rich and molybdenum-rich carbides are inherently more stable than iron 

carbides, and they resist dissolution of carbon with hydrogen to form methane. Therefore, the alloys containing 

chromium and molybdenum resist HTHA at higher temperatures and hydrogen pressures. See CSB’s E-6600E 

and E-6600B Metallurgical Analysis report (Appendix I). 
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Figure 16. Nelson Curves from Current API RP 941. These Nelson curves are used to predict the 

occurrence of HTHA in various materials of construction. 
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4.1.2 Conditions that increase HTHA susceptibility 

Welding performed on steel process vessels creates additional HTHA risk factors, such as residual 

stress.60 Post-weld heat treatment is a method that can reduce the stress in steel that was generated from 

the welding process. The process of post-weld heat treatment consists of a sequence of controlled heating 

and cooling steps applied to the welded structure using externally applied heating elements.61 This 

process gives the metal time to readjust to its original, prefabrication state62 and removes residual stress. 

The carbon in the steel becomes less reactive, inhibiting the reaction with hydrogen to form methane. 

Chemical resistance to HTHA is thus modestly improved in post-weld heat-treated steels.63

As will be discussed in Section 4.2.1, the carbon steel shells of 

the B and E heat exchangers were not post-weld heat-treated, and 

therefore the steel surrounding the welds may have been highstress areas.64 HTHA was only found in the areas near the welds 

in both the B and E heat exchangers. 

Post-weld heat treating is a manual activity and therefore low on 

the hierarchy of controls.65 Consequently, post-weld heat 

treating carbon steel is a weaker safeguard to prevent HTHA 

failures than the use of materials that are not susceptible to 

HTHA damage.66,67 

 

60 API Technical Report 941. The Technical Basis Document for API RP 941. 2008; p 163. 61 Krishnan, J. and Ahmed, Khaleel; Post-Weld Heat Treatment- Case Studies. BARC Newsletter. Centre for 

Design and Manufacture, Bhabha Atomic Research Centre, May 2002. 

62 Gillissie, J.G., Heat Treatment- What Is It?. The National Board of Boiler and Pressure Vessel Inspections. 

October 1981. 

63 API Technical Report 941. The Technical Basis Document for API RP 941. 2008; p 162. 

64 Post-weld heat treatment is generally avoided unless specified as mandatory by codes or standards. Incorrect 

post-weld heat-treatment procedures can result in metal that is out of specification for the service. In the United 

States, the ASME Boiler Code is the authority that mandates post-weld heat treatment. If the code requires postweld heat treatment, it is performed, but if the code does not specify the requirement for post-weld heat 

treatment, then the heat treatment is generally not performed. The ASME Boiler Code did not require post-weld 

heat treatment for the B and E heat exchangers. See 2011 ASME Boiler and Pressure Vessel Code; Paradowska 

A., Price J.W.H, and Dayawansa P. Measurement of Residual Stress Distribution in Tubular Joints Considering 

Postweld Heat Treatment Materials Forum Volume 30- 2006. Institute of Materials Engineering Australasia 

Ltd.; and Funderburk, R. Scott, Postweld Heat Treatment. Welding Innovation, Vol. XV, No. 2, 1998. 65 An effectiveness ranking of techniques used to control hazards and the risk they represent can be described as a 

hierarchy of controls – the higher up (further left) on the hierarchy, the more effective the risk reduction achieved 

(Figure 17). 66 Improper post-weld heat treating can lead to vessel failure. Steward, M. and Lewis, O. Pressure Vessels Field 

Manual Common Operating Problems and Practical Solutions, 2013; pp 236-237. 

67 Post-weld heat treating problems include heat treating errors such as inadequate time at temperature, inadequate 

or excessive temperature rate, inadequate temperature, cooled too rapidly, cooled too slowly, and cooled to the 
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Despite the improved HTHA resistance of post-weld heat-treated vessels compared with non-post-weld 

heat-treated vessels, upgrading vessel materials to inherently safer materials of construction is a better 

approach to prevent equipment failure from HTHA. This approach is discussed further in Section 4.1.3. 

4.1.3 Inherently Safer Design 

As defined in the Center for Chemical Process Safety (CCPS)68 book Inherently Safer Chemical 

Processes, 2nd ed., inherently safer design is the process of identifying and implementing inherent safety 

in a specific context that is permanent and inseparable from the process.69 In the book Guidelines for 

Engineering Design for Process Safety, 2nd ed., the CCPS states that “inherently safer design solutions 

eliminate or mitigate the hazard by using materials and process conditions that are less hazardous.”70

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

compared to a different technology with regard to a specific hazard or risk.71 A technology can be 

inherently safer with respect to one risk but not inherently safer from another risk. Consequently, it is 

important to carry out a comprehensive documented hazard analysis to identify the individual and overall 

risks in a process and assess how the risks can be effectively minimized to control hazards. An inherently 

safer systems or hierarchy of control review details a list of choices that offer varying degrees of 

inherently safer implementation. The review should include risks of personal injury, environmental harm, 

and lost production, as well as an evaluation of economic feasibility.72

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.73 Process upgrades, rebuilds, and 

repairs offer additional opportunities to implement inherently safer design concepts. Conducting a 

comprehensive hazard review to determine risks and identify ways to eliminate or reduce those risks 

constitutes an important step in implementing an inherently safer process. 

 

 

wrong temperature. Canale, L., Mesquita, R., and Totten, G., Failure Analysis of Heat Treated Steel 

Components, 2008; pp 106-109. 

68 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. 

69 Center for Chemical Process Safety (CCPS). Inherently Safer Chemical Processes – A Life Cycle Approach. 

2009; section 2.2. 70 Ibid at Section 5.1.1. 

71 Ibid at Section 5.2. 72 Ibid at p 184. 73 Kletz, Trevor and Amyotte, Paul. Process Plants: A Handbook for Inherently Safer Design. 2010; p 14. 
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An effectiveness ranking of techniques used to control hazards 

and their associated risks can be described as a hierarchy of 

controls. As depicted in Figure 17, the further left on the 

hierarchy continuum, the more effective the technique is in 

reducing risk. All concepts in the hierarchy of controls should 

be included in the process of risk assessment and reduction. 

Upgrading the equipment material of construction to a more 

HTHA-resistant steel is a high-ranking, inherently safer choice 

in material selection. Holding other variables constant, 

upgrading the material of construction can eliminate the 

potential for HTHA. As previously discussed, post-weld heat 

treating to modestly reduce HTHA susceptibility is low on the 

hierarchy of controls and thus is a weaker safeguard to prevent 

HTHA failures than the use of materials that are not susceptible 

to HTHA damage. 

Figure 17. Hierarchy of Controls. The highlighted boxes reflect inherently safer controls, based on 

Process Plants: A Handbook for Inherently Safer Design Second Edition; Kletz, Trevor Amyotte, Paul; 

CRC Press 2010. 

Since the April 2010 incident, Tesoro has installed new NHT heat exchangers, incorporating aspects of an 

inherently safer design.74 As discussed in Section 4.4.1.3, the materials of construction of two heat 

exchangers have been upgraded to significantly reduce the potential for HTHA. 

 

 

74 While the material of construction is upgraded in the new exchangers, portions of the heat exchangers that are 

manufactured with carbon steel are still designed to operate at temperatures higher than 400 0F. 
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4.1.4 HTHA Inspection Strategy Limitations 

While inspection is an important mechanical integrity program component, there are significant 

limitations with relying solely on inspection strategies to prevent equipment failure from HTHA. For 

example, refinery equipment must already be damaged by HTHA for equipment inspection to identify 

HTHA. HTHA damage is also extremely difficult to identify by conducting an inspection. API RP 941 

includes a discussion of these difficulties: 

High temperature hydrogen attack is a difficult inspection challenge. 

The early stages of attack with fissures, or even small cracks, can be 

difficult to detect. The advanced stage of attack with significant cracking 

is much easier to detect, but at that point there is already a higher 

likelihood of equipment failure.75 

Some existing inspection methods attempt to 

identify HTHA, as described in Appendix E. 

However, inspection should not be solely relied 

on to identify and control HTHA. Inspection 

results can be unreliable and misleading. 

Successful identification of HTHA is highly 

dependent on the specific techniques employed 

and the skill of the inspector, and few inspectors 

have this level of expertise.76 

Inspection thus ranks very low on the hierarchy of 

controls. API RP 571 Damage Mechanisms 

Affecting Fixed Equipment in the Refining 

Industry implicitly supports the concept of 

inherently safer design by describing material 

selection to avoid HTHA failures noting, “300 

Series SS, as well as 5Cr, 9Cr and 12Cr alloys, 

are not susceptible to HTHA at conditions 

normally seen in refinery units.”77

 

 

75 API RP 941. Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and 

Petrochemical Plants. 2008; p 11. 76 “HTHA is dangerous, difficult to detect and can be missed. The reliability of HTHA inspections depends on the 

skill of the inspector.” See: Birring, A., Ultrasonic Testing - Detection of Hydrogen Attack, See:

http://www.nde.com/hydrogen.htm, (accessed June 13, 2013). 77 API RP 571. Damage Mechanisms Affecting Fixed Equipment in the Refining Industry. 2003; p “5-83”. 
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4.2 Tesoro Heat Exchanger Failure 

4.2.1 NHT Heat Exchanger Construction 

The NHT heat exchangers were constructed in 1971 and installed and placed in service in Anacortes. The 

two banks of three heat exchangers were metallurgically identical; the pressure containing “shell” base 

material for each heat exchanger in the bank was specified based on the design operating conditions. 

Exchanger Shell-Side Materials of Construction 

 A/D Mn-0.5Mo steel (SA-302-B), factory clad78 with 1/8” thick Type 304 stainless 

steel.

 B/E Carbon steel (SA-515-70), factory clad with 1/8” thick Type 316 

stainless steel applied to the 4’ Section 4 (Can 4) as shown in Figure 18.79

 C/F Carbon steel (SA-515-70). 

The general construction of each heat exchanger shell consisted of a series of four steel sections, called 

“Cans” welded to form a cylinder (exchanger shell). This construction required a longitudinal weld to 

form each “Can” or section, and three circumferential welds to join the four sections end to end. The B 

and E heat exchanger design is shown in Figure 18. 

Figure 18. Fabrication Layout of the B and E Heat Exchangers 

Design data representing anticipated normal operation and the API RP 941 Nelson curves were used to 

select materials of construction for the NHT heat exchangers. Carbon steel was selected for the B and E 

heat exchangers because the design temperatures were below the carbon steel Nelson curve. “Can” 4 of 

the B and E heat exchangers, the hottest portion of the heat exchangers, was lined on the interior surface 

with a layer of Type 316 stainless steel on top of the carbon steel. The interior stainless steel was applied 

in a process known as “cladding.” The stainless steel was selected for protection against another damage 

 

78 Cladding is a process used to join dissimilar metals together to form a single metal piece. 

79 The remaining portions of the exchanger shell (Cans 1, 2, and 3) did not have a 316 stainless steel cladding. 
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mechanism called sulfidation corrosion.80 Although protection from sulfidation corrosion is the intent of 

the stainless steel cladding, the cladding also can be used to reduce the risk of HTHA. The stainless steel 

cladding reduces the effective hydrogen partial pressure that is acting on the carbon steel beneath the 

cladding.81 

The welding construction method used to manufacture the B and E heat exchangers resulted in a large 

heat-affected zone (HAZ).82 An example of the welds used to construct the E heat exchanger is shown in 

a cross-section micrograph in Figure 19.83 The top of the micrograph is the outside of the heat exchanger 

shell carbon steel wall.84 

 

80 Sulfidation is a damage mechanism that causes thinning in iron-containing materials, such as steel, because of the 

reaction between sulfur compounds and iron at temperatures ranging from 450 °F to 800 °F. This damage 

mechanism causes the metal to gradually thin over time. 81 API RP 941. Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and 

Petrochemical Plants. 2008; p 10. 

82 The process of welding requires substantial heat that alters the material properties of the material near the weld. 

This affected area near the weld is commonly referred to as the “heat-affected zone” or “HAZ”, shown in Figure 

19. 

83 Beta Laboratory, Beta Lab No.M10198, Tesoro Ls2 And Ls2/Cs2 Tee Findings, October 13, 2010 (Appendix H) 84 Figure 19 also shows the elements of a typical weld in the B and E heat exchangers. 
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Figure 19. Cross-Section of Sample NHT Heat Exchanger Weld.85 The cross-section of a multipass 

weld in the upper graphic is typical of the heat exchangers, and the schematic in the lower graphic 

defines the terms associated with the weld. 

The welds in the B and E heat exchanger shells were not post-weld heat-treated.86 As a result, the heataffected zones illustrated in Figure 19 were likely high-stress areas where HTHA damage ultimately 

accumulated. 

 

 

85 See Appendix I, Figure 5. 86 Some components of the heat exchangers were post-weld heat-treated, where wall thickness was at least one inch. 
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4.2.2 Post-Incident Metallurgical Analysis 

BETA Laboratory, located in Mayfield Village, Ohio, conducted metallurgical testing of the B and E heat 

exchangers through an agreement among Tesoro, the Washington Division of Occupational Safety and 

Health (DOSH), and the CSB. BETA Laboratory compiled a series of reports, included in Appendix H, 

on the failed heat exchanger (E) and the exemplar heat exchanger (B)87 that was removed from service 

after the accident at Tesoro. Test results indicate that the E heat exchanger failed at the heat-affected 

zones of the welds surrounding and within “Can” 3, as illustrated in Figure 20. 

Figure 20. E Heat Exchanger Failure Schematic 

The CSB contracted with the National Institute of Standards and Technology (NIST)88 to perform an 

independent analysis of the BETA Laboratory reports and to prepare a report that states a professional 

opinion of the failure mechanism that caused the rupture of the E heat exchanger.89 NIST metallurgical 

experts conducted the analysis. 

NIST determined that the metallurgical damage that caused the 

failure of the E heat exchanger was a result of HTHA, with other 

possible contributing co-mechanisms such as hydrogen-induced 

cold cracking that may have served as HTHA initiation points in 

the heat affected zones. The full metallurgical analysis is 

included in Appendix I. 

The documented HTHA damage for the failed E heat exchanger 

is extensive. Damage is evident in the base metal but only in the 

heat-affected zone adjacent to welds and along fusion boundaries 

 

87 The B exchanger was used as an exemplar during metallurgical testing because it experienced nearly identical 

process conditions and had the same geometry and materials as the E exchanger. 88 NIST is a non-regulatory federal agency in the U.S. Department of Commerce. The NIST mission is to promote 

US innovation and industrial competitiveness by advancing measurement science, standards, and technology in 

ways that enhance the economic security of the nation and improve the quality of life of citizens. See

http://www.nist.gov/public_affairs/general_information.cfm (accessed December 30, 2013). 

89 See CSB’s E-6600E and E-6600B Metallurgical Analysis report (Appendix I). 
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in the welds. No HTHA damage is evident in the base metal outside of the heat-affected zone.90 Because 

the fracture paths followed the narrow damaged regions along the welds, much of the damage in these 

regions was incorporated into the fracture surfaces during the failure as these damaged regions connected 

to form the macro-fracture. 

Similar HTHA damage is also evident and documented in the exemplar B heat exchanger that was 

unaffected by the incident. The HTHA damage in this heat exchanger is similar to the damage 

documented in the uncompromised portions of the E heat exchanger. Long and deep subsurface cracks 

are evident. In the case of the B heat exchanger, one circumferential weld heat-affected zone crack 

extends over 50 percent of the way around the circumference and more than one third of the way through 

the thickness of the heat exchanger shell wall,91 as shown in Figure 21 and Figure 22. 

Figure 21. Circumferential Weld Damage in the B Heat Exchanger. This photograph from the 

Spectrum inspection report on the B heat exchanger (Appendix G) shows the large crack directly 

downstream of the stainless steel clad portion of the heat exchanger. (The light green line below the 

dark black area is the crack; the dark portion is the edge of the stainless steel cladding.) This 

macrocrack formed in the high-stress region near the weld because of the linkage of microcracks and 

fissures caused by HTHA. 

 

90 See Appendix J 

91 See CSB’s E-6600E and E-6600B Metallurgical Analysis report (Appendix I). 
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Figure 22. Comparison of Damage Locations in the B and E Heat Exchangers. Severe HTHA damage 

is found in the B heat exchanger in the same locations where the E heat exchanger ruptured. 

NIST determined that without the HTHA damage, it is unlikely that the E heat exchanger would have 

ruptured under the conditions that occurred during the April 2010 start-up. However, both the B and E 

heat exchangers were severely degraded and had the potential to suffer a catastrophic rupture because of 

the advanced stages of HTHA evident in both heat exchangers. 

 
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4.3 Timing of the Incident 

Process data indicate that the D/E/F tube outlet temperature increased about 75 °F over a span of three 

minutes immediately before the rupture, as graphed in Figure 23. The CSB compared these changes in 

temperatures to those from the previous three startups. This magnitude of temperature increase is typical 

compared to the previous startups (Appendix B) and is likely explained by the difficulty of trying to 

maintain process control by manually operating large isolation block valves that were not designed as 

flow control valves.92

The E heat exchanger was in a severely degraded mechanical condition because of long-term cracking 

damage from HTHA. In addition to the increased mechanical stress from the startup of the A/B/C heat 

exchangers, this momentary increasing temperature appears to have been sufficient to cause the actual 

material strength of the critically weakened heat exchanger to be exceeded, rupturing the E heat 

exchanger at its weakest point – the area of the heat exchanger that was most damaged by HTHA. This 

scenario is the most likely explanation of the timing of the failure of the heat exchanger during the A/B/C 

heat exchanger startup, but it did not cause the failure. 

 

92 A block valve is a manually operated valve that is normally fully open or fully closed. Block valves are typically 

designed for tight shutoff when closed and for minimal obstruction of flow when open. These valves are not 

designed to throttle or control flow. 
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Figure 23. Temperature and Pressure Trends before the Anacortes Incident 

4.3.1 NHT Heat Exchanger Startup Conditions 

The CSB examined startup activities and process data at the time of the incident and concluded that no 

equipment mechanical integrity code parameters were exceeded. Temperature trends from the time when 

the A/B/C heat exchanger bank was coming on-line were compared to those from the three previous 

startups (as explained in Appendix B). All of the temperature trends are similar. The maximum 

allowable working pressure of the E heat exchanger was 655 psig at 650 oF. The operating data indicate 

that the design temperature of 650 oF was not exceeded before the rupture. 

The E heat exchanger was protected from excessive pressure by a pressure relief valve on a downstream 

vessel, which was set to relieve the pressure at 585 psig.93 Operating data indicate that the pressure relief 

valve was not challenged and did not open before the incident. The relief valve was inspected and tested 

after the incident, and it opened at the designated set pressure. 

 

93 This relief valve is located further downstream in the process. As a result the exchanger pressure is higher than 

the relief valve set pressure. This pressure difference is accounted for by the engineering design and documented 

in the relief system calculations. 
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As a result of this analysis, the CSB excluded improper operation of the NHT heat exchangers during 

startup as a plausible contributing cause of the incident. 

4.4 Process Conditions of the B and E Heat Exchangers 

In refineries and chemical plants, key temperatures, pressures, flow rates, and other data are typically 

measured using a distributed control system (DCS). This system tracks and records data reported to the 

system via instrumentation in the plant and can visibly display important variables to control room 

operators. Operators also can manually record data from field instrumentation that does not report to the 

DCS. 

Tesoro monitored temperatures and pressures of the process fluid entering and exiting the NHT heat 

exchanger banks, via both local field instrumentation and instrumentation that reported to the DCS. The 

locations of the temperature (TI) and pressure (PI) indicators are shown in Figure 24. 

Figure 24. Temperature and Pressure Indicators for the NHT Heat Exchanger Banks. This isometric 

process flow view depicts the lack of temperature indication on both the shell-side and tube-side of the 

B and E heat exchanger inlets and outlets. 

 
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Although some temperature and pressure measurements were 

taken surrounding the NHT heat exchanger banks, no temperature 

measurements were made between the heat exchangers. Thus, 

Tesoro did not know the operating temperature of the process fluid 

entering and exiting the B and E heat exchangers.94 Had Shell Oil 

or Tesoro performed a technical evaluation or installed 

instrumentation to monitor temperatures at these locations, a better 

evaluation of potential HTHA hazards could have been performed, 

and more effective safeguards could have been implemented. 

4.4.1 CSB Modeling of the NHT Heat Exchangers 

Because of the minimal temperature measurements of the NHT heat exchanger banks, the CSB performed 

process modeling to estimate the operating temperatures and hydrogen partial pressures of the B and E 

heat exchangers by using computer-based chemical process design software packages.95 The model 

required the use of several assumptions, such as fouling distribution, because of a lack of both process 

and fouling data gathered by Shell Oil and Tesoro. Consequently, all model results are estimates of the 

actual process conditions experienced by the NHT heat exchangers. The CSB used the model to estimate 

the operating conditions of each heat exchanger based on the available Tesoro operating data, including 

temperatures, pressures, flow rates, and fluid composition data. The model development process and 

associated results are described in Appendix C. A summary of the modeling results is depicted in Figure 

25, Figure 26, and Figure 27. 

 

94 A single external surface temperature measurement of 455 oF was taken in October 1998 on the inlet to either the 

B or E exchanger. 

95 Aspen HYSYS and Aspen Exchanger Design and Rating. 
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Figure 25. Model Results for Can 4. The stainless-steel-clad portion of the carbon steel B and E heat 

exchangers was estimated to occasionally operate above the carbon steel Nelson curve. No HTHA was 

found in this region, likely because stainless steel cladding reduced the potential for HTHA in the 

carbon steel beneath it. Tesoro’s design B and E process condition used for HTHA evaluation (504 F 

and 291 psia hydrogen partial pressure) did not represent the entire range of heat exchanger operating 

conditions. 
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Figure 26. Model Results for the Weld Downstream of Can 4. The circumferential weld immediately 

downstream of the stainless-steel-clad portion of the carbon steel B and E heat exchangers was 

estimated to operate just below the carbon steel Nelson curve. Extensive HTHA was found in this 

region, the hottest rupture location of the E heat exchanger and the major crack location of the B heat 

exchanger. 
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Figure 27. Model Results for the Coldest Region of the E Heat Exchanger. The coldest region of the E 

heat exchanger with evident HTHA was estimated to operate as much as 120 0F below the carbon steel 

Nelson curve. 

4.4.1.1 HTHA Occurred Below the Nelson Curve 

CSB process modeling estimates demonstrated that the hottest 

portion of the B and E heat exchangers with evident HTHA, the 

circumferential weld between “Can” 3 and “Can” 4, operated below 

the carbon steel Nelson curve. HTHA was also identified at the 

circumferential welds between “Can” 2 and “Can” 3, and also 

between “Can” 1 and “Can” 2. Modeling results also indicate that 

HTHA was found 

in locations that were 

estimated to operate 

up to 120 0F below 

the carbon steel 

Nelson curve. 
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the coldest region in the E heat exchanger96 with identified HTHA was estimated to have operated up to 

120 0F below the carbon steel Nelson curve. This finding suggests that the long-standing industry carbon 

steel Nelson curve is inaccurate—it cannot be relied on to prevent HTHA equipment failures, and it 

cannot be reliably used to predict HTHA equipment damage. 

4.4.1.2 Estimate That a Portion of the B and E Heat Exchangers Operated Above the 

Nelson Curve 

The CSB modeling analysis estimated that during operation while fouled, the stainless-steel-clad portion 

of the B and E heat exchangers at times likely operated above the carbon steel Nelson curve. This section 

was not damaged by HTHA, probably because the stainless steel cladding protected the carbon steel 

beneath it. As discussed in Section 5.3.3, operation near or above the carbon steel Nelson curve should 

have triggered an inspection for HTHA by Tesoro, but the company never performed such an inspection. 

4.4.1.3 Tesoro’s Replacement Heat Exchangers 

Since the April 2010 incident, Tesoro has installed new NHT heat exchangers with upgraded materials of 

construction to significantly reduce the potential for HTHA.97 In addition, an advanced process control 

system is in place to minimize fouling. The heat exchangers are also constructed using only one bank of 

exchangers. The entire NHT unit now must be shut down for cleaning, eliminating the hazards of online 

switching and creating a much safer approach for maintenance. The new heat exchangers also 

incorporate additional instrumentation to allow the monitoring of each heat exchanger for fouling and 

decrease the likelihood of operation in HTHA-susceptible conditions. 

 

 

96 HTHA was not conclusively identified in the B heat exchanger in this region. Only a limited metallurgical 

analysis was performed on the seam between Can 1 and Can 2 of the B heat exchanger. 

97 Although the materials of construction are upgraded in the new exchangers, portions of the heat exchangers that 

use carbon steel are designed to operate at temperatures of more than 400 0F. 
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5.0 Organizational Deficiencies 

Similar to the results of the CSB investigation of the disastrous March 2005 explosion at the BP Texas 

City site, the CSB identified deficiencies in the process safety culture and organization at the Tesoro 

Anacortes Refinery that contributed to the April 2, 2010, incident. At the time of the incident, 

deficiencies in the Tesoro process safety culture and organization coincided, with catastrophic 

consequences. The organizational deficiency allowed many personnel in a hazardous region, and the 

process safety culture problems led to a failure to control HTHA hazards, resulting in a major fire and the 

loss of seven lives. 

5.1 NHT Heat Exchanger Flanges – A History of Leaking 

During startup following cleaning, the NHT heat exchangers would frequently leak from flanges, 

occasionally resulting in fires that created hazardous conditions for workers. This hazard had persisted 

for more than a decade; the CSB found that the earliest documentation of these leaks was from 1997, 

when Shell Oil owned the refinery. 

Over the years, Tesoro attempted maintenance and engineering 

solutions to stop the heat exchanger leaks. In 2008, management 

and labor even jointly conducted a triangle of prevention (TOP)98

investigation that analyzed, in part, the NHT heat exchanger 

leaks. However, these attempts did not effectively resolve the 

problem of the heat exchangers leaking during startup; as a result, 

various operational techniques were developed to accommodate 

the fact that the leaking would typically cease once the heat 

exchangers stabilized at their normal operating temperatures. The 

leaks were very hazardous as the hot naphtha was highly 

flammable99 and had the potential to be operating above its 

autoignition temperature. However, because these leaks were 

never effectively prevented, the leaks from the NHT heat 

exchangers during startup became an accepted and normalized condition at Tesoro. 

 

98 The TOP program is a joint union-management workplace safety program that applies the knowledge of the 

workforce to understand and eliminate workplace hazards. 

99 The flash point is defined as the minimum temperature at which a liquid gives off sufficient vapor to form an 

ignitable mixture with air near the surface. The Tesoro Material Safety Data Sheets (MSDSs) for naphtha list its 

flash point as -7.1 oF. Liquids with a flash point of less than 23 oF fall into the highest hazard category of the 

Globally Harmonized System of Classification and Labeling of Chemicals (known as the GHS). See: 

https://www.osha.gov/dsg/hazcom/ghs.html#3.1 (accessed December 31, 2013). 
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5.1.1 Incident Report That Demonstrates Normalization of Hazardous Conditions 

The CSB identified an incident report describing a startup of the NHT D/E/F heat exchanger banks in 

March 2009, a year before the April 2010 incident, that resulted in the exposure of workers to hazards 

from both hot steam and leaking hydrocarbons while they put the NHT heat exchangers back in service. 

This incident report demonstrates the normalization of hazardous conditions that had been established at 

the refinery. 

The 2009 report states that the “exchangers leaked substantially” and that the leaks were “steady streams” 

flowing from each of the three heat exchangers being put in service. The incident report then describes 

how workers responded to the leaks by continuing the startup, while wearing only standard refinery 

personal protective equipment, to reach the desired heat exchanger temperatures. This long-standing 

practice was used to stop atmospheric hydrocarbon releases from the NHT heat exchangers. The report 

states that “[s]team lances were positioned at all leak locations.” Tesoro employees “continued the 

startup of the heat exchangers while monitoring leak status....” Eventually, the target exchanger 

temperatures were achieved, and the leaks stopped. 

This continuation of the startup – despite the exposure of workers to significant hazards – demonstrates 

the normalization of the extremely hazardous NHT heat exchanger leaks. The leaking of hightemperature, highly flammable process fluids constitutes a serious process safety incident. However, 

during the 2009 incident, the refinery alarm was not sounded; an emergency response team was not 

activated; the leak was not isolated from the unit; and the unit was not shut down. The incident report 

also did not address the need for permanent corrections to stop the leaks. Although Tesoro did make 

additional attempts to correct the heat exchanger leaks as discussed in Section 5.1.4, ultimately these 

efforts were unsuccessful and the CSB found that leaks did occur during the startup of the NHT heat 

exchangers on the night of the April 2010 incident. 

5.1.2 TOP Investigation of Fires 

In 2008, a TOP investigation team was assembled to begin what would become a ten month investigation 

into a series of loss of containment incidents at the Tesoro Anacortes Refinery, including some that 

resulted in fires. In all, fourteen refinery incidents that occurred between May 2003 and December 2007 

were investigated during this process. The TOP team investigation included the frequent leaks from the 

NHT heat exchangers during startup. 

The findings of the Tesoro TOP investigation team included the following: 

 Tesoro classified incidents involving incipient fires100 as “level 1” incidents that are reported but 

do not require investigation. The 2008 TOP investigation was launched after multiple level 1 

 

100 In 29 CFR 1910.155(c)(26), OSHA defines “incipient stage fire” as a fire that is in the initial or beginning stage 

and that can controlled or extinguished by portable fire extinguishers, a class II standpipe, or small hose systems 

without the need for protective clothing or breathing apparatus. 
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incidents appeared to have common causal factors. The report noted that it was very difficult to 

complete a proper TOP investigation when many of the incidents were so far in the past. 

 NHT heat exchanger leaks were common during startup. However, because the leaks tended to 

stop after operating temperatures were reached, incident reports were sometimes not filed. The 

incidents were treated as “normal” startup events, and steam lances were considered to be 

acceptable leak mitigation. The TOP investigation team noted complacency at the refinery 

because these events were so common and also cited a growing lack of concern toward activating 

emergency response. 

 A Tesoro mechanical engineer had at one time actively pursued mitigation of NHT heat 

exchanger leaks. Procedural changes for startup and shutdown were made, and the heat 

exchanger gasket surfaces were repaired. However, the engineer left Tesoro, and no further 

progress was made because of a combination of poor communication and a lack of 

implementation tracking. 

 Only one of the fourteen incidents investigated had prompted a previous TOP investigation, even 

though five of the fourteen investigated incidents involved fires in process units. The TOP 

investigation team concluded that this complacency in investigation practices caused associated 

complacency in the workforce toward process-related fires. 

5.1.3 MOCs Did not Effectively Control Hazardous Conditions 

A contributing factor to the presence of some of the six additional personnel in the NHT unit at the time 

of the April 2010 incident was likely the need for them to assist with steam lance use in anticipation of 

leaks during startup.101 Relying on steam suppression to mitigate leaks during NHT heat exchanger 

startups was a common practice and was part of the startup procedure. In October 2009, Tesoro approved 

a Management of Change (MOC) to install two new permanent steam stations near the NHT heat 

exchangers, shown in Figure 28.102

 

101 The CSB identified four steam lances near the NHT heat exchangers following the April 2010 incident. Three of 

the four steam lances were likely active at the time of the incident. 

102 The “Purpose” of the change was to “Provide improved response time and safety when responding to flange fires 

in the vicinity of the E-6600 exchanger structure.” However, the steam equipment was installed in the 

immediate vicinity of the exchangers and nothing prohibited this steam suppression equipment from being used 

to mitigate a leak from the exchangers. The project to install additional steam suppression equipment was 

competed in January 2010. One of the new steam stations is shown in Figure 28. 
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Figure 28. Steam Station and Steam Lance. This post-incident photograph shows a new steam station 

(left) with a connected steam lance (right). 

MOC is one of the 14 elements of the state of Washington PSM regulations.103 Although the PSM 

regulations impose a general requirement to perform a PHA 104 at least every 5 years, a formal hazard 

evaluation is not required for an MOC. The Tesoro MOC policy states, “Management of Change helps 

ensure that changes to a process do not inadvertently introduce new hazards or unknowingly increase the 

risk of existing hazards.” However, Tesoro decided that a hazard evaluation of the addition of steam 

stations was not required under their procedures because additional steam stations only involved a minor 

change to a utility system. Yet, the installation of the additional steam equipment enhanced the ability of 

the field operator(s) to confront hazardous leaks and extinguish fires in the area of the NHT heat 

exchangers, and the safety implications of these activities were not considered. 

 

103 MOC is one of the 14 elements of the WAC rules for PSM of highly hazardous chemicals. See

http://www.lni.wa.gov/wisha/rules/hazardouschemicals/#WAC296-67-045 (accessed December 25, 2013). 

MOC is also required by EPA RMP (See http://www.epa.gov/oem/content/lawsregs/rmpover.htm. (accessed 

December 25, 2013)) and is an element of the federal OSHA PSM regulations (See

https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=9760 (accessed 

December 25, 2013). 

104 A PHA is a hazard evaluation to identify, evaluate, and control the hazards of a process. Facilities that process a 

threshold quantity of hazardous materials, such as the Tesoro Anacortes Refinery, are required to conduct a PHA 

per the WAC Title296 Chapter 67, Safety standards for PSM of highly hazardous chemicals (1992). See:

http://apps.leg.wa.gov/wac/default.aspx?cite=296-67 (accessed September 29, 2013) PHAs are also required by 

the federal EPA RMP. 
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Good practice guidelines such as those published by the CCPS advise that a hazard assessment should be 

performed during MOC reviews.105 Tesoro should have conducted a formal hazard evaluation for the 

MOC and should have considered more robust alternatives to steam lances such as protecting workers by 

effectively correcting the mechanical problems that were causing the leaks. 

Washington PSM regulations require MOC reviews to consider the impact of proposed changes on 

operating procedures.106 However, operating procedures were not reviewed or modified as part of the 

MOC review conducted for the new steam suppression equipment. The existing NHT heat exchanger 

startup procedure only addressed field tasks for a single NHT outside operator. The procedure instructed 

the operator to have a steam hose (lance) ready in case a leak developed and to warm the heat exchangers 

slowly to prevent leaks, but if leaks did occur, to continue the startup as follows: 

Keep an active steam hose on hand in case of leaks. 

Slowly heating the bundle up to prevent leaks. 

Heating the exchanger too fast can cause leaks. If the heads begin to 

leak, they will usually reseal themselves as they come up to temperature. 

When the ability to use multiple steam lances on the NHT heat exchanger leaks was provided, the 

operating procedure was not updated to reflect the ability for, and likely presence of, additional personnel 

to operate those steam lances. In addition, no guidance was developed or provided to establish how large 

a leak or fire the field operator(s) was expected to fight and no evaluation was made to assure there was 

proper allowance for emergency egress from a large leak or fire. Tesoro did not view the NHT heat 

exchanger startup and history of leaks as high hazard activity—a reflection of the normalization of the 

hazardous conditions. 

5.1.4 Unsuccessful Tesoro Attempts to Prevent Heat Exchanger Flange Leaks 

Tesoro sporadically made attempts to prevent the leaking of the NHT heat exchangers. These attempts 

included: gasket modifications, changes to torque and bolting practices, resurfacing of flange surfaces, 

and the installation of warm-up piping to smooth the transition from cold to hot equipment during heat 

exchanger startup. Following the severe leaks from the NHT heat exchangers during the March 2009 

startup, in August 2009 Tesoro installed a different type of gasket in the NHT heat exchangers. During 

the startup that followed, Tesoro records indicate that no leaks from the heat exchangers occurred. Tesoro 

representatives told the CSB that this startup was evidence of “success” in correcting the NHT heat 

 

105 An important aspect of an MOC is assessing the hazards associated with proposed changes. The MOC team 

should determine the level of hazard evaluation needed for specific types of changes, but site management may 

decide that formal hazard evaluations are necessary for certain types of changes. The MOC process should 

provide sufficient information about the change to conduct a hazard evaluation. Center for Chemical Process 

Safety (CCPS). Guidelines for the Management of Change for Process Safety. 2008; pp 52-54. 

106 Modification to operating procedures is part of the MOC requirements addressed by the WAC process safety 

management regulations. See http://www.lni.wa.gov/wisha/rules/hazardouschemicals/#WAC296-67-045

(accessed December 25, 2013). 
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exchanger leaks. However, this was the last startup before the April 2010 incident, and a single 

successful startup without leaks is not evidence of long-term success.107 One of the four steam lances 

likely used for leak mitigation on the night of the April 2010 incident is shown in Figure 29. 

Figure 29. Post-Incident Steam Lance. This photograph shows a steam lance that was likely used 

during the startup. 

In addition, the Tesoro Anacortes Refinery has a history of incidents related to flange leaks.108 Despite 

industry best practices that require use of new heat exchanger gaskets, Tesoro documents indicate that the 

company noted that the new NHT heat exchanger gaskets, installed to prevent future startup leaks, could 

be re-used after subsequent cleaning cycles.109 In contrast, gasket manufacturer guidance and industry 

 

107 On the night of the April 2010 incident, two different operators reported two leaks during the startup of the heat 

exchangers. One leak was reported just before the incident. 

108 Tesoro incident reports document a history of gasket failures at the refinery. A variety of causes were identified 

for these past failures including loose bolts, damaged gaskets, installation of the wrong gasket, defective gaskets, 

and other installation-related causes. The Tesoro 2008 TOP investigation identified a contributing cause to the 

fires in the NHT unit was that “[f]langes and/or gaskets may have been damaged due to poor access and high 

maintenance frequency.” 

109 The notation indicated that the gasket vendor informed Tesoro that these gaskets could be re-used. Maintenance 

records indicate that the job plan did call for new gaskets. 
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best practice guidance indicate that new gaskets should be installed and that gaskets should not be reused.110,111 

Regardless, Tesoro’s perceived “success” in resolving the NHT heat exchanger leaks in August 2009 did 

not result in the presence of fewer personnel during the April 2010 startup. In fact, Tesoro normalization 

of the hazardous NHT heat exchanger leaks ultimately contributed to the presence of a significant number 

of additional workers near the NHT heat exchangers at the time of the incident and thus a larger number 

of fatalities as a result of the heat exchanger failure. 

5.2 Hazardous Nonroutine Work 

Nonroutine work can be a highly hazardous operation. Work is performed on equipment that might or 

might not be shut down while adjacent equipment containing hazardous process material continues to 

operate. This type of operation places maintenance and operations personnel at risk. The CCPS provides 

the following guidance: 

Experience indicates that many accidents do not occur during “normal” 

operation but, rather, during such nonroutine modes of operation.112 

By its nature, nonroutine work carries with it the potential for 

unrecognized hazards that sometimes has led to a catastrophic 

incident.113

During the period 1970 to 1989, 60 to 75% of major incidents in 

continuous processes occurred during “non-routine” modes of operation; 

i.e., in operating phases other than the continuous operation of the 

process after start-up.114 

The 1989 Phillips Houston Chemical Complex fire and explosion, which killed 23 workers, expedited 

issuance of the PSM standard. Similar to the April 2010 Tesoro Anacortes Refinery incident, it involved 

the performance of hazardous nonroutine work in a running process unit.115

 

110 When a flanged joint is opened, the gasket should be not be re-used. A new gasket should always be installed. 

Mannan, S. Lee’s Loss Prevention in the Process Industries, Hazard Identification, Assessment and Control. 

Chapter 21, “Equipment Maintenance and Modification.” p 25. 

111 Lamons. Gasket Handbook. 2012; p 113. See

http://www.lamons.com/public/pdf/lit_reference/LamonsGasketHandbook2012.pdf (accessed December 27, 

2013). 

112 Center for Chemical Process Safety (CCPS). Revalidating Process Hazard Analyses. 2001; pp 31-32. 113 Center for Chemical Process Safety (CCPS). Guidelines for Auditing Process Safety Management Systems. 

2011; p 393. 114 Center for Chemical Process Safety (CCPS), Guidelines for Hazard Evaluation Procedures. 2008; p 257. 115 U.S. Department of Labor. A Report to the President: Phillips 66 Company Houston Chemical Complex 

Explosion and Fire. April 1990; p 21. 
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The state of Washington’s PSM regulations also stress the importance of employers identifying the 

hazards of nonroutine work in process areas and then communicating such hazards to those employees 

performing the work.116 

Tesoro acknowledged both the potential hazards and relevance of nonroutine work to the Anacortes 

refinery incident in its own investigation report on the April 2010 incident. 

Continuous petroleum or chemical processes operate most effectively 

when they are in a steady state. Non-routine activities, including startup 

or shutdown, can create additional risks because parameters such as flow, 

temperature and pressure are in a state of flux.117

5.2.1 CSB Investigation of Tosco Avon Refinery 

On February 23, 1999, a fire occurred in the crude unit at the Tosco Corporation’s Avon oil refinery in 

Martinez, California.118 Workers were attempting to replace piping attached to a 150-foot-tall distillation 

column119 while the process unit was in operation. During removal of the piping, naphtha was released 

onto the hot distillation column and ignited. The flames engulfed five workers located at different heights 

on the column. Four workers were killed, and one worker sustained serious injuries. 

The CSB investigated the incident and determined that the refinery’s management system did not 

recognize or control the serious hazards posed by performing nonroutine repair work while the crude 

processing unit remained in operation.120 Although the piping replacement activities at Tosco were 

dissimilar to starting up the heat exchanger bank at the Tesoro refinery’s NHT unit, both involved 

hazardous nonroutine work. 

A key conclusion and recommendation from the CSB 1999 Tosco investigation addressed the importance 

of advance planning and thorough hazard evaluations for the safe performance of higher hazard 

nonroutine work. Management has the obligation to identify hazards, implement effective controls and 

 

116 See WAC 296-67-291 Appendix C, Compliance guidelines and recommendations for process safety management 

(nonmandatory) http://www.lni.wa.gov/WISHA/Rules/hazardouschemicals/default.htm#WAC296-67-021

(accessed December 3, 2013). 

117 See TOP Investigation Team Report. Naphtha Hydrotreater E-6600E Failure, 12:35 a.m., April 2, 2010, 

Anacortes Refinery, Washington. p 21. http://tsocorp.com/wp‐

content/uploads/2014/01/Anacortes_final_report.pdf (accessed April 2, 2014). 118 Ultramar Diamond Shamrock Corporation purchased the Avon oil refinery in September 2000 and renamed it the 

Golden Eagle Refinery. Tesoro purchased the Golden Eagle Refinery in 2002 and was the final party to respond 

to the CSB site-based safety recommendations from the 1999 Tosco incident. 

119 A distillation column is an oil refinery processing vessel that separates preheated hydrocarbon mixtures into 

various components based on boiling point. The separated components are referred to as fractions or cuts. Inside 

the column some trays draw off the fractions as liquid hydrocarbon products (such as naphtha), and piping 

transports them to storage or other units for further processing. 

120 CSB Investigation Report, Refinery Fire Incident – Tosco Avon Refinery, March 2001. See

http://www.csb.gov/assets/1/19/Tosco_Final_Report.pdf (accessed December 4, 2013). 
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limit personnel exposure to higher-hazard work – but not meeting this obligation is a common failing, 

identified in both the Tesoro and Tosco investigations, that led to the catastrophic incidents. The CCPS 

recommends that companies considering tasks that entail employee access to hazardous areas should 

“minimize the number of people in harm's way should an incident occur.”121

The likelihood of leaks occurring during the startup of the NHT heat exchangers made returning them to 

service a serious hazard to the workers involved. Similar to the Tosco incident, the serious hazards could 

have been more effectively controlled through the use of hazard evaluation techniques and more effective 

management control of the nonroutine work. 

Unlike Tosco, Tesoro had years to evaluate the hazards and effectively control the frequent NHT heat 

exchanger leaks. Multiple incident reports were developed and hazard reviews were conducted. Each of 

these events presented opportunities for Tesoro to recognize the hazardous nonroutine work and 

effectively control the hazards. However, Tesoro never effectively corrected the hazardous startups and 

failed to limit access to a minimum number of essential personnel. 

5.2.2 NHT Heat Exchanger Cleaning and Startup 

While in operation, the NHT heat exchangers fouled, reducing heat transfer between the tube-side and 

shell-side process fluids. This reduction in heat transfer both increased shell-side outlet temperatures and 

decreased tube-side outlet temperatures. To maintain process requirements, the heat exchangers were 

periodically cleaned. Tesoro accomplished this task with hazardous nonroutine work, cleaning one bank 

of heat exchangers at a time while the remainder of the process continued to operate. 

During this nonroutine work, one bank of heat exchangers was isolated, opened, and cleaned, while the 

other bank of heat exchangers remained in operation. This maintenance activity typically lasted at least 

three days. During some of the cleaning operations – for example, when the tubes were removed from the 

heat exchanger to facilitate the cleaning – contractors and specialized equipment were needed in the unit. 

In the past, this operation involved as many as fourteen personnel in the NHT unit at one time while the 

other heat exchanger bank and the remainder of the process continued to operate around them. 

5.2.3 Tesoro Failure to Control Heat Exchanger Startup Hazards 

On April 1, 2010, Tesoro operations staff began implementing the procedure to startup the clean A/B/C 

heat exchanger bank. The startup procedure only described roles for the two NHT operators normally 

assigned to a shift, one in the control room and one outside in the field. However, additional outside 

operators from other units frequently assisted in the heat exchanger startup. In addition to responding to 

potential leaks, supplemental personnel were sometimes requested to assist in the NHT heat exchanger 

startup operations because of the difficult labor-intensive process involved. When starting up a bank of 

NHT heat exchangers, the operator was required to open several large block valves to introduce the 

 

121 Minimize the number of people in harm’s way should an incident occur. See Center for Chemical Process Safety 

(CCPS). Guidelines for Risk Based Process Safety. 2007; p 296. 
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process fluid to the heat exchanger bank that was shut down. The block valves were located on three 

different levels of the NHT structure, as illustrated in Figure 30. The geared mechanisms that opened and 

closed these valves were of a type referred to as “long-winded” because they were physically demanding, 

requiring over a hundred turns (by hand) of large wheels to fully open the valves. In addition, the heat 

exchanger procedures required deliberate and coordinated manipulation of these valves. As a result, 

startup by only the one official NHT outside operator was complex and difficult, and additional personnel 

often assisted with the heat exchanger bank startups. 

Figure 30. Unit structure (left) and manual block valve (right) 

Tesoro routinely relied on additional staff members during NHT heat exchanger startups but never 

assessed the risks or made any attempts to control them. Tesoro did not conduct an MOC to consider the 

risks of these organizational changes, despite its policy that required the performance of such a risk 

assessment.122

 

122 The performance of a MOC review to examine the safety implications of organizational change is not required by 

either the federal OSHA PSM standard or the Washington PSM regulation. Although it is noted that Tesoro 

MOC procedures went beyond regulatory requirements, its failure to apply its own policy to circumstances that 

should trigger a MOOC review underscores the need for a PSM regulatory revision to help ensure that needed 

MOOC safety reviews are not voluntary. In the 2007 BP Texas City investigation report, the CSB recommended 

to the federal OSHA that it revise the PSM standard to require MOC reviews for organizational changes, 

including staffing changes. In response, OSHA sent a memorandum in 2009 to its Regional Administrators, 

stating the new agency position that changes to operating procedures that include organizational changes are 

subject to MOC requirements, even though they are not explicitly applicable. In August 2013, the CSB Board 

voted that the OSHA response was “open-unacceptable.” In December 2013, OSHA published a Request for 

Information (RFI) as a step in the rule-making process to revise the chemical accident prevention regulations, 

including the PSM standard. The RFI seeks public input on whether to revise the PSM standard to explicitly 

require MOC reviews for organizational changes, citing the BP Texas City CSB recommendations. See: 

(https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=FEDERAL_REGISTER&p_id=24053) 
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The Tesoro MOC policy includes a requirement for Management of Organizational Change (MOOC), 

which recognizes that “... changes in an organization can ... sometimes result[] in unrecognized negative 

effects.” For examples, an MOOC is needed in the case of staffing modifications, changes in 

maintenance practices, and shifting of personnel roles and responsibilities – all typical practices used at 

the refinery to provide additional operators from other units to assist in startup of the NHT heat 

exchangers. The MOOC policy includes provisions for providing “[c]lear documentation and 

communication of why the change is necessary” and “[a] clear understanding of the risks involved and 

application of effective measures to reduce, eliminate, or mitigate those risks.” The Tesoro MOOC policy 

covers “non-routine tasks” and includes requirements for the following: 

Document all identified risks; include methods to reduce, eliminate or 

mitigate them [...] 

Review the risks involved with the changes. Ensure discussions include 

human factors, competence, workload issues, and sufficient resources to 

ensure the change can be carried out safely. 

In post-incident interviews, Tesoro employees described the number of employees in the unit at the time 

of the explosion (seven workers) as unusually high. Yet, the CSB learned that it was not unusual for a 

shift supervisor to enlist one to four additional staff members from other units to perform the hazardous 

nonroutine work associated with the NHT heat exchanger startups. Although some employees might 

have perceived this as positive (e.g., reflection on individual willingness to help), the practice actually 

exposes a poor company process safety culture. Tesoro required operators who did not have defined roles 

in the procedure to assist with the startup, a hazardous activity with a long history of incidents. 

An effective PSM system would have corrected the problems with known leaks and fires and would have 

controlled all aspects of hazardous nonroutine work. This approach would include taking proactive 

measures to eliminate worker exposure hazards and limiting access to only the minimum personnel 

needed to perform the tasks.123 The use of more personnel than the number called for in the procedure 

exposed more workers to the high-hazard activity. This higher level of risk to workers should have been 

identified in NHT unit procedural reviews, PHAs, or an organizational MOOC. 

 

(accessed January 3, 2014). While the CSB welcomes this positive step, it is important to note that more timely 

proactive federal PSM revisions requiring MOOC reviews would also require similar PSM revisions in 

Washington’s State Plan OSHA program. If implemented, the revised regulations would have required a safety 

review of staffing changes for the NHT exchanger startup and could have had a preventive impact. 

123 Minimize the number of people in harm’s way should an incident occur. Center for Chemical Process Safety 

(CCPS), Guidelines for Risk Based Process Safety; 2007; p.296. 
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For example, in such a review, Tesoro could have 

recommended automating the NHT heat exchanger 

startup or redesigning the heat exchangers to a single 

bank so that online switching was not possible. 

Automation could have limited the role of the single 

outside NHT operator and minimized exposure to 

hazards. With automation, the task for the outside 

operator could have been reduced to simply opening 

the primary isolation block valves for the A/B/C heat 

exchangers. If the heat exchanger leaks had been 

corrected, there would no longer be a need for multiple 

operators to be actively prepared to mitigate a leak or 

fire during the startup, and the single necessary operator 

could leave the immediate area. The remainder of the 

startup could have been performed by the automatic 

system and controlled remotely by the NHT operator in 

the control room. Such approaches could have 

eliminated the need to station personnel in the 

immediate vicinity of the heat exchangers. Since the 

incident, Tesoro has redesigned the NHT heat 

exchangers to create a single heat exchanger bank. 

Now, online switching is not possible, and automated 

startup can be used to minimize hazards to personnel. If 

Tesoro had taken such an approach before the incident, 

the consequences of the April 2010 incident could have 

been significantly reduced. 

 
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5.3 Process Hazard Analyses Failed to Prevent or Reduce the Consequences 

CSB process modeling estimates suggest that HTHA occurred at the Tesoro Anacortes Refinery at 

temperatures and hydrogen partial pressures below the carbon steel Nelson curve. However, the CSB has 

found that both Shell Oil and Tesoro had many opportunities to prevent the damage caused to the B and E 

heat exchangers by HTHA long before the April 2010 catastrophic failure. Such opportunities included 

the following: 

 DMHRs to predict potential HTHA damage 

 Verification of operating conditions 

 PHAs to identify hazards, evaluate safeguards, and assess considerations for inherently safer 

design. 

The PSM-required PHAs124 conducted on the NHT heat exchangers failed to prevent the April 2010 

incident or to reduce the consequences by limiting personnel access to potentially dangerous areas during 

the hazardous startup activity. The Shell Oil and Tesoro PHAs conducted on the Anacortes refinery NHT 

unit failed to accomplish the following: 

 Effectively evaluate and control hazardous nonroutine operations 

 Effectively evaluate and control the frequent leaks during startup 

 Restrict or limit the number of personnel present during the hazardous nonroutine startup of the 

NHT heat exchangers 

 Identify effective safeguards to control hazards from damage mechanisms such as HTHA. 

5.3.1 Hazardous Nonroutine Operations 

None of the Anacortes refinery PHAs effectively evaluated and controlled hazards associated with the 

nonroutine work necessary to periodically clean the NHT heat exchangers. The Washington PSM 

regulations address the need for nonroutine operations to be evaluated and require that at least one 

member of the PHA team has expertise in nonroutine tasks.125 The CCPS describes the importance of 

PHA evaluations, as well as the hazardous potential and frequent problems of PHAs that lack sufficient 

analysis of nonroutine work as follows:126

 

124 A PHA is a hazard evaluation to identify, evaluate, and control the hazards of a process. Facilities that process a 

threshold quantity of hazardous materials, such as the Tesoro Anacortes Refinery, are required to conduct a PHA 

per the WAC, Title 296, Chapter 67, Safety standards for process safety management of highly hazardous 

chemicals (1992). See: http://apps.leg.wa.gov/wac/default.aspx?cite=296-67 (accessed September 29, 2013). 

PHAs are also required by the federal EPA Risk Management Program. 125 See WAC 296-67-291 Appendix C--Compliance guidelines and recommendations for process safety management 

(nonmandatory) http://www.lni.wa.gov/WISHA/Rules/hazardouschemicals/default.htm#WAC296-67-021

(accessed December 3, 2013). 126 Center for Chemical Process Safety (CCPS). Revalidating Process Hazard Analyses. 2001; pp 31-32. 
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It is not uncommon for initial PHAs of continuous processes to focus 

only on normal operations, failing to address nonroutine, critical 

operating modes such as startup, shutdown, preparation for maintenance, 

emergency operations, emergency shutdown, and other activities whose 

characteristics may differ considerably from normal operations. 

Experience indicates that many accidents do not occur during “normal” 

operation but, rather, during such nonroutine modes of operation. 

Consequently, it is important that a PHA evaluate the hazards of a 

process during nonroutine as well as normal (routine) operating modes.

The 1996 Shell Oil PHA for the NHT unit did not evaluate or identify any issues related to nonroutine 

hazardous work associated with the frequent NHT heat exchanger cleaning operations. The 2006 Tesoro 

NHT unit PHA revalidation identified startup as a nonroutine operation but noted that existing procedures 

were adequately addressing nonroutine work. 

5.3.2 Access Was Not Controlled During Hazardous NHT Heat Exchanger Startup 

The 1996 Shell Oil NHT unit PHA did not identify or analyze leaks from the NHT heat exchangers, and 

no recommendations were made to prevent these leaks. The 2001127 and 2006 Tesoro NHT unit PHA 

revalidations also did not mention the frequent leaks from the NHT heat exchangers.128 The 2010 Tesoro 

NHT unit PHA team reviewed the March 2009 NHT heat exchanger startup incident where a steady 

stream of flammable hydrocarbons leaked from the exchangers near workers. In its evaluation of this 

incident, the PHA team reviewed unspecified “administrative controls” and determined that they were “in 

place and effective.” However, the CSB identified no administrative controls in place to minimize the 

number of workers present or their exposure to these startup hazards. In April 2010, less than two months 

after the PHA team determined that the “administrative controls” were in place and effective, seven 

workers were asked to be present during the hazardous nonroutine startup of the NHT heat exchangers. 

According to the Tesoro procedure, a single field operator should have conducted this startup work. 

 

 

127 The 2001 PHA revalidation conducted by Tesoro did not raise issues related to the NHT heat exchangers. The 

only mention of these exchangers is in the process description. 

128 The 2008 TOP investigation of fires in the Anacortes refinery NHT unit concluded that complacency about 

exchanger leaks was a contributing factor in allowing the problem to persist. 
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5.3.3 Failure to Effectively Identify and Evaluate HTHA Hazards 

During the 38 years that the NHT heat exchangers were in operation, the Anacortes Refinery had many 

opportunities to prevent the April 2010 incident by identifying and effectively controlling the potential for 

HTHA in the B and E heat exchangers. Both Shell Oil and Tesoro performed DMHRs, commonly known 

as corrosion reviews, of the Anacortes refinery’s process equipment to determine the susceptibility to 

damage mechanisms such as HTHA.129 The first documented corrosion study for the NHT unit occurred 

in 1990, with subsequent studies in 1999, 2003, and 2008.130 

A problem common to all of the DHMRs conducted over the 20 years before the April 2010 incident is an 

inaccurate understanding the extent of stainless steel cladding covering the inside surface of the of the B 

and E heat exchanger shell wall. Each damage mechanism review documents that the B and E heat 

exchangers had a protective 316 stainless steel cladding covering the carbon steel wall. However as 

shown in Section 4.2.1, the 316 stainless steel cladding was installed only on the hottest section (Can 4) 

of the heat exchanger. The other three sections of the B and E heat exchanger shell walls were carbon 

steel without any protective cladding. 

The 1999 and 2003 DMHRs document both recognition of the need for proper materials of construction 

and a good understanding of the need to determine accurate equipment operating conditions: 

The prevention of HTHA begins with proper materials selection for the 

anticipated process conditions, i.e., hydrogen partial pressure and 

temperature. Careful review of these process variables must be made not 

only for normal operation but also for any other routine or non-routine 

mode of operation to determine the controlling set of conditions for the 

materials selection. 

Off-normal conditions must be considered in addition to normal 

operating conditions. 

Despite this recognition that the full range of operating conditions should be determined, none of the 

DMHRs requested that a technical evaluation, such as process simulation, be conducted for estimation or 

required that instrumentation be installed to measure the full range of operating conditions of the B and E 

heat exchangers. There were no temperature instruments installed on the B and E heat exchangers, and 

the hydrogen partial pressure is a parameter that must be calculated. Because these values were not 

 

129 Corrosion reviews consist of a process-by-process review of the plant for the susceptibility of API RP 571 

damage mechanisms. A process flow diagram is marked up with process variables (temperature, flow, pressure, 

etc.) and evaluated based on current operating data and past equipment repair history. 130 The 1990 review occurred while Shell Oil still owned the refinery, and was conducted by Shell Oil employees 

and the Shell Westhollow Corporation of Texas. Following the purchase of the refinery in 1998, Tesoro 

contracted with Shell Westhollow for preparation of the 1999 and 2003 study. The 2008 study was conducted by 

Lloyd’s Register Capstone. 
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rigorously evaluated, the Tesoro and Shell damage mechanism hazard reviews relied on design data that 

did not reflect all operating conditions. 

DMHRs were conducted in 1990, 1999, 2003, and 2008. Highlights of the analyses related to HTHA and 

the NHT heat exchangers are summarized in Figure 31. 
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DMHR Author Significant HTHA Information and CSB Findings 

January 

1990131

Shell Oil 

Company 

 DMHR: HTHA inspection of carbon steel is never required for 

operation more than 25 °F below carbon steel Nelson curve. 

 DMHR: Inspection is required every 2 to 3 years if operation is less than 

25 °F below carbon steel Nelson curve. 

 CSB: No specific recommendations are made for B and E heat 

exchangers. 

 CSB: Entire shells of B and E heat exchangers are listed as fully clad in 

Type 316 stainless steel, a material resistant to HTHA. However, only 

the hottest section (Can 4) of the heat exchanger is clad in Type 316 

stainless steel. 132

March 1999 

Reviewed 

again in 

September 

2003 

Shell Oil 

Company 

 DMHR: HTHA occurs before it is detectable. 

 DMHR: HTHA control requires knowing and accommodating actual 

operating conditions. 

 DMHR: In many older units operation of the reactors and heat 

exchangers up to the HTHA limits is economically attractive. 

 DMHR: Operating close to the Nelson curves requires very close 

control and monitoring of operating parameters, coupled with frequent 

inspection for HTHA. 

 CSB: The B and E heat exchanger shells are considered members of the 

same HTHA operating condition – based risk group as the A/D heat 

exchangers. However, no specific guidance is offered for the B and E 

heat exchangers. 

 CSB: Entire shells of B and E heat exchangers are listed as fully clad in 

Type 316 stainless steel, a material resistant to HTHA. However, only 

the hottest section (Can 4) of the heat exchanger is clad in Type 316 

stainless steel.

October 

2008 

Lloyd’s 

Register 

Capstone 

 DMHR: HTHA not a concern since operating conditions are below the 

Nelson curve. 

 CSB: Tesoro process engineering provides B and E heat exchanger 

shell-side temperatures. The values are lower than design, implying less 

risk of HTHA: 

Capstone data: 500 °F  (B and E shell-side)  350 °F 

Design: 504 °F  (B and E shell-side)  405 °F 

Capstone data: hydrogen partial pressure  240 psia 

Design: hydrogen partial pressure  291 psia 

Figure 31. DMHR and CSB Findings on Anacortes HTHA and Heat Exchangers (1990–2008) 

 

 

131 Recommendations reviewed in December 1993. 

132 API RP 941. Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and 

Petrochemical Plants. Figure 1, Note 2, August 2008. Section 5.5 of API RP 941 states that it is not advisable 

to take credit for the presence of a stainless steel cladding. However, the CSB learned that some experts were 

less concerned about HTHA in the B and E exchangers when information provided to them indicates a Type 316 

stainless steel cladding is present. 
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None of these DMHRs conducted in the 20 years before the incident identified the potential danger of 

HTHA in the B and E heat exchangers because they primarily relied on design data instead of measured 

process conditions.133 Although all of these design data indicated operation below the Nelson curve, CSB 

modeling estimated that the hottest portions (Can 4) of the heat exchangers at times operated above the 

Nelson curve. As a result, the B and E heat exchangers were never inspected for HTHA and more 

HTHA-resistant materials were never considered until after the April 2010 incident. It is vitally important 

to fully understand actual operating conditions of refinery processes to ensure that all damage mechanism 

hazards are adequately analyzed. 

5.3.3.1 Insufficient Process Instrumentation 

An important factor in determining HTHA susceptibility is operating temperature. The Anacortes 

refinery HTHA inspection procedure “required” instrumentation to ensure and periodically document that 

the operation was appropriately monitored. However, for the instrumentation to be “required” a 

determination first had to be made that the process equipment was operating within 25°F or 25 psia134 of 

the appropriate Nelson curve. The procedure did not clarify how to make such a determination (which 

would necessitate accurate measurement capability) without already having an accurate measurement. 

The procedure stated the following:

Accurate measurements/determinations of temperature and 

hydrogen partial pressure should be made routinely and the 

records maintained to provide assurance that operating 

conditions remain compatible with Nelson Curve limits. 

Such measurements/determinations/records are required for 

equipment/piping that operate[s] within 25°F or 25 psia of the 

appropriate Nelson Curve.135

No temperature instrumentation was on the B or E heat exchangers. Figure 32 shows where temperature 

and pressure measurement instruments were located on the heat exchanger banks. Intermediate 

temperature and pressure instrumentation was nonexistent. This hazard evaluation barrier adversely 

affected all DMHRs at the Anacortes refinery. The operating temperature was unknown at the B and E 

heat exchangers, specifically as it increased significantly from heat exchanger fouling. With these key 

data absent from the analysis, the technicians, engineers, and damage mechanism experts relied on design 

operating conditions. 

 

133 The 2008 Capstone review used a partial pressure of 240 psia based on a modeling effort associated with an 

engineering project. Also, as previously noted in Section 4.4, a single external surface temperature measurement 

of 455 oF was taken in October 1998 on the inlet to either the B or E heat exchanger. 134 Absolute pressure measured in units of pounds force per square inch, or pounds per square inch absolute (psia). 

135 Although dated January 30, 2006 this procedure appears to have been developed by Shell Oil. The accuracy of 

the data used to develop the Nelson curve is described as being +/- 20 oF. The procedure also describes the 

benefit of stainless steel cladding on the inside surface of equipment to prevent HTHA damage. 
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Figure 32. Temperature and Pressure Instruments on the NHT Heat Exchanger Banks. This 

isometric process flow view shows the lack of temperature indication on both shell-side and tube-side 

of the E and B heat exchanger inlets and outlets. 

5.3.4 HTHA Hazards Were Not Effectively Controlled 

In 1995,136 Shell Oil completed a project PHA related to process modifications that could increase the 

hydrogen partial pressure in the NHT heat exchangers; however, no consideration, evaluation, or 

recommendation was made to account for the impact of this change on the potential for heat exchanger 

damage from HTHA. 

The initial NHT unit PHA completed by Shell Oil in 1996 identified the potential for HTHA in the NHT 

heat exchangers. The PHA cited ineffective, non-specific, judgment-based qualitative safeguards such as 

the facility’s inspection program, unit monitoring, procedures, practices, and limits on key and critical 

 

136 When this project was implemented, a Management of Change (MOC) review was also conducted. The MOC 

did not consider or evaluate the potential impact of increased hydrogen partial pressure on equipment 

susceptibility to HTHA. 
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variables for temperature (based on the Nelson curve) as safeguards. However, the B and E heat 

exchangers were never inspected for HTHA, no instrumentation was in place to monitor the inlet 

temperature of the B or E heat exchangers for Nelson curve limits, and no procedures or practices were in 

place to provide effective protection from HTHA. The effectiveness of these safeguards was neither 

evaluated nor documented; instead, the PHA merely listed general safeguards. If the adequacy of these 

safeguards had been analyzed, improved safeguards to protect against HTHA-related failure of the B and 

E heat exchangers could have been recommended. 

 The 2001137 and 2006 Tesoro PHA revalidations do not address or modify the analysis from the 1996 

Shell Oil PHA. In the 2001 PHA Tesoro included a review of the corrosion control program and a 

specific mechanical integrity checklist associated with the corrosion program. In 2006, the Tesoro 

corrosion program was still using these documents. However, in the 2006 PHA, Tesoro discontinued a 

review of these mechanical integrity programs in part because they were “not a legal requirement.” The 

following CCPS guidance on mechanical integrity does not recommend a focus on minimum compliance 

with regulation and notes: 

...[A] compliance-only program may miss out on many of the 

benefits of a more holistic approach, such as reduced risks for 

employees, the neighboring community, and the facility.138

... the more holistic approach helps to ensure compliance with governing 

regulations and, ultimately, often turns out to be less expensive than the 

minimum compliance effort would have been.139

5.3.4.1 PHA Assumptions That Contributed to Ineffective Control of HTHA Hazards 

For the sixteen year period starting in 1996 and ending in 2012, Shell Oil and Tesoro conducted PHAs at 

the Anacortes refinery that used a set of assumptions for the hazard scenarios and risk assessments 

generated by the PHA team. The purpose of these assumptions was documented as helping the team to 

assess “the worst credible scenarios not the worst imaginable scenarios.” However, based on the CSB 

investigation of the April 2010 incident, the use of these assumptions contributed to PHAs that were not 

effective in controlling process hazards. 

The CSB determined that several of the Tesoro process unit PHA assumptions, shown in boxes in the rest 

of this section, could lead to ineffective evaluation of significant hazards and proposed safeguards 

associated with the immediate causes of the April 2010 incident. 

 

137 The 2001 PHA revalidation conducted by Tesoro did not raise any issues related to the NHT heat exchangers. 

The only mention of these exchangers is in the process description. 

138 Center for Chemical Process Safety (CCPS). Guidelines for Mechanical Integrity Systems. 2006; pp 3-5 

139 Ibid at 5. 
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Tesoro’s PHA assumptions included: 

This assumption likely adversely influenced the evaluation of damage mechanism hazards and contributed 

to these hazards being ineffectively evaluated during the PHA. Equipment damage is a significant causal 

factor for loss of containment, and loss of containment is a primary process hazard. The immediate cause 

of the April 2010 incident was a damage mechanism – HTHA – that the Shell Oil PHA team in 1996 did 

not effectively evaluate. The 1996 PHA team significantly underestimated the risk of NHT heat exchanger 

failure. The frequency was appropriately estimated as being less than three percent, which was considered 

a “Low” frequency in the Shell Oil methodology. However, the consequence of the scenario was 

determined to be “Low to Medium” and significantly less than the actual consequence of the April 2010 

incident. A “Low to Medium” consequence, according to the Shell Oil guidance documents, would include 

the following: 

 A hydrocarbon release of a few hundred to 2,000 pounds; 

 Moderate property damage in the $500,000 to $2 million range; 

 Some recordable injuries140 to workers; or 

 Moderate disruption to refinery operations, with a return to operation within a few weeks. 

As previously noted, to control HTHA hazards the 1996 Shell Oil NHT unit PHA team cited non-specific, 

judgment-based qualitative safeguards, such as the facility’s inspection program, unit monitoring, 

procedures, practices, and limits on key and critical variables for temperature (based on the Nelson curve) 

as safeguards. None of these safeguards were effective, and they did not prevent the catastrophic E heat 

exchanger failure as a result of HTHA damage. 

The 1996 Shell Oil NHT unit PHA was revalidated by Tesoro in 2001 and 2006, but these PHA teams did 

not address or modify the analysis from the 1996 Shell Oil NHT unit PHA. 

The Tesoro 2007 PSM and RMP compliance audit indicated that previous PHAs at the Tesoro Anacortes 

Refinery lacked sufficient detail and did not identify all of the hazards of the process.141 As a result, in 

 

140 OSHA provides the following as examples of recordable injuries, “Cut, puncture, laceration, abrasion, fracture, 

bruise, contusion, chipped tooth, amputation, insect bite, electrocution, or a thermal, chemical, electrical, or 

radiation burn. Sprain and strain injuries to muscles, joints, and connective tissues are classified as injuries when 

they result from a slip, trip, fall or other similar accidents.” See https://www.osha.gov/recordkeeping/newosha300form1-1-04.pdf (accessed January 2, 2014). 

141 The compliance audit was conducted pursuant to the requirements in 40 CFR 68.79 and to the OSHA PSM 

Standard, 29 CFR 1910.119, paragraph (o) triennial compliance audit requirement. As an example of the lack of 

detail in the 2006 Tesoro NHT unit PHA, the 2007 audit compared the NHT unit PHA to the Alkylation unit 

Corrosion Inspection Program 

Assumption: The System has a corrosion inspection program. Leaks or 

loss of containment due to corrosion of pipes and vessels is not credible 

 for pipes and vessels included in these programs. 
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2010 Tesoro conducted a new PHA that was a complete line-by-line evaluation. The 2010 NHT unit PHA 

evaluated hazards associated with the NHT heat exchangers in February 2010, just 38 days before the April 

2010 incident. With the “assumptions” still being used and, notably, the corrosion control and mechanical 

integrity programs no longer being reviewed as part of the PHA program, the 2010 Tesoro NHT unit PHA 

team did not identify the potential hazard of B or E heat exchanger shell failure because of HTHA 

damage.142 

Using this assumption contributed to PHA teams not effectively evaluating proposed inspection-related or 

maintenance-related safeguards. The 1996 Shell Oil NHT unit PHA stated that the inspection program was 

a safeguard to prevent HTHA failure of the NHT heat exchangers. However, the B and E heat exchangers 

were never inspected for potential HTHA damage. 

Using this assumption contributed to the PHA teams not considering the susceptibility of materials to 

failure from damage mechanisms such as HTHA, or recommending inherently safer materials such as 300 

series stainless steel to mitigate damage mechanisms such as HTHA.143

 

PHA. The 2007 audit found that although the Alkylation unit had approximately half the complexity of the NHT 

unit, the Alkylation unit PHA conducted four times more hazard evaluation scenarios and made nearly 15 times 

more recommendations than the 2006 Tesoro NHT unit PHA. 142 The term “shell” in this context refers to the pressure containing carbon steel wall of the heat exchanger. The 

2010 Tesoro NHT unit PHA did identify HTHA as a possible hazard for the tube side of the B and E exchangers. 

Heat exchangers of this design have process flow through two sides, separated by mechanical design. Heat is 

transferred from one side to the other in order to exchange heat. Flow on the inside of the tubes through the heat 

exchanger is commonly referred to as “tube-side”, while flow on the outside of the tubes is called “shell-side”. 

The B and E exchangers had HTHA damage to the pressure containing portion on the shell-side. The 2010 

Tesoro NHT unit PHA did not identify HTHA as a hazard where HTHA occurred on the shell-side of the 

exchanger. 143 As previously discussed, API RP 571 identifies inherently safer materials to prevent HTHA noting, “300 Series 

SS, as well as 5Cr, 9Cr and 12Cr alloys, are not susceptible to HTHA at conditions normally seen in refinery 

units.” See API RP 571. Damage Mechanisms Affecting Fixed Equipment in the Refining Industry. 2003; p “5-

83”. 

Inspection and Maintenance Program 

Assumption: The equipment is inspected per the plant preventive 

maintenance standards, and maintenance is performed promptly. 

Materials of Construction 

Assumption: The materials of construction of piping, gaskets, vessels, and valves 

have been correctly selected according to Shell design standards. 
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5.4 CSB Conclusions on Organizational Deficiencies 

For years, management at the refinery under both Shell Oil and Tesoro failed to effectively evaluate the 

potential for HTHA in the B and E heat exchangers. External corrosion experts repeatedly and 

erroneously assumed that heat exchanger design conditions were representative of actual process 

operating conditions despite knowing that these heat exchangers experienced severe heat transfer 

performance deterioration and required frequent cleaning. 

Tesoro management also allowed worker exposure to hazards from fires and significant hydrocarbon 

leaks during startup of the NHT heat exchangers to become an accepted “normal” practice. Relying on 

steam suppression to mitigate leaks during NHT heat exchanger startups was a common and acceptable 

practice and was part of the startup procedure. Tesoro made attempts to correct the heat exchanger design 

problem that caused the leaks that sometimes resulted in fires, but ultimately these were ineffective. 

Additional employees were frequently brought in to assist the NHT field operator with the labor-intensive 

heat exchanger startup and hydrocarbon leak mitigation. On the night of the incident seven workers were 

performing the role that procedurally was intended for a single outside operator. 

Well-known industrial safety and accident analysis experts James Reason and Andrew Hopkins indicate 

that safety culture is defined by collective practices, arguing that this is a useful definition because it 

suggests a practical way to create cultural change. More succinctly, safety culture can be defined as “the 

way we do things around here.”144,145

Employees respond to issues that capture the attention of leaders.146 Hopkins notes that leadership 

qualities that minimize, downplay, or deny risk will erode a process safety culture. A culture of risk 

denial can include the following characteristics: 

 Belief that it cannot happen here 

 Normalization of deviance (normalization of hazardous conditions) 

 Ad hoc criteria for danger 

 Downgrading intermittent warnings 

 Burden (onus) of proof – requiring proof of danger rather than proof of safety 

 Group think (eliminates minority voices in deference to consensus)147

Several of these characteristics were identified during the CSB investigation of the Tesoro Anacortes 

April 2010 incident, including normalization of hazardous conditions and a misplaced burden of proof of 

 

144 Hopkins, Andrew. Safety, Culture and Risk; The Organisational Causes of Disasters. Sydney, New South 

Wales: CCH Australia Limited. 2005; p 7. 

145 Center for Chemical Process Safety (CCPS), Guidelines for Risk Based Process Safety. 2007; p 40. 146 Hopkins, Andrew. Safety, Culture and Risk. 2005; p 8. 147 Ibid at 20-22. 
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safety.148 It is an important distinction that a company culture, including its process safety culture, is the 

embodiment of its practices and not the sum of its beliefs. Consequently, a process safety culture can be 

objectively measured by examining the process safety practices and outcomes. The practices of the 

Tesoro Anacortes Refinery – the use of excessive number of personnel to participate in hazardous 

activities, the lack of verification of actual process conditions, normalization of hazardous leaks of the 

NHT heat exchangers, and PHA assumptions that contributed to ineffective hazard evaluation of major 

hazards – are all indications of a deficient process safety culture at the Tesoro Anacortes refinery. 

 

 

148 Burden of proof means to require proof of danger rather than proof of safety. It is applicable to the process safety 

culture at the Anacortes refinery and is shown through the repeated use of design data to evaluate the NHT 

exchangers for HTHA susceptibility. Rather than obtain data on actual operating conditions, Shell Oil and 

Tesoro corrosion experts were allowed to repeatedly rely on design operating conditions. Such design operating 

conditions were readily available, but there was no instrumentation to obtain actual operating conditions for the 

B or E exchangers. Refinery management did not require that these experts obtain data on and use the actual 

operating conditions to prove safety when reaching their conclusion that the B and E exchangers were not 

susceptible to HTHA damage. 
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6.0 Industry Codes and Standards 

6.1 API RP 941 Operating Limits and Material Selection for HTHA 

API RP 941 is the industry guidance document that describes how to predict and manage HTHA. API RP 

941 was initially published in 1970 to communicate broadly industry’s experience with HTHA – both 

HTHA occurrences and conditions where HTHA did not occur. 

6.1.1 No Minimum Requirements to Prevent HTHA 

As discussed in Section 4.1.1, industry uses the Nelson curves as lines of demarcation to predict HTHA. 

Above each curve, HTHA is possible for that material of construction, and below the curve, the prediction 

is that HTHA will not occur. Industry also uses these curves to select materials of construction based on 

the anticipated operating conditions and to create an HTHA inspection and prevention program. 

However, API RP 941 is written permissively, and there are no minimum requirements for refiners to take 

any action to prevent HTHA failures.149 Specifically, there are no user requirements as follows: 

 There are no minimum requirements for users to perform HTHA susceptibility evaluations; 

 There are no requirements for users to select inherently safer materials of construction; and 

 There are no minimum requirements for users to verify process operating conditions of 

equipment that is potentially susceptible to HTHA. 

6.1.2 History of the Nelson Curves 

The Nelson curves are based on industry experience with HTHA and were first developed in 1949 by 

George Nelson,150 who gathered the original data to create the Nelson curves. After his death, none of his 

original data were found; only the information contained on the actual Nelson curves was available to API 

and the rest of industry.151 On the basis of the Nelson curves, in 1970 the API published API RP 941 

Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and 

Petrochemical Plants.

152

API RP 941 contains a submittal sheet for companies to report their experience with HTHA.153 It tasks 

the company reporting HTHA equipment damage to provide a limited and simplistic history of operating 

conditions. API requests only the average and maximum process and metal temperature and a single 

 

149 API RP 941 uses the term “should” 27 times and the word “shall” once. As used in a standard, “shall” denotes a 

minimum requirement to conform to the standard, while “should” denotes a recommendation which is advised 

but not required to conform to the standard. 

150 G. A. Nelson, “Operating Limits and Incubation Times for Steels in Hydrogen Service,” Proceedings, 1965, 

Volume 45, American Petroleum Institute, Washington, D.C. pp. 190-195. 

151 API TR 941. The Technical Basis Document for API RP 941. 2008; p 128. 152 Ibid at 127. 153 HTHA experience includes both reports of HTHA damage and equipment that was not damaged by HTHA. 
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value for hydrogen partial pressure to represent equipment operating conditions. API provides very 

limited instructions on completing the datasheet to report HTHA equipment damage. There is no 

assurance that the data are representative of actual operating conditions. The datasheet reported to API 

does not ensure that the data cover the life of the equipment versus the year, month, or even week before 

equipment failure. The use of a single hydrogen partial pressure value does not ensure that the variability 

of the process is appropriately represented by the data reported. 

As demonstrated in the CSB analysis of the B and E heat exchanger operating conditions in Section 4.4.1, 

refinery equipment often operates at a range of temperatures and hydrogen partial pressures. The API RP 

941 technical report acknowledges this, stating that the authors “find it difficult to obtain accurate 

operating data and material damage assessments.”154 In addition, not all companies report their HTHA 

failures to API (for example, Tesoro did not formally report the failure information to API following the 

April 2010 incident). Furthermore, the consequences of HTHA equipment damage, such as a multifatality incident, are not included as part of the data submitted to API. These are significant weaknesses 

in relying on empirical, self-reported data. 

6.1.3 Industry Critiques of Nelson Curves 

The applicability and accuracy of the Nelson curves have been called into question within the refining 

industry. Two comprehensive reports analyze the Nelson curves: the Hydrogen Attack Project and API 

TR 941, The Technical Basis Document for API RP 941. 

The Hydrogen Attack Project is a report by the Materials Property Council155 and the API.156 The report 

presents a history of HTHA analysis, the Nelson curves, and API RP 941. The report highlights problems 

in obtaining accurate data on operating conditions, analogous to the problems that the CSB identified at 

Tesoro, stating:

The only really reliable way to get an equipment exposure temperature is 

to properly measure the actual temperature of the component. Many 

times the process thermocouples are not well located for measuring the 

temperature of a particular component or in the case of exchangers, a 

particular exchanger in a multi-exchanger train. The design and/or 

process flow diagrams may not provide a very good estimate of actual 

operating temperatures.157

 

154 API TR 941. The Technical Basis Document for API RP 941. 2008; pp 45-46. 155 The Materials Properties Council (est. 1966) was founded by the American Society of Mechanical Engineers, 

ASM International, ASTM and the Engineering Foundation and supported by industry, technical organizations, 

codes and standards developers, and government agencies in order to provide valid data on the engineering 

properties of metals. See: http://www.forengineers.org/mpc/index.html (accessed November 21, 2013). 

156 Hydrogen Attack Project, Materials Property Council / American Petroleum Institute, undated. 

157 In this context, the term “train” is synonymous with “bank” and is used to describe multiple heat exchangers in 

series. Hydrogen Attack Project, Materials Property Council / American Petroleum Institute, p 19, undated. 
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API TR 941 was issued as the technical basis 

document for API RP 941.158 This technical report 

addresses several possible limitations of the Nelson 

curves, such as the location and shape of the 

curves.159 API TR 941 acknowledges that there is 

still more to learn about HTHA, stating “We are still 

far from being able to make quantitative predictions 

about the behavior of steels subject to HTHA.”160 

Critics of the Nelson curves also contend that, 

although the curves are easy to apply, their simplicity 

minimizes their effectiveness.161 Critics of the curves 

say that HTHA is a complex phenomenon. The risk 

of HTHA is a function of more than solely the three 

variables described by the Nelson curves (material of 

construction, temperature, and hydrogen partial 

pressure).162 Other variables that are not addressed by 

the curves affect the potential for HTHA, such as 

stress,163 carbide stability,164,165 grain size,166 type of 

weld,167 and time in operation.168 

 

158 API Technical Report 941. The Technical Basis Document for API RP 941. 2008. 

159 Ibid at 2. 160 Ibid at 45. 161 Van der Burg, M.W.D., Van der Giessen, E., and Tvergaard, V. “A continuum damage analysis of hydrogen 

attack in a 2.25Cr-1Mo pressure vessel,” Materials Science and Engineering A241 (1998) 1-13, p1. 162 Ibid at 12. 163 API RP 941. Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and 

Petrochemical Plants. 2008; Section 3.2. 164 A carbide is an intermetallic compound containing carbon. There are many possible combinations of carbon and 

other atoms (such as iron, titanium, niobium, vanadium) that combine to form carbides in steel. Each of these 

carbides has an effect on the properties of the steel. 165 Van der Burg, M.W.D, Van der Giessen, E., and Tvergaard, V. “A continuum damage analysis of hydrogen 

attack in a 2.25Cr-1Mo pressure vessel,” Materials Science and Engineering A241 (1998) 1-13, p12. 

166 Grain size is a fundamental characteristic of steel microstructure, indicating the size of each individual crystalline 

packet of iron atoms (known as a “grain”). 

167 Manna, G., P. Castello, and F. Harskamp. “Testing of welded 2.25CrMo steel, in hot, high-pressure hydrogen 

under creep conditions” Engineering Fracture Mechanics 74 (2007) 956-968, p.956. 168 Shewmon, Paul. Hydrogen Attack of Carbon Steel. Metallurgical Transactions A Vol 7A February 1976, p 280. 
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API TR 941 warns that applying API RP 941 has become less conservative as equipment is pushed to the 

limits of the Nelson curves for economic reasons.169 API TR 941 notes the following: 

The concept of a simple boundary between safe and unsafe operating 

conditions in hydrogen for common alloys, of the type depicted by the 

Nelson curves should not be expected. Certainly material composition, 

heat treatment and stress are well accepted as variables that influence 

behavior. 

Experience shows damage accumulation is time dependent. However, 

the methods of detection and quantification of damage are so inadequate, 

operating conditions so poorly recorded, failure analyses so cursory and 

materials characterization so primitive, that life prediction is on shaky 

grounds today.170

6.1.4 Unreliable Carbon Steel Nelson Curve 

As discussed in Section 4.4.1, CSB process modeling of the Tesoro NHT heat exchangers estimates that 

HTHA occurred below the carbon steel Nelson curve. 

As previously discussed, post-incident analysis of the 

NHT heat exchangers determined that damage from 

HTHA was occurring in portions of the B and E heat 

exchangers that were estimated to have operated 

below the carbon steel Nelson curve. The coldest 

region in the E heat exchanger with identified HTHA 

was estimated to operate up to 120 0F below the 

carbon steel Nelson curve. This finding indicates that 

the industry developed carbon steel Nelson curve is 

inaccurate and cannot be relied on to prevent HTHA 

equipment failures or to predict HTHA equipment 

damage. 

 

 

169 API Technical Report 941. The Technical Basis Document for API RP 941 . 2008; p 45. 170 API Technical Report 941. The Technical Basis Document for API RP 941. 2008; p 47. 
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6.1.4.1 ExxonMobil HTHA Incident Below the Carbon Steel Nelson Curve 

ExxonMobil also experienced equipment damage from HTHA at process conditions that were noted as 

being immediately below the carbon steel Nelson curve.171 Similar to Tesoro, the ExxonMobil incident 

included damage to a heat exchanger of a hydrotreating unit.172 This failure has many similarities to the 

Tesoro April 2010 incident and further highlights that the carbon steel Nelson curves cannot be relied 

upon to prevent HTHA equipment failures.173 Similar to the Tesoro April 2010 incident, cracking was 

observed in non-PWHT carbon steel constructed in the early 1970’s and operating at conditions reported 

as being below the Nelson curve.174 The ExxonMobil HTHA failure also occurred adjacent to weld 

seams in the heat affected zone of the vessel.175 

6.1.4.2 Other Industry Reports of HTHA Damage to Equipment that Operated Below the 

Carbon Steel Nelson Curve 

The CSB has learned of at least eight recent refinery incidents where HTHA reportedly occurred below 

the carbon steel Nelson curve. In addition to the ExxonMobil incident, Valero, Shell, and ConocoPhillips 

have all reported incidents to the API 941 committee where the companies have concluded that 

equipment operating below the carbon steel Nelson curve was damaged by HTHA. Valero reported three 

incidents at their Corpus Christi refinery and one incident at their Texas City refinery. Shell reported at 

least two equipment components in one process unit had HTHA below the carbon steel Nelson curve. In 

addition, ConocoPhillips reported an incident of HTHA below the carbon steel Nelson curve at one 

facility. In 2011, API issued an industry alert on HTHA in refinery service.176 The API alert noted 

multiple incidents of carbon steel equipment at operating conditions where carbon steel was previously 

thought to be resistant to HTHA. These refinery incidents and the subsequent API response strongly 

suggest an industry-wide problem with the carbon steel Nelson curve. 

6.1.5 Essential Adjustments Are Needed to API RP 941 

Although the potential consequences of HTHA-related failure can be catastrophic, API RP 941 currently 

imposes no substantive requirements on users. API RP 941 should require companies to verify the actual 

operating conditions of equipment that is potentially susceptible to HTHA. In addition, API RP 941 

should incorporate the principles of the hierarchy of controls and inherently safer design to prevent 

equipment failures from HTHA. The CSB has identified at least eight incidents in refineries where 

HTHA equipment damage was found at operating conditions below the carbon steel Nelson Curve. 

 

171 McLaughlin, J., Krynicki, J., and Bruno, T. Cracking of non-PWHT’d Carbon Steel Operating at Conditions 

Immediately Below the Nelson Curve. ExxonMobil Research and Engineering Company, Proceedings of the 

ASME 2010 Pressure Vessels & Piping Division, 2010; pp 18-22. 

172 Ibid.

173 Ibid.

174 Ibid.

175 Ibid.

176 See: http://www.api.org/publications-standards-and-statistics/hidden-pages/industry-alert (accessed January 19, 

2014). 
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Furthermore, CSB modeling of the Tesoro Anacortes refinery NHT heat exchangers suggests the E heat 

exchanger failed from HTHA damage that occurred below the Nelson curve. In support of inherent safety 

to prevent equipment failures from HTHA, the CSB proposes a new boundary for the carbon steel Nelson 

curve in Figure 33. This boundary would prohibit carbon steel equipment at process conditions that API 

has identified as susceptible to HTHA, above 400 0F,177 and which operates at greater than 50 psia 

hydrogen partial pressure. 

Figure 33. CSB Modeling Results of HTHA and the Nelson Curve at the Tesoro Anacortes Refinery. 

CSB modeling estimates suggest that HTHA occurred in the B and E heat exchangers below the carbon 

steel Nelson curve. The CSB recommends that the carbon steel Nelson curve be relocated as shown to 

prevent HTHA in carbon steel. 

 

 

177 API Technical Report 941. The Technical Basis Document for API RP 941. 2008; p 6. 
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6.1.6 ANSI Z10, Exemplifies Standards Clarity 

As previously stated, API RP 941 is written permissively with no minimum requirements to prevent 

HTHA failures. In contrast, the American National Standards Institute178 (ANSI) Occupational Health 

and Safety Management Systems standard, ANSI/AIHA Z10-2012 (Z10), provides an improved example 

of how to clearly define obligations in a standard document.179 Z10 makes use of both “should” and 

“shall” language as well as explicit document formatting to differentiate mandatory requirements from 

voluntary recommendations. The following specification addresses the format, which is illustrated in 

Figure 34. 

This [Z10] standard is formatted into two columns to help distinguish 

requirements from recommended practices and explanatory information. 

Requirements are in the left column and are identified by the word 

‘shall.’ An organization that chooses to conform to this standard is 

expected to fulfill these requirements. The text in the right hand column 

uses the word ‘should’ to describe recommended practices, or 

explanatory notes to the requirements on the left. This use of the terms 

‘shall’ and ‘should’ to identify requirements and distinguish them from 

recommendations and explanatory notes is common practice in ANSI 

and international standards.180

 

178 ANSI is a group comprised of government agencies, organizations, companies, academic and international 

bodies, and individuals that oversees the development and use of industry guidelines and standards. For more 

information see http://www.ansi.org/about_ansi/overview/overview.aspx?menuid=1 (accessed January 27, 

2014). 

179 Z10 was developed by over 50 organizations and included representation workers (USW), regulators (OSHA), 

and industry (API). Section 5.1.2 requires the use of the hierarchy of controls to achieve risk reduction for 

identified hazards. ANSI/AIHA Z10-2012. Occupational Health and Safety Management Systems. 2012; p x, xi, 

15. 

180 ANSI/AIHA Z10-2012. American National Standard - Occupational Health and Safety Management Systems. 

June 27, 2012; p.ix. 
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Source: ANSI/AIHA Z10-2012, p.17 

Figure 34. Example of ANSI Z10 Obligations Formatting 

6.2 API RP 580 Risk Based Inspection / 

API 581 Risk Based Inspection Technology 

API intends for risk-based inspection (RBI) to be a process that enables optimization of inspection efforts 

by balancing the time between inspections against the risks of equipment failure caused by the known 

damage mechanisms.181 

API RP 581, Risk-Based Inspection Technology is used in conjunction with API RP 580, Risk-Based 

Inspection. API RP 580 is the API standard for developing an RBI program. API RP 581 is the API 

standard for implementing an RBI program. 

Unlike API RP 941, API RP 581 predicts the susceptibility of HTHA risk versus equipment service time. 

This time-based increase in risk is based on a mathematical model, associating risk with the type of steel. 

The API RP 581 model represents an early attempt to address the shortcomings of the empirical Nelson 

curves. However, API RP 581 lacks specific direction to ensure that users employ appropriate actual 

operating conditions. As a result, the CSB found that using the Tesoro design operating conditions and 

38 years of operation yields a result that the B and E heat exchangers have a “Low Susceptibility” to 

HTHA.182 

 

181 Risk Based Inspection (RBI) Best Practice: The Technical Specification for Ensuring Successful Implementation. 

by Ron Selva B.Sc., C.Eng., F. I. Mech. E; 13th International Conference on Pressure Vessel & Piping 

Technology, 20-23 May 2012, London, Keynote Paper – Technical Session: Managing Risk. 182 API 581 defines three levels of HTHA susceptibility; Low, Medium, and High. Using the E exchanger design 

operating conditions of a hydrogen partial pressure of 291 psi and a temperature of 504 oF along with 38 years of 

continuous service (333,108 hours) into equation 2.51 from API RP 581 results in a HTHA susceptibility 

parameter of 4.53. The minimum value for “Low” HTHA susceptibility is greater than or equal to 4.53. 
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Like API RP 941, API RP 581 is written permissively, so there are no minimum requirements to prevent 

HTHA failures. There are 19 uses of “shall” in RP 581, but none are substantive—nearly all the uses of 

“shall” appear in formulas or requirements for damage factor or in inspection effectiveness calculations 

that are themselves non-mandatory. There are three uses of “shall” in the HTHA section, but again these 

are employed for calculations that are permissive—such as “the following procedure may be used” or if 

HTHA is detected, “fitness for service should be performed.” An instructive example of the 

permissiveness of API RP 581 is that the document provides important guidance for conditions that 

would make equipment susceptible to HTHA damage. However, if the equipment is identified as meeting 

the criteria that would indicate HTHA is a credible damage mechanism, the guidance provided by API RP 

581 is that the equipment “should” be evaluated for HTHA susceptibility. 

 
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7.0 Regulatory Oversight of Petroleum Refineries in Washington 

As addressed in the recently released CSB draft Chevron Regulatory Report, many regions around the 

world such as the United Kingdom (UK) and Australia have implemented regulatory systems for high 

hazards consisting of both prescriptive183 and goal-setting elements184 that place the duty on the owner or 

operator of the facility, known as the duty holder,185 to demonstrate to the regulator that they have 

reduced risks to as low as reasonably practicable, or ALARP. The CSB determined that there are key 

features of an effective major accident prevention regulatory: 

 Duty Holder Safety Responsibility, including a process safety report 

 Continuous Risk Reduction to ALARP 

 Adaptability and Continuous Improvement 

 Active Workforce Participation 

 Process Safety Indicators that Drive Performance 

 Regulatory Assessment, Verification, and Intervention; and 

 Independent, Competent, Well-Funded Regulator. 

The findings, analysis, and conclusions of the Chevron Interim Report and the draft CSB Chevron 

Regulatory Report are applicable to the CSB Tesoro investigation and are incorporated into this report by 

reference. The Chevron Interim Report and the draft Chevron Regulatory Report can be accessed in 

Appendix F. 

The United States has persisted in the use of a more activity-based186 regulatory approach that does not 

adequately engage companies and their employees in continuous improvement and risk reduction. The 

CSB has found that the existing regulatory approach for onshore petroleum refineries in Washington: 

 relies on a framework that is primarily activity-based without a risk reduction target; 

 does not effectively involve the workforce in hazard analysis and prevention of major accidents; 

and 

 does not employ a sufficient number of staff members with the technical expertise needed to 

provide sufficient oversight of petroleum refineries. 

 

183 A prescriptive regulation or standard describes the specific means or activity-based actions to be taken for hazard 

abatement and compliance. 

184 Performance or goal-based regulations state the objective to be obtained (such as risk reduction or hazard 

abatement) without describing the specific means of obtaining that objective. 185 Duty holders are considered to be “those who create and/or have the greatest control of the risks associated with a 

particular activity. Those who create the risks at the workplace are responsible for controlling them.” UK 

Health and Safety Executive, Planning to do business in the UK offshore oil and gas industry? What you should 

know about health and safety; October 2011; p 2. http://www.hse.gov.uk/offshore/guidance/entrants.pdf

(accessed June 5, 2013). 

186 Activity-based standards and regulations require the mere completion of an activity and do not focus on the 

effectiveness of major accident prevention or risk reduction. 
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7.1 Background 

The occurrence of a number of large accidents, 

including a massive explosion and fire at the Phillips 

66 Company’s Houston Chemical Complex in 

Pasadena, Texas, resulting in 23 fatalities, and the 

1984 toxic release in Bhopal, India, which caused 

several thousand known fatalities, resulted not only in 

the creation of the CSB but also in the first federal 

regulations specifically designed to prevent major 

chemical accidents that threaten workers, the public, 

and the environment. One of these regulations is the 

OSHA PSM standard, which was adopted in 1992. 

This standard applies to a process187 involving a 

chemical at or above the listed threshold quantity (also 

known as a highly hazardous chemical), or flammables 

in a quantity of 10,000 pounds or more.188 It contains 

broad requirements to implement management 

systems, identify and control hazards, and prevent 

“catastrophic releases of highly hazardous 

chemicals.”189 Many processes in a petroleum refinery 

are subject to the PSM standard. 

As discussed in the draft Chevron Regulatory Report, the CSB has concluded that the frequent occurrence 

of refinery accidents demonstrates the pressing need to examine the current regulatory structure in place 

in the US. Despite the fact that the nation’s roughly 150 petroleum refineries represent only a small 

fraction of the thousands of industrial and chemical facilities in the US, the CSB has noted a considerable 

number of significant and deadly incidents at refineries over the last decade. In 2012 alone, the CSB 

tracked 125 significant incidents at US petroleum refineries.190 Three of these incidents took place in the 

state of Washington. 

 

187 The PSM standard defines “process” as “any activity involving a highly hazardous chemical including any use, 

storage, manufacturing, handling, or the on-site movement of such chemicals, or combination of these activities.” 

29 CFR §1910.119(b) (1992). 

188 29 CFR §1910.119(a)(1) (1992). This standard also applies to the manufacture of explosives and pyrotechnics in 

any quantity [29 CFR §1910.109(k)(2) & (3)]. 

189 Preamble to Process Safety Management of Highly Hazardous Chemicals; Explosives and Blasting Agents. 

Section 1 – I. Background (March 4, 1992). See 

http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=PREAMBLES&p_id=1039 (accessed May 

10, 2013). 

190 These incidents were reported to the Department of Energy and/or the National Response Center and examined 

by the CSB’s Incident Screening Department. 
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7.2 L&I Division of Occupational Safety and Health (DOSH) 

Section 18 of the Occupational Safety and Health Act of 1970 (OSHAct) 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 as much as 50 percent of an approved plan's operating 

costs. These programs must be “at least as effective in providing safety and healthful employment” as the 

federal PSM standard.191 DOSH administers an approved state occupational Safety and Health Plan in 

accordance with the OSHAct and enforces Washington’s PSM standard under the Washington 

Administrative Code (WAC).192 Although most State Plan states are funded through a state general fund, 

DOSH is funded mostly by an insurance group and by federal OSHA. Unlike the California Division of 

Occupational Safety and Health (Cal/OSHA), DOSH does not have a dedicated PSM unit; rather, it 

currently employs four PSM specialists, including one chemical engineer, to regulate nearly 270 PSMcovered facilities in the state, including five petroleum refineries. One of those specialists has previous 

refinery experience; the other three have experience with ammonia facilities and chemical manufacturing. 

7.2.1 Causal Findings Analysis 

The findings in this report identify a number of weaknesses with Tesoro process safety performance. In 

many of these causal issues, the existing Washington PSM regulations did not require Tesoro to perform 

at a more effective level to control hazards and prevent incidents. In Figure 35 below, the CSB identifies 

the causal issues which highlight the gaps within the Washington and federal PSM regulations, and how 

each issue is more effectively managed in a more robust goal-setting approach. In this section of the 

report, some of these examples will be examined in relation to key features of a more effective regulatory 

approach. 

 

 

191 29 U.S.C. §667(c)(2) (1970). 

https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_id=2743&p_table=OSHACT (accessed 

September 24, 2013). 

192 The Washington PSM standard is established under Title 296, Section 67 of the Washington Administrative Code 

(WAC). 
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Process Safety 

Concept Causal Finding Washington and Federal PSM Regulation and Enforcement 

Goal-Setting 

Regulatory Approach 

MOC 

Tesoro added steam 

stations in the 

vicinity of the heat 

exchanger structure. 

This equipment 

enhanced the ability 

of the field 

operator(s) to 

confront hazardous 

leaks and extinguish 

fires in the area of 

the NHT heat 

exchangers, and the 

safety implications 

of these activities 

were not considered. 

The MOC developed 

by Tesoro did not 

evaluate or control 

hazards associated 

with the heat 

exchanger leaks, 

emergency egress, or 

with how the steam 

equipment would be 

used. Although 

affected, heat 

exchanger startup 

procedures were not 

reviewed or modified 

to account for the 

change. 

The MOC element requires 

implementation of written 

procedures to manage changes 

that shall address the impact of 

the change on health and safety; 

however the element is activity 

based rather than performance 

based and there is no 

requirement to control hazards. 

There is no WAC PSM 

requirement to actually control 

hazards through the MOC 

process. Current regulations 

allowed Tesoro’s narrow focus 

in looking at the change as a 

minor modification to a utility 

system rather than taking a 

broader view of how the change 

could impact the overall process.

The duty holder is 

required to drive risk to 

ALARP. 

Demonstration of 

MOC effectiveness in 

managing major 

accident hazard risk is 

a key requirement of a 

robust goal-setting 

regulatory system. The 

mere existence of 

MOC written 

procedures is 

insufficient under the 

more robust goalsetting regulatory 

approach. 
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Process Safety 

Concept Causal Finding Washington and Federal PSM Regulation and Enforcement 

Goal-Setting 

Regulatory Approach 

PHA 

PHAs in 1996, 2001, 

and 2006 cited 

ineffective, nonspecific, judgmentbased, qualitative 

safeguards to prevent 

equipment failure 

from HTHA. 

However, the 

effectiveness of these 

safeguards was 

neither evaluated nor 

documented; instead 

the PHA merely 

listed them. 

Although the PHA element 

requires addressing the control 

of hazards, it does not require 

addressing the effectiveness of 

the controls or using the 

hierarchy of controls. For 

example, the standard would not 

require the use of improved 

materials of construction or 

inherently safer design to 

mitigate corrosion hazards. 

The goal-setting 

regulatory approach 

requires use of the 

most effective practical 

safeguards to achieve 

ALARP. The goalsetting approach 

requires the use of 

inherently safer design 

and the hierarchy of 

controls.193

PHA 

The 2010 Tesoro 

NHT unit PHA 

failed to identify 

HTHA as a hazard 

for the shell of the B 

and E heat 

exchangers. 

DMHRs are not required by the 

PSM regulation. The PHA 

element does not require 

consideration of RAGAGEPs 

such as API RP 571, Damage 

Mechanisms Affecting Fixed 

Equipment in the Refining 

Industry. Washington L&I did 

not cite Tesoro for this issue. 

In the UK, the Health 

and Safety Executive 

(HSE) has worked with 

industry to develop 

guidance on DMHRs in 

the UK offshore 

petrochemical industry. 

The implementation of 

best practice standards 

referenced by a duty 

holder’s process safety 

report may be 

enforced by the 

regulator to achieve 

ALARP. 

 

193 According to the HSE, essential considerations for determining whether a duty holder has reduced risks to 

ALARP include “the adoption of inherently safer designs...”. HSE. The Safety Report Assessment Manual, 

Sections 8 to 15. p 30. http://www.hse.gov.uk/comah/sram/s8-15.pdf (accessed October 30, 2013). The HSE 

also notes that the guidance to Control of Major Accidents Hazards (COMAH) Regulation 4 (General Duty) 

“describes the application of all measures necessary to reduce risk of a major accident to ALARP based on a 

hierarchical approach (inherent safety, prevention, control, mitigation).” Ibid at 8. 
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Process Safety 

Concept Causal Finding Washington and Federal PSM Regulation and Enforcement 

Goal-Setting 

Regulatory Approach 

PHA 

PHAs identified 

HTHA as a hazard 

for the B and E heat 

exchangers, but 

ineffective 

safeguards failed to 

control the hazard. 

L&I did not 

effectively review 

the PHAs before the 

incident. 

WAC does not require 

submission of the PHA to L&I 

to be reviewed for sufficiency 

and acceptance. L&I does not 

have a sufficient number of 

technically qualified PSM 

personnel to perform effective 

reviews of PHAs. 

Under the more robust 

goal-setting regulatory 

approach, the PHA is 

part of the report 

submitted to the 

regulator for 

acceptance. The duty 

holder is required to 

drive risk to ALARP. 

Effective goal-setting 

regulatory systems 

employ sufficient 

numbers of technically 

competent personnel to 

assess, verify, and 

intervene as necessary. 

PHA 

In the 2006 NHT 

unit PHA, Tesoro 

discontinued a 

review of their 

corrosion control and 

mechanical integrity 

programs in part 

because they were 

“not a legal 

requirement.” 

Tesoro conducted the 

optional review 

ineffectively and 

then ended it when 

they determined it 

was not strictly 

required. 

There is no requirement in the 

PSM regulation for a 

performance based DMHR. 

By shifting the 

responsibility for risk 

management to the 

duty holder, the goalsetting approach would 

require continual risk 

reduction and 

performance of an 

effective DMHR. This 

review is not just an 

activity but must meet 

the goal of preventing 

equipment failures. 
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Process Safety 

Concept Causal Finding Washington and Federal PSM Regulation and Enforcement 

Goal-Setting 

Regulatory Approach 

Incident 

Investigation 

There was a history 

of leaks and fires on 

the NHT heat 

exchangers during 

startup, as identified 

in a Tesoro 

investigation report. 

Tesoro attempted to 

address the 

problems, but the 

hazard was never 

controlled. 

Washington PSM regulations 

require incident investigation 

and preparation of a report, but 

do not require recommendations 

or control of hazards identified 

in the investigation. Although 

the regulations do not require 

recommendations to be 

developed, if recommendations 

are made the regulation requires 

them to be resolved. 

Investigation of 

incidents is required to 

demonstrate legal 

compliance with 

framework legislation. 

The ALARP 

requirement would 

require remedial action 

including crosscompany learning from 

incident investigations. 

The HSE can require 

duty holder compliance 

with investigation 

report 

recommendations. 

Nonroutine 

Work 

Tesoro failed to 

perform an 

evaluation of the 

higher hazards of the 

nonroutine work of 

starting up a bank of 

heat exchangers. 

Tesoro also did not 

define or control the 

number of workers 

required to perform 

the startup. 

Although the WAC PSM 

regulation contains guidance on 

ways to control hazards when 

performing nonroutine work, 

compliance is not mandatory. 

The WAC regulations do not 

require either a hazard 

evaluation of nonroutine work 

or limitations on essential 

personnel during higher-hazard 

activities. 

The goal-setting 

regulatory approach 

would require 

incorporation of goodpractice guidance to 

achieve ALARP, such 

as the CCPS Risk 

Based Process Safety

guidelines that address 

nonroutine work. 
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Process Safety 

Concept Causal Finding Washington and Federal PSM Regulation and Enforcement 

Goal-Setting 

Regulatory Approach 

Mechanical 

Integrity 

API RP 941 has no 

minimum 

requirements to 

control, identify, or 

prevent the 

occurrence of HTHA 

in process 

equipment. 

The mechanical integrity 

element of PSM requires that 

employers follow RAGAGEPs 

for inspection and testing 

procedures. However, API RP 

941 has no minimum 

requirements. Post-incident, 

L&I cited Tesoro for insufficient 

testing and inspection 

procedures for the heat 

exchangers but did not 

specifically reference API RP 

941 or HTHA. 

In a goal-setting 

regulatory system, the 

regulator can reject the 

use of weak and 

inadequate standards 

referenced in a process 

safety report (by 

rejecting the report) 

and can require more 

rigorous performance 

to achieve ALARP. 

Inherently 

Safer Design 

The B and E heat 

exchangers were 

constructed of 

carbon steel – the 

most HTHAsusceptible material 

of construction used 

by industry. API RP 

571 identifies 

materials that are not 

susceptible to 

HTHA. 

Neither Washington nor federal 

OSHA requires the use or 

implementation of inherently 

safer design. 

The goal-setting 

regulatory approach 

requires the 

implementation of 

inherently safer 

systems analysis.194

 

194 According to the HSE, essential considerations for determining whether a duty holder has reduced risks to 

ALARP include “the adoption of inherently safer designs...”. HSE. The Safety Report Assessment Manual, 

Sections 8 to 15. p 30. http://www.hse.gov.uk/comah/sram/s8-15.pdf (accessed October 30, 2013). The HSE 

also notes that the guidance to COMAH Regulation 4 (General Duty) “describes the application of all measures 

necessary to reduce risk of a major accident to ALARP based on a hierarchical approach (inherent safety, 

prevention, control, mitigation).” Ibid at 8. 
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Process Safety 

Concept Causal Finding Washington and Federal PSM Regulation and Enforcement 

Goal-Setting 

Regulatory Approach 

Process Safety 

Indicators 

For more than a 

decade during startup 

following cleaning, 

the NHT heat 

exchangers would 

frequently leak from 

flanges, occasionally 

resulting in fires that 

created hazardous 

conditions for 

workers. 

Federally and in the state of 

Washington, neither the PSM 

nor RMP regulations require 

companies to utilize or report 

process safety indicators. 

Process safety 

indicators that drive 

performance are a key 

feature of a goal-setting 

regulatory approach. 

Publicly reported 

indicators can reveal 

critical safety areas that 

must be targeted for 

improvement to 

prevent accidents. 

Figure 35. Gaps Within the Washington and Federal PSM Regulations. Causal findings highlight the 

gaps within the Washington and federal PSM regulations and how the process safety concept relating 

to each finding is more effectively managed in a more robust goal-setting regulatory approach. 

7.3 OSHA National Emphasis Program 

7.3.1 Federal National Emphasis Program 

In a 1992 compliance directive,195 OSHA stated that the primary enforcement model for the PSM 

standard would be planned, comprehensive, and resource-intensive Program Quality Verification (PQV) 

inspections.196 These inspections consisted of the following three parts: 

1. determining whether the elements of a PSM program are in place 

2. evaluating whether the programs comply with the requirements of the standard, and 

3. verifying compliance with the standard through interviews, data sampling, and field observations. 

The CSB noted in its BP Texas City Final Investigation Report that for the 10-year period before the 

Texas City incident, federal OSHA conducted no planned PQV inspections in petroleum refineries. As a 

result, the CSB recommended in its report that OSHA strengthen the planned enforcement of the OSHA 

PSM standard by developing more highly trained and experienced inspectors to conduct more 

comprehensive inspections similar to those under the OSHA PQV program, at facilities posing the 

greatest risk of a catastrophic accident. 

 

195 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. 

196 OSHA Instruction CPL 02-02-045 (1994). 
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Spurred in part by recommendations in the CSB BP Texas City Final Investigation Report, OSHA 

adopted the Petroleum Refinery Process Safety Management NEP on June 7, 2007.197 The NEP was a 

federal program that established guidelines for inspecting petroleum refineries to ensure compliance with 

the PSM standard. The NEP was designed to address the prevention and minimization of the 

consequences of catastrophic releases of toxic, reactive, flammable, or explosive chemicals in the refining 

industry.198 In adopting the NEP, OSHA noted that no other industry sector in the country had 

experienced as many fatal or catastrophic incidents related to highly hazardous chemicals.199

Unlike the PQV approach to inspections, which “employs a broad, open-ended inspection strategy and 

uses a more global approach to identify compliance deficiencies...,” the NEP “provide[d] CSHOs 

[Compliance Safety and Health Officers] with a tool to evaluate for compliance with the standard.” 200 

The tool is meant to identify “a particular set of requirements from the PSM standard from which CSHOs 

are to review documents, interview employees, and verify implementation for specific processes, 

equipment, and procedures.”201 According to CPL 03-00-004, the NEP inspections were required to be 

conducted by a team consisting of at least one Team Leader and one Level 1 Team Member.202,203 

Although the CSB called for an ongoing comprehensive inspection program, inspections being conducted 

pursuant to the NEP ended in 2011 in part because these inspections were very time consuming and 

resource intensive. OSHA has publicly stated204 that NEP inspection hours were roughly 40 times greater 

than average OSHA inspection hours. 

7.3.2 Washington State National Emphasis Program 

OSHA State Plan states such as Washington were strongly encouraged but not required to adopt the NEP. 

However, on February 8, 2008, DOSH formally adopted the NEP through DOSH Directive 2.64205 for the 

 

197 Originally Directive Number CPL 03-00-004, Petroleum Refinery Process Safety Management National 

Emphasis Program. 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. 

198 https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_id=3589&p_table=DIRECTIVES, Accessed 

October 30, 2013. 

199 OSHA Directive number CPL 03-00-004, Section VIII, Background 

200 CPL 03-00-004, Section X(D)(1). 2007. 

https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_id=3589&p_table=DIRECTIVES (accessed 

September 24, 2013). 201 Ibid 202 CPL 03-00-004, Section X(C)(1). 2007. 

https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_id=3589&p_table=DIRECTIVES (accessed 

September 24, 2013). 203 A Level 1 Team Member is considered to be Trained OSHA personnel with experience in the chemical 

processing or refining industries. CPL 03-00-004, Section X(C)(2). 

204 See Barab, Jordan. OSHA’s Refinery & Chemical National Emphasis Programs. Power Point presentation made 

at CSB Public Hearing on Process Safety Indicators; July 20, 2012. 

http://www.csb.gov/UserFiles/file/Barab%20%28OSHA%29%20PowerPoint.pdf (accessed August 14, 2013). 

Also see Transcript of CSB Public Hearing on Safety Performance Indicators; p 52. 

http://www.csb.gov/assets/1/19/CSB_20Public_20Hearing.pdf (accessed August 14, 2013). 

205 DOSH Directive 2.64. Petroleum Refinery Process Safety Management. February 8, 2008. 

http://www.lni.wa.gov/Safety/Rules/Policies/PDFs/WRD264.pdf (accessed September 24, 2013). 
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five refineries206 in the state of Washington. The stated purpose of DOSH Directive 2.64 was to “reduce 

or eliminate the workplace hazards associated with the catastrophic release of highly hazardous chemicals 

at petroleum refineries.”207 The directive required the DOSH staff to follow the compliance directions in 

OSHA Instruction CPL 03-00-004 when conducting NEP inspections. When CPL03-00-004 referenced 

another CPL, DOSH instead followed any existing equivalent DOSH policy and directives. DOSH also 

used WAC equivalents in place of the OSHA 1910.119 PSM standard. For example, when auditing PSM 

section 1910.119(j) “Mechanical Integrity,” DOSH instead used WAC 296-67-037. 

CPL 03-00-004 provides for a two-step NEP inspection process. The first step is a PSM compliance 

review based on a “static” list of inspection priority items. The second is a PSM compliance review 

based on a “dynamic” list of priority inspection items.208

The DOSH NEP team consisted of six people, including a team lead who had been with L&I since the 

early 1990s. The team lead had more process safety and refinery experience than the other team 

members. None of the team members had an engineering or metallurgy background, and the team as a 

whole had limited experience with PSM and with refinery operations. 

 

 

206 The five petroleum refineries in Washington are BP Cherry Point Refinery; Conoco Phillips Ferndale Refinery; 

Tesoro Anacortes Refinery; Shell Oil Products Refinery; and US Oil and Refining Refinery. 

207 DOSH Directive 2.64. Petroleum Refinery Process Safety Management. February 8, 2008; p 1. 

http://www.lni.wa.gov/Safety/Rules/Policies/PDFs/WRD264.pdf (accessed September 24, 2013). 208 Static questions within the NEP are publicly available. The company can prepare for them. Dynamic questions 

are not available to the company prior to the audit. Reference: OSHA CPL 03-00-004 Section X (D)(3). (June 

7, 2007). See: https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_id=3589&p_table=DIRECTIVES

(accessed September 24, 2013). 
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7.3.3 Tesoro National Emphasis Program Audit 

Following Washington’s adoption of the federal NEP, the DOSH NEP team lead developed a proposed 

refinery inspection plan. To determine the focus for the NEP audit at each facility, the DOSH NEP team 

examined the age of each process in the refinery, hazards surrounding different process units, and past 

events, including near misses. 

On October 7, 2008, the DOSH NEP team initiated a formal NEP audit of the Tesoro CR and NHT units. 

The selection of these units was based primarily on the fact that the NHT unit stood out to the team as 

problematic in terms of previous incidents and near misses. The Tesoro NEP Audit Report noted the 

following: 

Elsewhere, refinery records indicate a relatively higher incidence of 

process safety related events occurring in the Catalytic Reformer and 

Naphtha Hydrotreater (CR/NHT) process areas when compared to other 

units, with the possible exception of the Catalytic Cracking unit 

equipment when viewed in its entirety. 

From 2002 to 2007, the CR/NHT experienced a total of 117 records 

related to process safety. Of those, 36% were attributed to equipment 

failures, 33% human error, and the remaining 31% were attributed to 

failure of a process control or safeguard. 

Previous inspection activities at the refinery have included at least five 

safety and health compliance inspections since 2003. These have 

included scheduled inspections, complaints, and accident and near miss 

investigations. 

The NEP team spent several weeks at the Tesoro refinery during the NEP audit. The refinery NEP 

inspection process was a two-step process. The first step consisted of a compliance review based on a 

static list of inspection priority items. The CSHO was required to follow the list verbatim. The list of 

questions related to various aspects of process safety, such as equipment, engineering and administrative 

controls, and safe work practices. The answers to these questions were the basis for determining 

compliance with various PSM requirements. The second step focused on a dynamic list of inspection 

priority items that were directed towards the specific selected process unit.209

7.3.3.1 Tesoro NEP Results Associated with the E Heat Exchanger 

The Tesoro Anacortes NEP audit is noteworthy, as it was the only audit conducted under the federal 

OSHA NEP program that focused on a unit that subsequently experienced a catastrophic accident that the 

CSB investigated. The heat exchanger that failed, the E heat exchanger, was a fundamental component of 

the Tesoro NEP audit. Within the scope of the NEP nine pressure vessels were selected at random; the E 

 

209 OSHA Directive CPL 03-00-004, Section X, (D) (3). 
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heat exchanger was one of the vessels reviewed. The NEP states, “Inspection records for all nine vessels 

were examined and found to be in order. No citable deficiencies found.” 

Like the CSB, the DOSH NEP identified the issue of PHA assumptions for the PHA. Reflecting the 

weakness in the current PSM requirements for PHAs, DOSH mentioned the problematic nature of using 

the assumptions but did not cite Tesoro in this area. The NEP states the following: 

Problems were identified in the area of procedures, inspection, and 

testing of devices that indicate assumptions made by PHA teams inhibits 

identification of problematic areas. 

Given the methodology used and expertise available, the mechanical integrity issues related to the failure 

of the E heat exchanger were not detected during the NEP audit. To prevent the April 2010 incident, the 

NEP audit needed to identify the susceptibility of the E heat exchanger to HTHA and to recognize that 

Tesoro had incorrectly concluded that it was not susceptible. The topics investigated during the NEP 

audit were contained in prescriptive questions for the individual unit, which resulted in a shallow 

technical review. For example, significant emphasis was placed on verifying the existence of basic 

protocols for conducting thickness monitoring. On the basis of the CSB review of the question sets 

applied for the Tesoro refinery, there was no mention of HTHA, corrosion studies, or failure mechanisms 

and no references to the API RP 571 damage mechanisms. The NEP team lead confirmed that little 

emphasis was placed on possible damage mechanisms that could be present, including HTHA. The NEP 

found the following: 

In general, the refinery maintains corrosion control documentation that 

attempts to identify corrosivity data and potential failure mechanisms. 

The inspection procedure I-08.01 addresses metallurgy and corrosion in 

the refinery. 

The refinery has a procedure for conducting corrosion awareness training 

of staff and managing corrosion control procedures. 

Unless a member of the NEP audit team had a personal interest in metallurgical damage mechanisms, or 

had experience to prompt investigation into the area of metallurgy, reliance on these static and dynamic 

lists would not lead to the conclusion that the B and E heat exchangers were susceptible to HTHA. 

The NEP inspection was formally closed on March 12, 2009; at that time, a summary of the audit findings 

was presented to Tesoro. The NEP inspection team identified 17 process safety code violations under 

Chapter 296-67 of the WAC,210 but only two of these addressed mechanical integrity,211 and neither 

related to the NHT heat exchangers or to identification or control of HTHA. 

 

210 See http://apps.leg.wa.gov/wac/default.aspx?cite=296-67 (accessed September 25, 2013). 

211 Mechanical integrity violations of WAC 296-67-037 were issued for the following: 

a. No written procedures for controls and emergency shutdowns; 13 instances were documented in which the 

employer did not have written procedures for the inspection and testing of emergency equipment; and 
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On October 23, 2009, six months before the incident, a settlement agreement was reached between L&I 

and Tesoro whereby Tesoro agreed to perform a PSM compliance audit with an industry recognized PSM 

consultant within 60 days of the agreement date and to commit to a completed compliance audit within 

six months of the consultant’s contract initiation date. In exchange for the audit, L&I agreed to reduce the 

citations from seventeen (17) to three (3) citations. Subsequently, the total penalty was reduced from 

$85,700 to $15,450.212 The same consulting firm that Tesoro hired for its most recent OSHA-mandated 

compliance audit also conducted the audit under the settlement agreement. However, the compliance 

audit conducted by the consulting firm was not a comprehensive audit of the entire refinery PSM 

program. It was limited only to those areas covered by the fourteen eliminated citations from settlement 

agreement between L&I and Tesoro. 

7.4 Risk Reduction and Continuous Improvement 

The CSB Chevron Regulatory Report provides a detailed discussion of the advantages of adding robust 

goal-setting regulatory attributes to make the PSM standard more effective in preventing major accidents. 

Many countries throughout the world implement a goal-setting regulatory approach, which provides the 

regulator with the tools needed to drive continuous improvement among facilities and to ensure that duty 

holders are identifying and controlling hazards and reducing risks to ALARP. The existing federal and 

state of Washington PSM standards, on the other hand, are more reactive in nature and contain activitybased requirements that do not focus on specific risk reduction; rather, the mere completion of the 

activities satisfies the requirements. 

Highlighting the reactive nature of the Washington PSM standard, following the Tesoro incident, DOSH 

initially cited Tesoro for 39 willful violations and five serious violations related to the incident, with a 

total proposed fine of $2.39 million.213 Four of the citations were issued to Tesoro for failing to follow 

recognized and generally accepted good engineering practice (RAGAGEP) for mechanical integrity under 

WAC 296-67-(4)(b) “such as those published by the American Petroleum Institute.”214 No RAGAGEPs 

were specified in the citations. RAGAGEPs are technologically focused, with no emphasis on 

organizational issues, human factors, or culture-based measures. OSHA developed the mechanical 

integrity RAGAGEP requirement to “make sure that process equipment is inspected and tested properly, 

and that the inspections and tests are performed in accordance with appropriate codes and standards.”215

However, as in this case, OSHA mainly enforces RAGAGEP reactively. Here, DOSH used unspecified 

 

b. Documenting inspections and tests – 24 instances identified in which the employer did not document testing of 

emergency field devices or where the record did not identify what testing procedure was used. 

212 See http://www.osha.gov/pls/imis/establishment.inspection_detail?id=312459290; (accessed on June 19, 2013). 

213 Tesoro has appealed these citations. 

214 State of Washington Department of Labor and Industries, Division of Occupational Safety and Health. Tesoro 

Citation – Notice Inspection. October 1, 2010; p 9. http://www.lni.wa.gov/Main/Docs/TesoroCitationNoticeInspectionNo314251315.pdf (accessed September 25, 2013). 215 OSHA. Preamble to 29 CFR Part 1910, Process Safety Management of Highly Hazardous Chemicals, Section 3, 

Title III. Summary and Explanation of the Final Rule, 1992. Available at 

http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=PREAMBLES&p_id=1041 (accessed June 

6, 2013). 
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RAGAGEPs to issue a citation to Tesoro post-incident, rather than working to drive continuous 

improvement and risk reduction through preventative NEP inspections. Although many OSHA inspectors 

have cited to RAGAGEPs following NEP refinery audits, DOSH did not cite any RAGAGEPs for 

mechanical integrity following its NEP audit of the Tesoro refinery in 2008. 

Similar to OSHAct Section 5(a)(1), also known as the General Duty Clause, the WAC requires employers 

to provide employees a workplace “free from recognized hazards216 that are causing, or are likely to 

cause, serious injury or death.”217 Similar to federal OSHA, DOSH may use this provision following an 

incident to cite a company for hazards not addressed by the regulations, but these citations are often 

difficult to prove especially if the regulator lacks industry-specific expertise, and are resource intensive to 

sustain. DOSH did not cite Tesoro for General Duty Clause violations following the April 2010 incident. 

Washington’s Safety Standards for Process Safety Management of Highly Hazardous Chemicals were 

established to “prevent[] or minimiz[e][] the consequences of catastrophic releases of toxic, reactive, 

flammable, or explosive chemicals.”218 Washington’s PSM standard contains many activity-based 

elements that are almost identical to those in the federal PSM standard. For example, an employer must 

perform a PHA “appropriate to the complexity of the process and shall identify, evaluate, and control the 

hazards involved in the process.”219 This language does not support the principle of ALARP and makes 

no mention of reduction of risk or continuous improvement. As a result, PHAs may satisfy Washington’s 

PSM requirement by merely listing safeguards, and there is no requirement to evaluate or document the 

effectiveness of those safeguards, or to show that the safeguards reduce risks. 

Following the April 2010 incident DOSH issued two citations to Tesoro for its 2006 PHA revalidation.220

One of these citations was dismissed and the second citation addressed Tesoro’s failure to establish and 

implement written procedures to manage the change made by discontinuing the PHA revalidation system 

that included mechanical integrity and corrosion control review in 2006. 221 However, as discussed in 

Section 5.3, PHAs conducted on the NHT unit cited non-specific, judgment-based qualitative safeguards 

that in light of the April 2010 incident were not effective. If the Washington PSM standard had required 

an evaluation and documentation of safeguard effectiveness, Shell Oil and Tesoro would have been 

obligated to conduct this analysis, and DOSH inspectors could have relied on the regulation for support 

during inspections. 

 

216 According to L&I, “A hazard is recognized if it is commonly known in the employer’s industry, or if there is 

evidence that the employer knew or should have known of the existence of the hazard, or if it can be established 

that any reasonable person would have recognized the hazard.” 296 WAC 800-11005 (2012). 

217 296 WAC 800-11005 (2012). http://www.lni.wa.gov/wisha/rules/corerules/PDFs/296-800-110.pdf (accessed 

September 26, 2013). 

218 26 WAC 67-001(1) (1992). 

219 26 WAC 67-017(1) (1992). 

220 Under appeal, citation item 1-37 was dismissed. 

221 In the 2001 PHA, Tesoro included a review of the corrosion control program and a specific mechanical integrity 

checklist associated with the corrosion program. In 2006, Tesoro excluded these items because they were being 

used in the DMHR and it was “not a legal requirement” for PHAs. 
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Tesoro conducted a PHA for the NHT unit between February 1, 2010, and May 21, 2010. Despite the 

fact that the PHA was being conducted at the time of the April 2010 incident, the PHA failed to identify 

significant hazards associated with the immediate 

causes of the incident, including damage 

mechanisms such as HTHA. The PHA also took 

credit for inspection safeguards that did not exist. 

The PHA failed to address HTHA damage in the B 

or E heat exchangers on the shell-side and the PHA 

used inspection as a safeguard to mitigate HTHA 

consequences on the tube side. As discussed in 

Section 5.3.3, no inspection for HTHA was ever 

conducted on the B or E heat exchangers. No 

evaluation was documented to demonstrate the 

effectiveness of the inspection safeguards claimed 

by the PHA team; that is a manual activity and 

thus low in the hierarchy of controls. The PHA 

analysis concluded that the worst consequence 

resulting from a loss of primary containment 

(catastrophic failure of the E heat exchanger) was a 

disabling injury and substantially understated the 

actual consequence of seven worker fatalities. The 

combination of understating the consequence and 

overstating the safeguards resulted in 

underestimating the risk of a catastrophic failure of the E heat exchanger, despite the fact that the incident 

took place 50 days before completion of the PHA. 

In a robust goal-setting regulatory approach, a risk assessment such as this would be part of the process 

safety report submitted to the regulator to demonstrate and ensure that the hazards are adequately 

identified and that risks are being reduced to ALARP. If the hazards are not sufficiently identified and 

controlled, the regulator may reject the process safety report and require improvements and further risk 

reduction. In this case, because mere completion of the PHA satisfied the PSM requirements, DOSH did 

not analyze or address Tesoro’s failure to adequately identify and control hazards. In addition, DOSH did 

not issue any post-incident citations to Tesoro regarding its 2010 NHT unit PHA. 

The existing regulatory approaches in the US and Washington, such as the PSM and RMP programs, do 

not require companies to reduce risks to ALARP. While the Clean Air Act (CAA) directed the EPA to 

promulgate the RMP regulations “to provide, to the greatest extent practicable, for the prevention and 

detection of accidental releases of regulated substances,” 222 there is no RMP ALARP requirement. Under 

both the PSM and RMP regulations, an employer must “control” hazards when conducting a PHA of a 

covered process. However, there is no requirement to address the effectiveness of the controls or the 

 

222 42 U.S.C. §7412(r)(7)(B)(i) (1990). 
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hierarchy of controls. Thus, a PHA that meets the regulatory requirements might still inadequately 

identify or mitigate major hazard risks. In addition, there is no requirement to submit PHAs to the 

regulator, and the regulator is not responsible for assessing the quality of the PHA or the proposed 

safeguards. 

The Tesoro PHA goals encourage the PHA team to identify high-consequence, low-frequency hazards 

that are possible but might not be realized. The company’s PHA goal supports the principle of ALARP. 

The Tesoro PHA policy states the following: 

In the end, the reduction of RISK is the goal. 

Any improvement in a layer of protection that is permanent and 

inseparable, and not easily weakened or removed from the system, is 

considered to be a process safety improvement in an inherently safer 

direction. 

Can the Likelihood be reduced? 

If the Hazard cannot be removed, and Consequences cannot be reduced, 

then what can be done to reduce the likelihood of the event(s) occurring? 

None of the Tesoro PHA teams ever considered applying the principles of inherently safer design by 

upgrading the heat exchangers before the incident; yet, following the April 2, 2010, incident, more 

HTHA-resistant materials were used for the replacement equipment. In conducting its PHA of the NHT 

unit, which was required under the state of Washington PSM standard,223 Tesoro did not address 

inherently safer design or implement effective safeguards to prevent HTHA. However, there is no 

Washington (or federal) PSM requirement to consider inherently safer design or to evaluate the 

effectiveness of safeguards. Thus, Tesoro was never cited for failure to evaluate or implement inherently 

safer design or for the PHA claim of HTHA inspection as a safeguard despite the company never 

inspecting the E heat exchanger for possible presence of HTHA. 

Under a robust goal-setting regulatory approach, Tesoro would be required to apply the hierarchy of 

controls and inherently safer design to achieve ALARP. As detailed in the CSB Chevron Regulatory 

Report, a company must demonstrate how inherently safer design concepts were applied in the design 

decisions that were taken. This principle applies to all life cycle stages of a facility, and includes 

materials selection and corrosion management in the design. 224

 

223 Under WAC 296-67-001 Process safety management of highly hazardous chemicals. See: 

http://www.lni.wa.gov/wisha/rules/hazardouschemicals/default.htm#WAC296-67-001 (accessed September 28, 

2013). 

224 HSE. Assessment Principles for Offshore Safety Cases (APOSC); March 2006; p 7. 

http://www.hse.gov.uk/offshore/aposc190306.pdf (accessed August 6, 2013). 
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7.5 Workforce Participation 

As the CSB noted in its Chevron Interim and draft Chevron Regulatory Reports, workforce participation 

is a key element of process safety and effective major accident prevention. The CCPS lists workforce 

involvement as one of 20 essential management components necessary to reduce process safety risks and 

prevent major chemical accidents.225 In one of its publications, the CCPS states that workforce 

participation leads to worker empowerment, management responsiveness, and process safety performance 

improvement.226 The OSHA PSM standard provides for participation by workers and their 

representatives. It requires employers to consult with employees and their representatives on the 

performance and development of PHAs and on the development of the 13 remaining PSM elements, and 

to develop a written plan of action regarding the implementation of the employee participation required 

under this section.227 However, other regions such as the UK go further to ensure effective worker 

participation by specifying the election of safety representatives by the workers to serve many functions 

related to health and safety, including investigating complaints and accidents and conducting 

inspections.228 UK regulations also require employers to establish a safety committee when one is 

requested by at least two health and safety representatives.229

 Like the federal PSM standard, the WAC provides for workforce participation in a company’s PSM 

program and has implemented language identical to that contained in the federal PSM standard.230 

However, throughout its investigation of the Tesoro incident, the CSB has seen that the Tesoro refinery 

workforce and its representative, the United 

Steelworkers Union (USW), expressed concerns 

regarding the NHT unit that were not adequately 

addressed by Tesoro managers in the lead-up to the 

incident. During a 2006 PHA revalidation on the NHT 

unit at the Tesoro Anacortes Refinery, workers noted 31 

near misses in the NHT unit in the last 5 years because 

of many possible factors, including too many outside 

tasks and continual rotation of the field and control 

room operators. The PHA team requested a review of 

experience and training for NHT operators to address 

these workload concerns. A manager at the refinery 

closed the action item with one simple statement: “Experience levels of teams, where and when 

individuals are trained on the NHT are managed by team supervisor.” The action item was closed without 

resolution of the concerns expressed by the Tesoro workers on the PHA team. 

 

225 CCPS. Guidelines for Risk Based Process Safety; March 2007; p liv. 226 Ibid at 125. 227 29 CFR §1910.119(c) (2012). 228 See: the Safety Representatives and Safety Committees Regulations, 1977, and the Health and Safety 

(Consultation with Employees) Regulations 1996. 

229 Ibid. 

230 See: WAC §296-67-009 (1992). http://apps.leg.wa.gov/wac/default.aspx?cite=296-67-009 (accessed September 

26, 2013). 
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7.6 Funding and Regulator Competency 

The CSB stated in both its BP Texas City Final Investigation Report (issued in March 2007) and its draft 

Chevron Regulatory Report (Appendix F) the importance of having a well-resourced, competent regulator 

consisting of individuals with the necessary training, education, and experience to conduct comprehensive 

and robust inspections of facilities with the goal of preventing catastrophic accidents. As noted above, 

currently DOSH employs only four Process Safety Specialists to cover approximately 270 PSM facilities 

within the state of Washington, and only one of those has significant refinery experience. None have 

metallurgical experience and only one has an engineering background. Despite the fact that DOSH 

performed a detailed NEP inspection at the Tesoro refinery, the team did not have the technical expertise 

to inspect for and identify possible damage mechanisms present in the NHT unit such as HTHA. 

Individuals within L&I have expressed to the CSB that there is currently no funding in the state of 

Washington to form a multi-disciplinary process safety group to conduct more thorough facility 

inspections. This was also the case in California at the time of the Chevron incident in August 2012. 

Despite the fact that Cal/OSHA had formed a dedicated PSM unit, it did not have the staffing, funding, or 

experience to oversee the state’s 15 petroleum refineries. Following the Chevron incident, the California 

State Legislature approved a 2013-2014 state budget bill (AP 110) that allows the California Department 

of Industrial Relations to charge state petroleum refineries a “fee” by March 31, 2014, to help pay for at 

least 15 new positions in Cal/OSHA’s Process Safety Unit, which enforces the California PSM standard 

throughout the state.231

Adding more robust goal-setting regulatory attributes to the existing PSM regulation will require a full 

commitment and extensive effort by the Washington legislature, regulators, and Washington petroleum 

refineries. The CSB believes that this effort is necessary to ensure that Washington, like other regions 

around the world, is effectively managing process safety and risk, and in the process, preventing major 

accidents such as the April 2, 2010, Tesoro incident. 

7.7 Similar Deficiencies in the Anacortes and Richmond Refinery Incidents 

The CSB identified a number of similar causal findings for both the April 2010 Tesoro Anacortes 

Refinery incident and the August 2012 Chevron Richmond Refinery incident. These findings included 

ineffective PHAs, lack of effective safeguards to prevent damage mechanism hazards, no requirements to 

use the hierarchy of controls or to implement inherently safer design to the greatest extent possible, weak 

and permissive industry standards that lack minimum requirements to control damage mechanism 

hazards, and regulators that lack sufficiently qualified personnel to provide effective oversight. 

 

231 See: http://www.caltax.org/homepage/062113_Legislature_Approves.html (accessed July 9, 2013). 
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7.7.1 Reliance on Inspection Instead of Inherently Safer Design in Mechanical 

Integrity Programs at Tesoro and Chevron Refineries 

The August 6, 2012, Richmond, California, Chevron refinery incident occurred when a severely thinned, 

low-silicon carbon steel pipe component ruptured, releasing hot hydrocarbons that autoignited and 

endangered the lives of 19 employees.232 Like HTHA, low-silicon areas that result in rapid corrosion are 

very difficult to identify by inspection. Identification of this hazard requires the inspection of every 

single component in a carbon steel piping circuit to identify the quickly corroding pieces. Despite this 

difficulty and despite Chevron’s notable expertise on sulfidation corrosion,233 the refinery still operated 

the high-risk piping circuit with a carbon steel material of construction, the steel that is most susceptible 

to rapid rates of sulfidation corrosion in low-silicon components. The refinery then relied on its 

inspection program to identify any quickly corroding pieces, a very low-ranking method on the hierarchy 

of controls, to prevent process safety incidents. Ultimately, the inspection program failed to detect the 

low-silicon component in the piping circuit. Had Chevron designed the piping circuit by using an 

inherently safer material of construction, such as high-chromium steel, the corrosion rates in the piping 

circuit would have been much slower and much more uniform, and the incident would not have occurred. 

The Anacortes refinery also in effect relied on its mechanical integrity program to identify damage 

mechanisms such as HTHA in its NHT heat exchangers instead of incorporating design elements that 

would eliminate the risk of HTHA. Although Tesoro was not actively looking for HTHA in the B and E 

heat exchangers, this is the only mechanical integrity component that could identify the damage in the 

heat exchangers. As described previously, inspection for HTHA is very difficult and not sufficiently 

reliable. The use of inherently safer materials of construction, such as high-chromium steels, significantly 

lowers the risk of HTHA in this type of service. 

Both Tesoro and Chevron had the expertise and capability needed to design the damage mechanisms out 

of the equipment by incorporating inherently safer design. However, both companies continued to rely on 

mechanical integrity programs, such as inspection, to identify the damage after it had already occurred in 

the system. Although inspection programs are needed they are very low on the hierarchy of controls, and 

in both cases the inspection strategies failed to prevent a major process safety incident. Since the 

incidents, both Chevron and Tesoro redesigned the equipment that failed, incorporating inherently safer 

design practices. Now, sulfidation corrosion in Chevron’s new piping circuit will be significantly reduced 

and without risk of variable corrosion rates. Tesoro installed new NHT heat exchangers, using materials 

of construction that are highly resistant to HTHA. 

 

232 The CSB plans to release three separate reports on the Chevron incident. All draft and final reports can be found 

at http://www.csb.gov/chevron-refinery-fire/ (accessed January 6, 2014). 

233 Chevron employees were leaders in the development of the industry standard on sulfidation corrosion, API RP 

939-C. 
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7.7.2 Ineffective PHAs at Tesoro and Chevron 

PHAs are a crucial opportunity to identify hazards in a refinery process unit. However, neither Tesoro 

nor Chevron PHAs identified the significant hazards that led to the April 2010 and August 2012 incidents, 

respectively. The CSB found similar deficiencies in the PHA of both companies. Instead of performing a 

rigorous analysis of damage mechanisms present in the refinery during the PHA process, both companies 

simply cited non-specific, judgment-based qualitative safeguards to reduce the risk of damage 

mechanisms. The effectiveness of these safeguards was neither evaluated nor documented; instead, the 

PHAs merely listed general safeguards. If the adequacy of these safeguards to control and prevent 

damage mechanisms had been verified, recommendations could have been made to improve safeguards 

intended to protect against the failure of the highly susceptible carbon steel equipment. 

7.7.3 Applicable API Standards Lack Minimum Requirements to Control Hazards 

The Anacortes and Richmond refineries relied on API standards to assist in the selection of materials of 

construction for both Tesoro NHT heat exchangers and the Chevron piping circuit: specifically, API RP 

941, Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and 

Petrochemical Plants, and API RP 939-C, Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion 

Failures in Oil Refineries. Both documents provide guidance on how to avoid HTHA and sulfidation 

corrosion failures, respectively, but neither document imposes minimum requirements on the user to 

adequately control hazards. In fact, the CSB found in its Chevron investigation that API RP 939-C was 

specifically written to not require any action by the user (emphasis added). Thus, API’s current 

consensus, standard creating process is not effective in ensuring that companies perform essential safety 

practices that can prevent fatal process safety incidents. 

7.7.4 Weak Regulations and Ineffective Regulators 

The CSB found significant gaps in the regulations and the technical abilities of the regulators in both 

Washington and California. Refineries in both states are required to comply with requirements in the 

state OSHA PSM and EPA RMP regulations. However, neither state’s regulations were successful in 

preventing the April 2, 2010, and August 6, 2012, major process safety incidents. 

Under the existing regulatory systems in both Washington and California, there is no requirement to 

conduct DMHRs or to reduce risk to ALARP. Both Tesoro and Chevron were required to “control” 

hazards, but there was no requirement to evaluate the effectiveness of the controls or to ensure the use of 

the hierarchy of controls. In addition, there is no requirement to submit PHAs to the regulator, and the 

regulator is not responsible for assessing the quality of the PHA or the proposed safeguards. 

Furthermore, neither Washington nor California requires the use of inherently safer design to the greatest 

extent practicable. A more robust goal-setting regulatory approach in both states would help to ensure 

that all of the refineries in these states rigorously apply process safety concepts that focus more 

effectively on prevention. The PSM regulations in the state of Washington should be augmented with 

more robust goal-setting attributes including requirements to implement inherently safer designs and the 

hierarchy of controls to prevent major process safety incidents. 
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Both states also have significant weaknesses in their PSM staffing resources. Washington L&I (the 

Washington PSM regulator) and Cal/OSHA (the California PSM regulator) lack sufficient technically 

experienced and qualified staff members to verify that PSM requirements are being implemented 

adequately. Cal/OSHA has only seven inspectors, and only one with a technical background, for 1,700 

PSM-covered facilities including 14 petroleum refineries, and Washington L&I has only four inspectors, 

and only one with a technical background, for more than 270 PSM-covered facilities including five 

petroleum refineries. 

As described in the CSB Chevron Regulatory Report and in Section 7.0 of this report, it is essential that 

regulators of high-hazard facilities are independent, well funded, well staffed, and technically qualified. 

These regulators must be able to communicate effectively with refinery personnel and to monitor the 

adequacy of refinery process safety practices. 

7.8 Environmental Protection Agency and Chemical Accident Release Programs 

The CSB determined that a key causal factor of the 

April 2010 incident was Tesoro’s failure to 

implement more effective safeguards to prevent the 

heat exchanger failure, such as the use of inherently 

safer materials that are resistant to HTHA. In a 

number of recent CSB investigations, such as the 

Chevron Richmond Refinery incident, the CSB 

found that the implementation by the company of the 

hierarchy of controls and inherent safety could have 

helped to prevent the incident. A number of these 

incidents had significant offsite consequences or had 

the potential to do so. The CSB has determined that 

Tesoro policies and relevant API standards do not 

require the application of inherently safer systems 

analysis or use of the hierarchy of controls to more 

effectively prevent chemical accidents. In this 

section of the report the CSB will examine the 

requirements of the use of inherent safety under the 

Clean Air Act and EPA’s Risk Management Program. 

7.8.1 Background 

Under the authority of the Clean Air Act (CAA) section 112(r),234 the EPA adopted the Risk Management 

Program regulations at 40 CFR Part 68, which went into effect in 1999. The CAA provides that the 

 

234 42 U.S.C. §7412(r)(7)(B)(ii) requires the Administrator to promulgate regulations that “shall require the owner or 

operator of stationary sources at which a regulated substance is present in more than a threshold quantity to 

prepare and implement a risk management plan to detect and prevent or minimize accidental releases of such 
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regulations and appropriate guidance developed “provide to the greatest extent practicable, for the 

prevention and detection of accidental releases of regulated substances and for response to such releases 

by the owners or operators of the sources of such releases.”235 The EPA’s Risk Management Program 

requires facilities that contain more than the threshold quantity of any of the 77 listed toxic chemicals or 

63 flammable substances236 to prepare and submit to the regulating agency emergency contact 

information, descriptions of processes and hazardous chemicals onsite, an accident history, and worstcase release scenarios.237 The regulation defines three different Program levels (Program 1, 2, or 3) based 

on a process unit’s potential for impact to the public and the requirements to prevent accidents.238 

Program 3 processes are subject to additional, more stringent requirements to prevent accidents similar to 

those of the OSHA PSM standard. Program 3 facilities must implement elements of a prevention 

program, including: process safety information (PSI), PHA, standard operating procedures (SOPs), 

training, mechanical integrity, compliance audits, incident investigations, MOC, pre-startup reviews, 

employee participation, and hot work permits. These prevention program elements are based primarily on 

the OSHA PSM standard, and much of the language contained in each element is identical to the PSM 

standard. 

Each covered facility is required to submit a risk management plan (RMP) to EPA for all covered 

processes239 and update and resubmit these plans at least once every five years, or whenever a major 

accident occurs or the emergency contact information changes. Completing and submitting the RMP 

satisfies the regulatory requirement; again, the effectiveness of the RMP in risk reduction is not assessed 

by the EPA, rendering this another activity-based requirement for a covered facility. There is no approval 

of the RMP by the EPA, and there is no additional duty on the facility to implement what it says it is 

doing in the RMP, unlike the more robust goal-setting regulatory approach. 

Any facility with one or more covered processes must include in its RMP an executive summary; the 

registration for the facility; the certification statement; a worst-case scenario for each process involving 

flammables or toxics; the five-year accident history for each process; information concerning emergency 

response at the facility; at least one alternative release scenario analysis for each regulated toxic substance 

or flammable; a summary of the prevention program for each Program 2 process; and a summary of the 

prevention program for each Program 3 process.240 

 

substances from the stationary source, and to provide a prompt emergency response to any such releases in order 

to protect human health and the environment.” (1990). 235 42 U.S.C. §7412(r)(7)(B)(i) (1990). 

236 According to 40 CFR §68.10(a), “[a]n owner or operator of a stationary source that has more than a threshold 

quantity of a regulated substance in a process, as determined under §68.115, shall comply with the requirements 

of this part no later than the latest of the following dates...” 

237 See 40 CFR §68.12. General Requirements. 

238 See 40 CFR §68.10. Applicability. 

239 40 CFR §68.150 (1999). 

240 EPA Office of Solid Waste and Emergency Response. General Guidance on Risk Management Programs for 

Chemical Accident Prevention (40 CFR Part 68); March 2009; pp 9-1 and 9-2. See

http://www.epa.gov/osweroe1/docs/chem/Toc_final.pdf (accessed May 14, 2013). 
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The Tesoro Anacortes Refinery is a covered facility under the RMP program, and its CR/NHT unit is 

considered to be a Program 3 process, as it contains more than the threshold quantity of a flammable 

mixture including butane, ethane, hydrogen, methane, and propane.241 The refinery last submitted an 

updated RMP to EPA on March 28, 2011. The RMP contained a five-year accident history that listed the 

April 2, 2010, NHT catastrophic heat exchanger failure as well as a section on worst-case scenarios, 

which stated that the worst-case scenario associated with a release of flammable substances at Tesoro 

would be a vapor cloud explosion involving the full inventory of the largest storage tank containing an 

RMP regulated flammable mixture.242 

7.8.2 Enforcement of Inherent Safety in the United States 

Although industry good practice guidance provides243 that inherently safer technology (IST) is the 

preferable and often the most effective safety precaution in the hierarchy of controls to prevent major 

accidents it is not enforced by the EPA through its RMP program or through its General Duty Clause or 

other provisions of the Clean Air Act. 

7.8.3 The EPA RMP Program 

As discussed in Section 4.1.3, the hierarchy of controls is a well-recognized safety tool to rank the 

effectiveness of techniques to control hazards, with inherent safety being the most effective choice. The 

CCPS defines inherently safer design as the process of identifying and implementing inherent safety in a 

specific context that is permanent and inseparable.244 The CCPS also notes that “inherently safer design 

solutions eliminate or mitigate the hazard by using materials and process conditions that are less 

hazardous.”245 Regulatory systems around the world have recognized the importance of inherent safety; 

for example, the HSE requires major hazard facilities in the UK to implement inherently safer systems 

analysis including at the design stage in order to satisfy the risk reduction requirement of as low as 

reasonably practicable, or ALARP.246

The RMP program regulations under 40 CFR Part 68 do not require the use or implementation of 

inherently safer design or the hierarchy of controls. This is reflected in both the regulatory language, 

 

241 See http://data.rtknet.org/rmp/rmp.php?database=rmp&detail=3&datype=t&facility_id=100000028034 (accessed 

January 23, 2014). 242 Ibid. 

243 CRC Press, Process Plants: A Handbook for Inherently Safer Design Second Edition; Kletz, Trevor and 

Amyotte, Paul; 2010; pp 15-16. 

244 Center for Chemical Process Safety (CCPS). Inherently Safer Chemical Processes – A Life Cycle Approach. 2nd

ed., Section 2.2, 2009. 245 Ibid at Section 5.1.1. 246 According to the HSE, essential considerations for determining whether a duty holder has reduced risks to 

ALARP include “the adoption of inherently safer designs....” HSE. The Safety Report Assessment Manual, 

Sections 8 to 15. p 30. http://www.hse.gov.uk/comah/sram/s8-15.pdf (accessed October 30, 2013). The HSE 

also notes that the guidance to COMAH Regulation 4 (General Duty) “describes the application of all measures 

necessary to reduce risk of a major accident to ALARP based on a hierarchical approach (inherent safety, 

prevention, control, mitigation).” Ibid at 8. 
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which does not mention either concept, as well as citations issued by the EPA to companies following an 

incident. As of January 2014, the EPA had issued no civil enforcement penalties to Tesoro as a result of 

its April 2010 incident that resulted in seven fatalities. The EPA did conduct “post-incident” inspections 

of the Tesoro Anacortes Refinery in January and October of 2011. However, no violations were issued 

related to the implementation of inherently safer systems analysis or the hierarchy of controls. In 

December 2013 the EPA also issued a Finding of Violations relating to the Chevron Richmond Refinery 

incident of August 2012. Again, no violations related to either accident prevention approach. 

The CSB found in both its Chevron and Tesoro investigations that the incidents could have been 

prevented if inherently safer materials of construction had been used. In the years leading up to the 

Chevron incident, Chevron employees repeatedly recommended implementing inherently safer designs 

through the management of change (MOC) process, incident investigations, technical reports, and 

recommendations from employees in the past. However, despite the fact that Chevron’s training 

programs on inherently safer systems stated that “the greatest opportunity to eliminate or minimize 

hazards [is] during the development phase of new projects or major revamps of existing facilities,” the 

CSB did not identify any documented, thorough analysis of these proposed inherently safer solutions. 

Instead, Chevron repeatedly failed to implement proposed inherently safer recommendations to upgrade 

crude unit piping from carbon steel to metallurgy that was less susceptible to sulfidation corrosion. This 

led to extremely thinned piping which ultimately ruptured on August 6, 2012. 

At Tesoro, the CSB found that the carbon steel E heat exchanger ruptured because it was in a highly 

weakened state because of HTHA. As discussed in Section 7.4 the Tesoro PHA goals encourage PHA 

teams to seek inherently safer safeguards to reduce risk. However, these approaches were never 

implemented until after the April 2010 incident. As discussed in Section 4.1.3, the CSB determined that 

implementing inherently safer design by using materials that are HTHA-resistant, such as stainless steel, 

is higher on the hierarchy of controls than post-weld heat treating or reliance upon inspections, and is 

therefore a better approach to prevent HTHA damage. 

7.8.4 The General Duty Clause 

Section 112(r)(1) of the Clean Air Act, known as the General Duty Clause, states the following: 

It is the objective of the regulations and programs authorized under this 

subsection to prevent the accidental release and to minimize the 

consequences of any such release of any substance listed pursuant to 

paragraph (3) or any other extremely hazardous substance. Owners and 

operators of stationary sources producing, processing, handling, or 

storing such stances under paragraph (3) have a general duty to identify 

hazards which may result from accidental releases using appropriate 

hazard assessment techniques, to design and maintain a safe facility 
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taking such steps as are necessary to prevent releases, and to minimize 

the consequences of accidental releases which do occur.247

The General Duty Clause has been in effect since November 15, 1990, when Congress adopted the Clean 

Air Act Amendments of 1990. According to EPA guidance on the General Duty Clause, “EPA believes 

that owners and operators who have [] [extremely hazardous] substances must adhere, at a minimum, to 

recognized industry standards and practices (as well as any government regulations) in order to be in 

compliance with the general duty clause.”248 The EPA notes that to comply with the General Duty 

Clause, “many industries have developed standards and generally recognized safe practices to manage the 

risks associated with extremely hazardous substances.”249

The application of IST is considered by many to be 

good industry practice. Yet inherent safety concepts 

are not enforced by the EPA through the General Duty 

Clause. According to process safety expert Dr. Paul 

Amyotte in a presentation at the CSB’s April 2013 

Chevron Interim Report Public Meeting in Richmond, 

California, there are numerous resources available on 

the topic of inherent safety, most of which are written 

by “industrial practitioners.” The call for widespread 

use of inherently safer design principles in industry is 

being made mainly by people in industry.250 For 

example, as discussed in Section 4.1.4, API RP 571 

Damage Mechanisms Affecting Fixed Equipment in the 

Refining Industry implicitly supports the concept of 

inherently safer design by describing material selection 

to avoid HTHA failures, noting “300 Series SS, as well 

as 5Cr, 9Cr and 12Cr alloys, are not susceptible to 

HTHA at conditions normally seen in refinery units.”251 

In addition, the CCPS has stated in its 2009 book 

Inherently Safer Chemical Processes A Life Cycle 

Approach, which was written by 18 committee members, 16 of which were listed as having affiliation 

with industrial companies, that the modern approach to chemical process safety “is to apply risk 

 

247 42 U.S.C. §7412(r)(1) (1990). 

248 EPA. Guidance for Implementation of the General Duty Clause Clean Air Act Section 112(r)(1). May 2000; p 2. 

http://www.epa.gov/oem/docs/chem/gdcregionalguidance.pdf (accessed January 23, 2014). 

249 Ibid. 250 Dr. Paul Amyotte. Presentation to the U.S. Chemical Safety and Hazard Investigation Board Public Meeting to 

Release Interim Report and Safety Recommendations Resulting from Chevron Refinery Investigation. 

Richmond, CA April 19, 2013; p 2. 251 API RP 571. Damage Mechanisms Affecting Fixed Equipment in the Refining Industry. 2003; page ‘5-83’. 
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management systems theory...[which] includes recognition of the hazards posted by the process, and a 

continual effort to analyze the risks, and to reduce or control them to the lowest levels practical....”252

7.8.5 The EPA’s Authority to Enforce Inherent Safety 

The EPA has acknowledged that it has the authority to require the application of IST through the General 

Duty Clause. In an August 2013 letter responding to a Congressional inquiry that specifically asked, 

among other things, whether the EPA believes it “has the authority to mandate the use and/or 

consideration of Inherently Safer Technologies 

under Section 112(r) of the Clean Air Act[,]” EPA 

Assistant Administrator Mathy Stanislaus stated 

that the EPA has “broad authority to promulgate 

regulations for chemical accident prevention...” 

and can “consider factors such as facility design, 

equipment, and quantity of substances handled 

(and other factors).” He also stated that the EPA 

was currently evaluating various methods of 

improving increased chemical plant safety 

including safer management, increased 

preparedness management, and facility design and 

operations, and would also be examining best 

practices being utilized by industry leaders. 

Others have argued that the EPA has additional authority under Clean Air Act section 112(r)(7)(A) to 

promulgate a new rule requiring industries to implement IST. This section authorizes the EPA 

Administrator to “promulgate release prevention, detection, and correction requirements which may 

include monitoring, record-keeping, reporting, training...and other design, equipment, work practice, and 

operational requirements.”253 Section 112(r) further requires that the risk management plan include 

“safety precautions and maintenance, monitoring and employee training measures” to prevent accidental 

releases.254 As described in Section 4.1.3, inherent safety and the hierarchy of controls are long 

established, widely recognized methods for achieving more effective safety precautions to prevent 

chemical accidents. Incorporating requirements for the implementation of inherent safety and the 

hierarchy of controls is not only consistent with the 112(r) proscribed features of the risk management 

plan but in fact serves to make the safety precautions more effective in preventing accidental releases. 

Despite its acknowledged authority to do so, to date the EPA has not required industries to implement IST 

through either the creation of a new rule or the enforcement of the Clean Air Act General Duty Clause. In 

the wake of Bhopal and more recently the 9/11 tragedy, many groups have urged the EPA to create a new 

regulation requiring the implementation of IST or at a minimum, use its authority under the General Duty 

 

252 CCPS. Inherently Safer Chemical Processes – A Life Cycle Approach. 2nd ed.; 2009; p 9. 

253 42 U.S.C. §7412(r)(7)(A) (1990). 

254 42 U.S.C. §7412(r)(7)(B)(ii)(II) (1990). 
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Clause to require industries to implement IST. On March 14, 2012, the National Environmental Justice 

Advisory Council255 (NEJAC) sent a letter to the EPA urging the agency to promulgate new rules or 

guidance to “utilize its authority under the ‘General Duty Clause’ of the 1990 Clean Air Act section 

112(r) (also known as the Bhopal clause) to require covered chemical facilities to prevent, where feasible, 

catastrophic chemical releases.”256 The NEJAC noted that flaws in the chemical security law 

administered by the U.S. Department of Homeland Security (DHS) prohibited the agency from requiring 

the use of safer chemical processes at facilities. The group also reiterated that the EPA had made a 

proposal in 2002 to implement the General Duty Clause to make chemical plants safer. According to the 

proposal, chemical plants would be made “inherently safer by reducing quantities of hazardous chemicals 

handled or stored, substituting less hazardous chemicals for extremely hazardous ones, or otherwise 

modifying the design of processes to reduce or eliminate chemical hazards.”257 The NEJAC also stated 

that in 2003, the Government Accountability Office (GAO) concluded that the EPA could “’interpret the 

Clean Air Act’s general duty clause to address chemical facility security... According to EPA, it would 

not have to make any regulatory changes as it currently implements the general duty clause through 

guidance... to address the specific threat of disastrous risks to vulnerable communities.”258 The NEJAC 

concluded by recommending that “EPA use its authority under the 1990 Clean Air Act, Section 112(r), to 

reduce or eliminate these catastrophic risks, where feasible, by issuing new rules and guidance to fully 

implement the General Duty Clause. This action would reduce the danger and imminent threat that 

chemical plants, chemical manufacturing, and the transport and storage of hazardous chemicals pose to 

environmental justice and communities.”259 

 On July 25, 2012, the Coalition to Prevent Chemical Disasters260 (“the Coalition”) petitioned the EPA to 

“commence a rulemaking [pursuant to the Administrative Procedure Act (AP), 5 U.S.C. §553(e), and 

section 112(r)(7)(A)261 of the Clean Air Act (CAA), 42 U.S.C. §7412(r)(7)(A)] to require the use of 

inherently safer technologies, where feasible, by facilities that use or store hazardous chemicals.” The 

petition also requested that, pending completion of the rulemaking, EPA revise its guidance concerning 

 

255 NEJAC is a federal advisory committee to EPA that was established on September 30, 1993. It provides advice 

and recommendations about issues related to environmental justice. For more information see 

http://www.epa.gov/Compliance/ej/nejac/index.html (accessed January 24, 2014). 256 See https://www.documentcloud.org/documents/332041-nejac-letter.html (accessed January 22, 2014). 

257 Ibid. 258 Ibid. 

259 Ibid. 

260 The Coalition consists of over 100 organizations formed to prevent chemical disasters and protect workers. For 

more information see http://preventchemicaldisasters.org/ (accessed January 24, 2014). 261 42 U.S.C. §7412(r)(7)(A) states: “In order to prevent accidental releases of regulated substances, the 

Administrator is authorized to promulgate release prevention, detection, and correction requirements which may 

include monitoring, record-keeping, reporting, training, vapor recovery, secondary containment, and other 

design, equipment, work practice, and operational requirements. Regulations promulgated under this paragraph 

may make distinctions between various types, classes, and kinds of facilities, devices and systems taking into 

consideration factors including, but not limited to, the size, location, process, process controls, quantity of 

substances handled, potency of substances, and response capabilities present at any stationary source. 

Regulations promulgated pursuant to this subparagraph shall have an effective date, as determined by the 

Administrator, assuring compliance as expeditiously as practicable.” 
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the enforcement of the CAA’s general duty clause, section 112(r)(1), 42 U.S.C. §7412(r)(1), to “make 

clear that the duty to prevent releases of extremely hazardous substances includes the use, where feasible, 

of safer technologies to minimize the presence and possible release of hazardous chemicals.”262 

In the wake of the April 2013 explosion and fire that occurred at a facility in West, Texas, and resulted in 

fifteen fatalities and hundreds of injuries, President Obama issued Executive Order 13650 on August 1, 

2013. It established the Chemical Facility Safety and Security Working Group, which includes OSHA 

and the EPA, and tasked the group with, among other things, developing options for enhancing and 

modernizing policies, regulations, and standards to improve the safety and security of chemical 

facilities.263 A senior EPA official overseeing implementation of the Executive Order has stated the EPA 

is examining the successes of a New Jersey program that requires facilities to consider IST, such as safer 

chemicals, as a possible model for a federal IST policy.264 New Jersey’s 2008 IST rule has led facility 

owners and operators to take a “hard look at opportunities to reduce risk” at industrial plants.265 

New Jersey is the only state that currently implements and enforces IST requirements.266 The Toxic 

Catastrophe Prevention Act (TCPA) implements IST requirements in New Jersey, and covers 

approximately 90 facilities in the state.267 An owner or operator of a covered facility must complete an 

IST review report and must submit it to the New Jersey Department of Environmental Protection (DEP). 

The report “...shall identify available inherently safer technology alternatives or combinations of 

alternatives that minimize or eliminate the potential for an EHS [extraordinarily hazardous substance] 

release.”268 

IST alternatives that are identified must be determined as “feasible” in order for implementation to be 

required. Feasible means “capable of being accomplished in a successful manner, taking into account 

environmental, public health and safety, legal, technological, and economic factors.”269 If IST is not 

implemented, they must provide a written justification using a qualitative and quantitative evaluation of 

 

262 https://www.documentcloud.org/documents/404584-petition-to-epa-to-prevent-chem-disasters-filed.html

(accessed January 22, 2014). 263 Improving Chemical Facility Safety and Security. Exec. Order No. 13650, 78 Fed. Reg. 48029 (August 1, 

2013). http://www.whitehouse.gov/the-press-office/2013/08/01/executive-order-improving-chemical-facilitysafety-and-security (accessed January 24, 2014). 264 http://insideepa.com/Risk-Policy-Report/Risk-Policy-Report-12/03/2013/epa-looks-to-new-jersey-program-aspossible-model-for-ist-requirements/menu-id-1098.html (accessed January 22, 2014). 

265 Ibid. 266 Contra Costa County, California has a guidance document entitled “Attachment C: Inherently Safer Systems 

Checklist” which 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). 267 Under Title 7 of the New Jersey Administrative Code. See N.J.A.C. Section 7:31-4.12 (2010). Available at 

http://www.nj.gov/dep/rpp/brp/tcpa/downloads/conrulerev9_no%20fonts.pdf (accessed January 23, 2014). 268 N.J.A.C. Section 7:31-4.12 (d) (2010). 

269 N.J.A.C. Section 7:31-1.5 (2010). 
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environmental, public health and safety, legal, technological, and economic factors. If they decide to 

implement the IST, they must provide a schedule of when they will do it.270

An update is required every five years for all covered processes and at the same time as the updates of 

applicable hazard reviews or process hazard analysis. An update of the IST review is also required when 

there is a major change. While New Jersey’s IST rule contains positive features, it is primarily focused 

on the activity of the production of the IST report and lacks rigorous goal setting elements such as 

requiring facilities to reduce risks to as low as reasonably practicable, or ALARP or requiring that the use 

of IST prevent accidental chemical releases. 

7.8.6 The Role of Inherent Safety in Major Accident Prevention 

In 2011, Dr. Paul Amyotte released an article analyzing 63 CSB reports, studies, and bulletins resulting 

from CSB incident investigations to identify examples related to inherent safety and risk reduction 

measures. The article identified over 200 examples of the hierarchy of controls, with 36 percent of those 

being inherent safety.271 He concluded that the CSB products contained numerous examples where the 

use of the hierarchy of controls, including inherent safety, would be helpful in reducing risk in the process 

industries.272 The four main principles of inherent safety (minimization, substitution, moderation, and 

simplification) all play a role in the prevention and mitigation of process incidents. 

Simply put, the CSB has investigated numerous major process safety incidents over the years, including 

the Chevron and Tesoro incidents, where the implementation of inherently safer design and materials of 

construction could have prevented the incident. The EPA should work with industry and stakeholders to 

develop and implement a new regulation requiring companies to use inherently safer systems analysis and 

the hierarchy of controls in establishing safeguards for identified process hazards to help prevent these 

major process safety incidents from occurring in the future. While the new regulation is being adopted, 

the EPA should use its existing authorities under the CAA General Duty Clause to implement inherently 

safer systems and the hierarchy of controls to the greatest extent feasible for chemical accident 

prevention. 

 

270 N.J.A.C. Section 7:31-4.12 (e) and (f) (2010). 

271 Amyotte, Paul; MacDonald, Dustin K.; and Khan, Faisal I. An Analysis of CSB Investigation Reports 

Concerning the Hierarchy of Controls. 2011; p 1. 272 Ibid.
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8.0 Recommendations 

Pursuant to its authority under 42 U.S.C. §7412(r)(6)(C)(i) and (ii), and in the interest of promoting safer 

operations at petroleum refineries and protecting workers and communities from future accidents both in 

the state of Washington and nationally, the CSB makes the following safety recommendations: 

8.1 The U.S. Environmental Protection Agency 

2010-08-I-WA-R1 

Revise the Chemical Accident Prevention Provisions under 40 CFR Part 68 to require the documented use 

of inherently safer systems analysis and the hierarchy of controls to the greatest extent feasible when 

facilities are establishing safeguards for identified process hazards. The goal shall be to reduce the risk of 

major accidents to the greatest extent practicable, to be interpreted as equivalent to as low as reasonably 

practicable (ALARP). Include requirements for inherently safer systems analysis to be automatically 

triggered for all management of change, incident investigation, and process hazard analysis reviews and 

recommendations, prior to the construction of a new process, process unit rebuilds, significant process 

repairs, and in the development of corrective actions. 

2010-08-I-WA-R2 

Until Recommendation 2010-08-I-WA-R1 is in effect, enforce through the Clean Air Act’s General Duty 

Clause, section 112(r)(1), 42 U.S.C. §7412(r)(1) the use of inherently safer systems analysis and the 

hierarchy of controls to the greatest extent feasible when facilities are establishing safeguards for 

identified process hazards. 

2010-08-I-WA-R3 

Develop guidance for the required use of inherently safer systems analysis and the hierarchy of controls 

for enforcement under 40 CFR Part 68 and the Clean Air Act’s General Duty Clause, section 112(r)(1), 

42 U.S.C. §7412(r)(1). 

2010-08-I-WA-R4 

Effectively participate in the Tesoro Anacortes Refinery process safety culture survey oversight 

committee as recommended under recommendation 2010-08-I-WA-R15. Incorporate the expertise of 

process safety culture experts in the development and interpretation of the safety culture surveys. Ensure 

the effective participation of the workforce and their representatives in the development of the surveys 

and the implementation of corrective actions. 

 
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8.2 Washington State Legislature, Governor of Washington 

2010-08-I-WA-R5 

Based on the findings in this report, augment your existing process safety management regulations for 

petroleum refineries in the state of Washington with the following more rigorous goal-setting attributes: 

a. A comprehensive process hazard analysis written by the company that includes: 

i. Systematic analysis and documentation of all major hazards and safeguards, using the 

hierarchy of controls to reduce those risks to as low as reasonably practicable (ALARP); 

ii. Documentation of the recognized methodologies, rationale and conclusions used to claim that 

safeguards intended to control hazards will be effective; 

iii. Documented damage mechanism hazard review conducted by a diverse team of qualified 

personnel. 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 effective safeguards are in place to control hazards presented by those 

damage mechanisms. Require the analysis and incorporation of applicable industry best practices 

and inherently safer design to the greatest extent feasible into this review; and 

iv. 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. 

b. A thorough review of the comprehensive process hazard analysis by technically competent regulatory 

personnel; 

c. Required preventative audits and preventative inspections by the regulator; 

d. Require that all safety codes, standards, employer internal procedures and recognized and generally 

accepted good engineering practices (RAGAGEP) used in the implementation of the regulations contain 

adequate minimum requirements; 

e. Require an increased role for workers in management of process safety by establishing the rights and 

responsibilities of workers and their representatives on health and safety-related matters, and the election 

of safety representatives and establishment of safety committees (with equal representation between 

management and labor) to serve health and safety-related functions. The elected representatives should 

have a legally recognized role that goes beyond consultation in activities such as the development of the 
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comprehensive process hazard analysis, management of change, incident investigation, audits, and 

identification and effective control of hazards. The representatives should also have the authority to stop 

work that is perceived to be unsafe or that presents a serious hazard until the regulator intervenes to 

resolve the safety concern. Workforce participation practices should be documented by the company to 

the regulator; and 

f. Requires reporting of information to the public to the greatest extent feasible such as a summary of the 

comprehensive process hazard analysis which includes a list of safeguards implemented and standards 

utilized to reduce risk, and process safety indicators that demonstrate the effectiveness of the safeguards 

and management systems. 

 
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2010-08-I-WA-R6 

Establish a well-funded, well-staffed, technically qualified regulator with a compensation system to 

ensure the Washington Department of Labor and Industries regulator has the ability to attract and retain a 

sufficient number of employees with the necessary skills and experience to ensure regulator technical 

qualifications. Periodically conduct a market analysis and benchmarking review to ensure the 

compensation system remains competitive with Washington petroleum refineries. 

2010-08-I-WA-R7 

Work with the regulator, the petroleum refining industry, labor, and other relevant stakeholders in the 

state of Washington to develop and implement a system that collects, tracks, and analyzes process safety 

leading and lagging indicators from operators and contractors to promote continuous process safety 

improvements. At a minimum, this program shall: 

a. Require the use of leading and lagging process safety indicators to actively monitor the 

effectiveness of process safety management systems and safeguards for major accident 

prevention. Include leading and lagging indicators that are measureable, actionable, and 

standardized. Include indicators that measure safety culture, such as incident reporting and action 

item implementation culture. Require that the reported data be used for continuous process safety 

improvement and accident prevention; 

b. Analyze data to identify trends and poor performers and publish annual reports with the data at 

facility and corporate levels; 

c. Require companies to publicly report required indicators annually at facility and corporate levels; 

d. Use process safety indicators (1) to drive continuous improvement for major accident prevention 

by using the data to identify industry and facility safety trends and deficiencies and (2) to 

determine appropriate allocation of regulator resources and inspections; and 

e. Be periodically updated to incorporate new learning from world-wide industry improvements in 

order to drive continuous major accident process safety improvements in Washington. 

 
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8.3 Washington State Department of Labor & Industries - Division of 

Occupational Safety and Health 

2010-08-I-WA-R8 

Perform a verification audit at all Washington petroleum refineries to ensure: 

a. Prevention of HTHA equipment failure and safe operation of the equipment. Audit HTHA 

prevention and process condition monitoring techniques used at all Washington petroleum 

refineries. Verify that all affected equipment in use meets the requirements contained in 

Recommendation 2010-08-I-WA-R10; 

b. For nonroutine work, a written hazard evaluation is performed by a multidisciplinary team and, 

where feasible, conducted during the job planning process prior to the day of the job execution. 

Verify that each facility has an effective written decision-making protocol used to determine 

when it is necessary to shut a process down to safely perform work or conduct repairs. Ensure 

the program reflects the guidance in the CCPS Risk Based Process Safety book related to 

hazardous nonroutine work; and 

c. Effective programs are in place to control of the number of essential personnel present during all 

hazardous nonroutine work. 

2010-08-I-WA-R9

Effectively participate in the Tesoro Anacortes Refinery process safety culture survey oversight 

committee as recommended under recommendation 2010-08-I-WA-R15. Incorporate the expertise of 

process safety culture experts in the development and interpretation of the safety culture surveys. Ensure 

the effective participation of the workforce and their representatives in the development of the surveys 

and the implementation of corrective actions. 

 
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8.4 American Petroleum Institute 

2010-08-I-WA-R10 

Revise American Petroleum Institute API RP 941: Steels for Hydrogen Service at Elevated Temperatures 

and Pressures in Petroleum Refineries and Petrochemical Plants to: 

a. Clearly establish the minimum necessary “shall” requirements to prevent HTHA equipment 

failures using a format such as that used in ANSI/AIHA Z10-2012, Occupational Health and 

Safety Management Systems;

b. Require the use of inherently safer materials to the greatest extent feasible; 

c. Require verification of actual operating conditions to confirm that material of construction 

selection prevents HTHA equipment failure; and 

d. Prohibit the use of carbon steel in processes that operate above 400 oF and greater than 50 psia 

hydrogen partial pressure. 

2010-08-I-WA-R11 

Revise American Petroleum Institute API RP 581: Risk-Based Inspection Technology to: 

a. Clearly establish the minimum necessary “shall” requirements to prevent HTHA equipment 

failures using a format such as that used in ANSI/AIHA Z10-2012, Occupational Health and 

Safety Management Systems;

b. Prohibit the use of carbon steel in processes that operate above 400 oF and greater than 50 psia 

hydrogen partial pressure; and 

c. Require verification of actual operating conditions to determine potential equipment damage 

mechanisms. 

 
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8.5 Tesoro Refining & Marketing Company LLC 

2010-08-I-WA-R12 

Actively participate with API in the completion of recommendation 2010-08-I-WA-R10. Document this 

participation. 

2010-08-I-WA-R13 

Once recommendation 2010-08-I-WA-R12 is in effect, develop and implement a plan to meet the 

requirements established through the acceptable completion of recommendation 2010-08-I-WA-R10. 

Document the implementation of the plan and the corrective actions taken.

2010-08-I-WA-R14 

Revise and improve the Process Hazard Analysis (PHA), the Integrity Operating Window (IOW), and the 

damage mechanism hazard review (DMHR) programs and cross-linking among these three programs such 

that all identified hazards are effectively managed in each program. For all Tesoro refineries require: 

a. the IOW to review damage mechanism hazards from the most recent PHA and safeguards 

identified to control these hazards; 

b. the IOW review or revalidation to be conducted at least every five years; 

c. the IOW to analyze and incorporate applicable industry best practice, the hierarchy of controls, 

and inherently safer design to the greatest extent reasonably practicable; 

d. the DMHR report to be developed by the DMHR team and not just the “corrosion expert;” 

e. the DMHR team to review the operating data to verify an accurate understanding of how the data 

was obtained, what it represents, and that it appropriately addresses both routine and nonroutine 

operations; 

f. the DMHR and/or IOW review to identify and review gaps between current industry best 

practices and existing Tesoro practices with regard to material selection and process controls and 

make recommendations that reduce risks from damage mechanism hazards; 

g. the DMHR and IOW review to review applicable Tesoro and industry-wide damage mechanism 

incidents as part of the respective DMHR or IOW review; 

h. the DMHR to review relevant MOCs to fully evaluate the impact of the MOC on damage 

mechanism hazards; 

i. the identification of minimum qualifications for the “corrosion expert” and ensure that the 

DMHR team has the necessary skills to meet these requirements; 

j. for sites that have a corrosion/materials engineer, the corrosion/materials engineer shall be a 

required participant in the DMHR; 
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k. the PHA to review the most recent DMHR and IOW reviews in order to contain a complete 

record of all identified damage mechanism hazards, evaluate existing safeguards, and propose 

new safeguards to control the identified hazards; 

l. the PHA to review the consequence of damage mechanism hazards identified in the risk-based 

inspection (RBI) program and IOW reviews to ensure effective safeguards are present to control 

the damage mechanism hazard; and 

m. the PHA to use the hierarchy of controls and implement opportunities for inherently safer design 

to the greatest extent reasonably practicable. 

8.6 Tesoro Anacortes Refinery 

2010-08-I-WA-R15 

Implement a process safety culture continuous improvement program at the Tesoro Anacortes Refinery 

including a written procedure for periodic process safety culture surveys across the work force. The 

process safety culture program shall be overseen by a tripartite committee of Tesoro management, USW 

representatives, Washington State Department of Labor and Industries – Division of Occupational Safety 

and Health, and the U.S. Environmental Protection Agency. This oversight committee shall: 

a. Select an expert third party that will administer a periodic process safety culture survey; 

b. Review and comment on the third party expert report developed from the survey; 

c. Oversee the development and effective implementation of action items to address identified 

process safety culture issues; and 

d. Develop process safety culture indicators to measure major accident prevention performance. 

The process safety program shall include a focus on items that measure, at a minimum, willingness to 

report incidents, normalization of hazardous conditions, burden of proof of safety in plant process safety 

programs and practices, and management involvement and commitment to process safety. The periodic 

process safety culture report shall be made available to the plant workforce. The minimum frequency of 

process safety culture surveys shall be at least once every three years. 

 
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8.7 United Steelworkers Local 12-591 

2010-08-I-WA-R16 

Effectively participate in the Tesoro Anacortes Refinery process safety culture survey oversight 

committee as recommended under recommendation 2010-08-I-WA-R15. 
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Appendix A AcciMap Causal Analysis 

The CSB team has developed an accident map (AcciMap) as a visual depiction of the casual factors of the 

April 2, 2010 Tesoro Anacortes Refinery explosion and fire (Figure 36).273 An AcciMap is a multilayered causal diagram that provides visualization of higher level causes at the company, industry and 

governmental levels. This diagram is especially useful for developing broadly applicable 

recommendations for accident prevention, 274 and includes five levels: 

- Outcome: Consequences of the incident 

- Physical Events and Conditions: The immediate causes of the incident.275

- Tesoro: Latent causes of the incident associated with company rules and policies. 

- Industry Codes and Standards: Latent causes of the incident associated with industry 

recommended practices, codes, and standards. 

- Government: Latent causes associated with government laws and legislation developed to 

manage highly hazardous industries.

 

273 A full-size, high resolution version of the Tesoro AcciMap is located on the CSB website. 

274 The AcciMap tool was developed by Jens Rasmussen and popularized by Andrew Hopkins. Rasmussen, J., &. 

A. Hopkins. Risk Management in a Dynamic Society: A Modeling Problem. Safety Science, 27 (2.3), 1997; pp 

183-213 

275 Immediate causal factors are the actions and conditions that directly lead to the consequence. However, while 

understanding immediate causal factors is vital, they are typically symptoms of systemic, or latent, causal 

factors. Latent causal factors are the pre-actions and pre-conditions that enabled the immediate causal factors to 

occur. It is these latent causal factors that must be alleviated in order to provide broad corrective change and 

prevent recurrence of similar incidents. 
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Figure 36. AcciMap of April 2, 2010 Tesoro Anacortes Refinery Explosion and Fire
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A.1 AcciMap Outcomes 

Seven Tesoro operations personnel were fatally injured following the sudden catastrophic failure of the 

in-service E heat exchanger that resulted in an explosion and fire. The fire burned for more than three 

hours and resulted in a seven month shutdown. 

A.2 Physical Events and Conditions 

The explosion and fire resulted from the sudden catastrophic rupture of the E heat exchanger, releasing 

flammable material that ignited likely because it was above its autoignition temperature. 

The seven fatally-injured employees, a more-than-typical number of workers for this job, were in the 

process of putting a bank of three heat exchangers (A/B/C) back in service. These heat exchangers were 

taken out of service several days before the incident for a maintenance cleaning operation to remove 

fouling, a deposit that greatly reduced heat transfer efficiency of the heat exchangers. While the A/B/C 

bank of heat exchangers was being cleaned, the NHT Unit continued to operate on the other bank, a 

matching series of three heat exchangers (D/E/F). 

When returning the three clean heat exchangers back to service, the middle heat exchanger of the D/E/F 

heat exchanger bank (the E heat exchanger) catastrophically ruptured. Post-incident metallurgical 

analysis determined that the E heat exchanger ruptured because of an advanced stage of HTHA. The 

HTHA occurred in both the B and E heat exchangers in the high stress, non post-weld heat-treated welds. 

The heat exchangers were in service for 38 years and were constructed of carbon steel, a material that is 

highly vulnerable to HTHA damage. 

A.3 Tesoro 

The intention of the established Tesoro procedures for startup of a bank of these heat exchangers was to 

require only one operator to be in the unit for the startup activity that was proceeding at the time of the 

incident. However, the more common practice was for additional operators to assist with this physical, 

labor-intensive startup activity. On the night of the incident, the operations supervisor requested five 

additional personnel to assist with the startup. All seven were present at the time of the incident and were 

working near the site of the explosion and fire. 

During startups of these heat exchangers, Tesoro routinely relied on the addition of ad hoc operations 

staff from other nearby operating units. This use of such additional personnel was explained as a result of 

both a collaborative culture and a need driven by task requirements. The startup of the heat exchangers 

required coordinated manual labor. In addition, a history of leaks was seen by the company as “normal” 

because of the high frequency of such leaks. The mitigation of these leaks required personnel standing by 

with steam lances, which some of the additional workers were likely doing on the night of the incident. 
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The startup of the NHT heat exchangers was hazardous nonroutine work. Leaks routinely developed that 

posed hazards to workers conducting the startup activities. Shell Oil and Tesoro PHAs at the refinery 

repeatedly failed to ensure that these hazards were controlled and that the number of workers exposed to 

these hazards was minimized. 

Tesoro was not aware of the severe HTHA damage in the B and E heat exchangers because it never 

performed any type of HTHA examination of the heat exchangers. Tesoro took this approach because 

corrosion experts had concluded HTHA was not a credible damage mechanism in these heat exchangers. 

This conclusion was based on a combination of reliance on the carbon steel Nelson curve (which the CSB 

has found to be unreliable) and a lack of knowledge of the actual operating conditions of the NHT heat 

exchangers. Instead of monitoring or modeling process conditions for use in PHAs and damage 

mechanism reviews, corrosion experts relied on process design data that suggested a lower HTHA 

susceptibility than indicated by the CSB modeling estimates. Therefore, these opportunities to identify 

the risks of HTHA were unsuccessful in preventing the April 2010 incident. 

A.4 Industry Codes and Standards 

API RP 941 is the industry standard for preventing equipment failure from HTHA by establishing 

equipment operating limits. This standard contains empirical industry HTHA experience based on 

temperature and hydrogen partial pressure. It notes operating boundaries at locations where various 

materials of construction have failed because of HTHA and where they apparently have not failed. Over 

the years, the boundaries have become more conservative in response to industry failures that occurred 

outside of the previously experienced operating limits. 

API RP 941 is written with permissive language. It is presented as a guideline that “is often used when 

selecting materials in hydrogen service.” It is also described as “an aide for materials selection.” API RP 

941 does not establish minimum requirements to prevent HTHA failures: 

 There are no minimum requirements for performing HTHA susceptibility evaluations. 

 There are no minimum requirements for selection of materials of construction to ensure that 

inherently safer design is employed. 

Analysis of the metal recovered from the B and E heat exchanger shell walls revealed a significant 

occurrence of HTHA well within the “safe” operating limits established by API RP 941, indicating that 

the current location of the carbon steel Nelson curve cannot be trusted to prevent equipment failure and 

cannot be relied on to predict the occurrence of HTHA. Damage from HTHA was occurring in portions 

of the B and E heat exchangers that CSB process modeling determined were operating as much as 120 °F 

degrees below the carbon steel Nelson curve. 

Other industry standards, such as API RP 581, offer guidance on how to predict, mitigate, and control the 

occurrence of HTHA. However, such standards share similar weaknesses with API RP 941. API 581 

does not require verification of actual operating conditions when identifying applicable damage 

mechanisms. API RP 581 calculations to determine susceptibility of equipment to HTHA confirmed that 

the B and E heat exchangers were not susceptible to HTHA. 
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A.5 Government 

The existing federal and state of Washington regulations for PSM of highly hazardous chemicals were not 

sufficient to prevent this incident as they were primarily activity based and did not focus on specific risk 

reduction (such as ALARP), inherently safer design, require leading and lagging process safety indicators, 

or require continuous improvement. For example, the unit PHA ineffectively identified and managed 

hazards, but its completion still satisfied the state of Washington’s PSM standard. In addition, despite its 

ability to do so, the EPA does not require facilities to analyze opportunities to implement inherently safer 

design. 

The state of Washington’s L&I completed a formal inspection of the CR and NHT process units as part of 

the OSHA Refinery NEP in March 2009, just more than one year before the incident. However, the NEP 

inspection lacked the level of detail required to detect the technical deficiencies in the Tesoro refinery’s 

mechanical integrity program. No HTHA issues were identified, and no citations relating to the E heat 

exchanger were issued. The state of Washington did not have sufficient personnel resources with the 

required technical knowledge and experience to seek out and oversee the highly technical area of failure 

mechanisms. The state of Washington has only four PSM specialists in its compliance section to regulate 

nearly 270 PSM-covered facilities, including five petroleum refineries. 
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Appendix B NHT A/B/C Heat Exchanger Startup Trend Data 

Trends of tube-side outlet temperatures are shown in Figure 38 through Figure 41 for the night of the 

incident and for the three previous startups for the A/B/C heat exchangers. The locations of the two 

temperature measurements are shown in Figure 37. 

Figure 37. Location of the Two Outlet Temperature Measurements 

D/E/F outlet temperature 

A/B/C outlet temperature 
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Figure 38. Temperature Data During NHT A/B/C Heat Exchanger Bank Startup on Night of the 

Incident 

Figure 39. Temperature Data During NHT A/B/C Heat Exchanger Bank Startup on August 29, 2009 
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Figure 40. Temperature Data During NHT A/B/C Heat Exchanger Bank Startup on April 2, 2009 

Figure 41. Temperature Data During NHT A/B/C Heat Exchanger Bank Startup on February 3, 2008 
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Appendix C CSB Simulation of the NHT Heat Exchangers 

C.1 Background

Process conditions (temperature, pressure, flow, and composition data) were available for the NHT feed 

streams entering and exiting the two banks of the NHT heat exchangers (Figure 42). However, the 

system lacked instrumentation between the individual heat exchangers. Therefore, the actual process 

conditions of the fluid entering and exiting the B and E heat exchangers were not available. The CSB 

used the Aspen HYSYS® and Aspen Exchanger Design and Rating process simulation computer software 

to model the A/B/C and D/E/F heat exchanger banks for estimating process conditions in the B and E heat 

exchangers where HTHA occurred. 

Of particular importance was the capability to model the qualitative fouling observations documented by 

Shell Oil workers.276 These observations indicate that the heat exchangers primarily fouled within the 

tubes. The observations also indicate that fouling in the A and D tubes was “Heavy”, fouling in the B and 

E tubes was “Moderate”, and fouling in the C and F tubes was “Light.”277 The documented observations 

show that the shell-side of the NHT heat exchangers experienced the formation of a light scale. 

 

276 These observations were made when Shell Oil owned the refinery. 

277 Other qualitative descriptions were also noted. However, these conditions were most frequently reported. 
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Figure 42. NHT Heat Exchanger Configuration with Known Process Conditions Indicated 

C.2 Modeling Approach 

The computer program Aspen Exchanger Design and Rating is a tool that allows the development of a 

rigorous mechanical model of a heat exchanger based on the actual mechanical details. The heat 

exchanger design data entered into the program included specific construction details such as the heat 

exchanger type; the shell dimensions; the number, diameter, and length of tubes; the baffle configuration; 

and the material of construction. 

The model developed using Aspen Exchanger Design and Rating was then used as an input to another 

Aspen computer program, Aspen HYSYS®. This software provides the capability to combine the heat 

exchanger mechanical model into a process model of an entire section of a refinery process, such as the 

NHT heat exchangers. Model inputs include data from the process, such as flow rates, temperature, 

pressures, process compositions and process physical properties. The CSB used the Aspen HYSYS®
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model to simulate past performance of the NHT feed/effluent heat exchangers. Historical DCS data and 

composition data were input into the model to reflect actual operating conditions. 

C.3 Fouling Distribution 

A key focus of the CSB modeling effort was to estimate operating conditions of the heat exchangers when 

they were fouled. Fouling results in higher shell-side temperatures, and the potential for HTHA would 

have been most severe during higher-temperature periods. The model includes input parameters, called 

fouling resistance, for estimating heat exchanger fouling. The CSB calibrated these fouling parameters 

by matching actual operating data under fouled conditions. Next, the CSB apportioned the level of 

fouling among the various heat exchangers. In both the model results and the data for actual heat 

exchangers in the unit, distribution of fouling among the A/D, B/E, and C/F heat exchanger tubes greatly 

affects the process conditions within the B and E heat exchangers. 

Because actual fouling distribution throughout the heat exchangers was not known, the CSB performed a 

sensitivity analysis of possible fouling distributions on the tube-side of the heat exchangers to 

approximate conditions that existed based on the available qualitative visual observations. For example, 

these observations described a uniformly light scale on the shell-side of each heat exchanger. As a result, 

a constant, light fouling resistance was incorporated in the model to represent this light scale. Qualitative 

observations also described fouling inside the tubes, with the extent of observed fouling increasing from 

C/F to B/E and then to A/D. The tube-side fouling distributions analyzed for the sensitivity analysis are 

shown in Figure 43. Distribution 2 was selected for the model because it best matched the overall 

documented observations of heat exchanger fouling. 

Percent fouling resistance 

in A/D exchangers 

Percent fouling 

resistance in B/E 

exchangers 

Percent fouling 

resistance in C/F 

exchangers 

Distribution 1 60% 30% 10% 

Distribution 2 55% 32.5% 12.5% 

Distribution 3 50% 35% 15% 

Figure 43. NHT Heat Exchanger Fouling Distributions Analyzed 

A schematic of how these distributions may appear visually is shown in Figure 44. 
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Figure 44. Visualization of Possible Tube-Side Fouling Distributions 

C.4 DCS Data and Composition Data Availability 

The necessary DCS and fluid composition data needed to model the heat exchangers were only available 

between 2007 and 2010.278 As a result, all modeled values represent estimates of process conditions 

causing HTHA from 2007 through 2010. HTHA degradation of the B and E heat exchangers during this 

time period is likely because the heat exchangers had experienced higher temperature and greater 

mechanical stress in the 2007 to 2010 time period than on the night of the incident.279 

 

278 The Tesoro Anacortes, Washington refinery first installed its DCS system in 2002. However, not all variables 

necessary for process simulation of the NHT heat exchangers were measured until 2007. 

279 On February 23, 2008, the D/E/F heat exchanger tube outlet temperature increased by 100 F over a 10 minute 

period before being brought down for a cleaning operation, reaching a maximum temperature of 

681 F. On August 22, 2009, during a startup of the D/E/F heat exchanger bank following a cleaning operation, 

the D/E/F exchanger bank tube outlet temperature increased by 100 F over a four minute period, reaching a 

maximum temperature of approximately 641 F during the startup. Other high-stress events during exchanger 
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The CSB modeled 10 days of operation during this 2007 to 2010 time period. Two of the periods 

modeled were characterized by clean heat exchanger conditions; during three of the periods modeled, 

middle-of-run operation conditions existed; and five of the periods modeled were characterized by fouled 

heat exchanger conditions near the end of a run. 

C.5 Calibration of Model with Actual Process Data 

Figure 45. Calibration of HYSYS Model with Actual Process Data. The fouling resistances (fouling 

factors), maintaining the 55%, 32.5%, 12.5% split, were adjusted until the tube-side and shell-side 

outlet model temperature results closely matched actual DCS-measured temperatures. 

Shown in Figure 45, actual composition data, flow rates, temperatures, and pressures were available for 

the process fluid entering both the tube-side and shell-side of the heat exchanger banks. Measured 

temperature values were available for the fluid exiting both the tube-side and shell-side of the heat 

exchanger banks. The fouling resistances (fouling factors) were adjusted in the model, maintaining the 

55%, 32.5%, and 12.5% split until the model’s tube and shell outlet temperatures closely matched the 

actual, measured process temperatures. This method resulted in an average of 2.5% error between the 

model’s outlet temperatures and the actual, measured tube and shell outlet temperatures. The temperature 

profile of the B and E heat exchangers was then analyzed to determine temperatures and hydrogen partial 

pressures along the length of the heat exchangers. 

 

startup are also shown in Appendix B. The E heat exchanger did not rupture as a result of the temperature and 

mechanical stresses of these startups. 
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C.6 Modeling Results 

The resulting plot of modeled operating conditions of the B and E heat exchangers is shown in Figure 46, 

which illustrates the full operating region of the B and E heat exchangers, the operating conditions at the 

rupture location, and the operating conditions at the CS2 seam (the coldest location where signs of HTHA 

were evident in the E heat exchanger). All graphed regions use the Distribution 2 fouling allocation. 

The estimated operating regions for the stainless steel clad portion of the B and E heat exchangers 

extended above the carbon steel Nelson curve. At the rupture location, the estimated operating conditions 

are just below the carbon steel Nelson curve. Model results for the coldest area of the E heat exchanger 

where signs of HTHA were evident (the CS2 weld between Cans 1 and 2) indicate HTHA damage in 

equipment that operated between 70 °F to 120 °F below the carbon steel Nelson curve. All graphed 

regions use the Distribution 2 fouling allocation. The model results illustrate the imprecision of the 

carbon steel Nelson curve. 

Figure 46. Estimated Operating Conditions of the B and E Heat Exchangers 
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Appendix D Evaluation of Current Tesoro Programs to Identify 

and Control Damage Mechanism Hazards 

In developing a recommendation for Tesoro to address several of the findings in Section 1.2.2, the CSB 

evaluated current Tesoro standards for conducting DMHRs, PHAs, and Integrity Operating Window 

(IOW). In addition to the incident-specific analyses described in the report, this evaluation provides the 

necessary detail and support for recommendation 2010-08-I-WA-R14. 

DMHRs evaluate a subset of hazards within the scope of a PHA.280 Because of the specialized focus and 

expertise required to properly assess damage mechanism hazards, Tesoro has developed a program to 

evaluate these hazards outside of the PHA process, using external hired experts. The PHA team is then 

required to review this information and incorporate it into the applicable PHA. 

The Tesoro PHA standard includes a requirement for the PHA team to review the most recent DMHR. 

This requirement establishes a link between the DMHR and the PHA, but it is not currently sufficient. To 

provide a better connection between the DMHR and the PHA, the DMHR team should be required to 

review the most recent PHA and validate the damage mechanism hazards and the safeguards identified to 

control these hazards. The PHA standard does not include a link between the IOW and the PHA. The 

PHA team should be required to review IOWs and validate the damage mechanism hazards and the 

safeguards identified to control these hazards. 

IOWs are intended to address operating limits to prevent unexpected degradation of equipment. Like 

DMHRs, IOW reviews evaluate a subset of hazards within the scope of a PHA. The IOW standard 

addresses 51 degradation mechanisms that Tesoro has determined should be evaluated outside of the PHA 

process. The results of the IOW review must be integrated into the PHA; however, the PHA standard 

does not currently contain language to ensure that this requirement is completed. Although IOWs provide 

a mechanism to qualitatively rank degradation hazard risks, there is no provision to evaluate the 

effectiveness of safeguards, consider the hierarchy of controls, or evaluate opportunities for inherently 

safer design to the greatest extent feasible. The results of the DMHR are reviewed and incorporated into 

the development of IOWs. Although degradation hazards are evaluated in the IOW review process, 

IOWs are only revalidated every 10 years, twice the 5-year revalidation frequency allowed by the PSM 

regulations.281 The IOW does evaluate incidents, but there is no provision to evaluate or consider 

industry-wide incidents. The IOW process does consider both routine and nonroutine operations. 

The Tesoro PHA standard includes guidance to provide direction to the PHA team on its responsibilities. 

This guidance suggests that the PHA team is responsible only for a review of the completed critical 

 

280 The state of Washington PSM rule requires that the PHA shall address the hazards of the process. See: 

http://www.lni.wa.gov/wisha/rules/hazardouschemicals/#WAC296-67-017 (accessed December 29, 2013). 

These regulations do not specifically require a DMHR. 

281 WAC 296-67-017(6), “Process hazard analysis,” requires the PHA to be updated and revalidated at least every 5 

years. See: http://www.lni.wa.gov/wisha/rules/hazardouschemicals/#WAC296-67-001 (accessed January 11, 

2014). 
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process data sheet that the corrosion expert produces as part of the DMHR. A specific requirement is 

never explicitly made for the PHA team to identify damage mechanism hazards, evaluate existing 

safeguards, and propose new safeguards to control these hazards. 

None of the Tesoro PHA, DMHR, or IOW standards ensure that effective safeguards are identified and 

evaluated to control damage mechanism hazards. Such a review is implied by the overarching 

requirements in the Tesoro PHA standard. However, the language used in the standard could functionally 

reduce the responsibility of the PHA team to a mere review of the critical process data sheet developed by 

the corrosion expert as part of the DMHR. No formal evaluation of safeguards is ever described as a 

requirement for damage mechanism hazards or for the establishment of IOWs. 

To improve the DMHR, this team should conduct a review of the relevant PHA hazards that address 

damage mechanisms. For these hazards, the DMHR should validate consequence, frequency, and 

proposed safeguards to control damage mechanism hazards. The DMHR should also evaluate alternatives 

that consider the hierarchy of controls and opportunities for inherently safer design to the greatest extent 

feasible. 

The final deliverable from a Tesoro DMHR is a written report that the corrosion expert prepares. Because 

the DMHR team does not review and approve this final report, it does not meet OSHA PSM requirements 

for a PHA. There is an OSHA interpretation letter from October 31, 1996, that essentially states that a 

“team”282 must perform the hazard analysis. OSHA’s intent appears to be that the analysis and 

recommendations developed remains a team product. As written, the Tesoro DMHR results in a team 

analysis but with a report developed by an individual. 

Under the Tesoro DMHR standard, the corrosion expert is required to assemble a critical process data 

spreadsheet. This spreadsheet is submitted to someone who has process expertise to provide the required 

process operating data. However, there is no guidance on how these data should be obtained or assurance 

that the data are appropriate to properly evaluate a given damage mechanism. In light of the April 2010 

incident at the Anacortes refinery, for each identified damage mechanism, there should be a clear 

understanding of what process data are required as well as a provision to ensure that design operating data 

are not used in lieu of obtaining actual measurements or performing a technical evaluation such as a 

process simulation to estimate needed process data. The DMHR team should review the operating data 

and collection techniques to verify an accurate understanding of how the data were obtained and what 

they represent, and it should appropriately consider routine and nonroutine operations as well as the full 

range of operating conditions. 

Before the April 2010 incident, in 2003, API identified materials that are not susceptible or are highly 

resistant to HTHA damage.283 Neither Shell Oil nor Tesoro damage mechanism reviews considered these 

materials as inherently safer controls for HTHA hazards. The Tesoro DMHR and IOW processes do not 

 

282 See: https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=INTERPRETATIONS&p_id=22289

(accessed December 29, 2013). 283 API RP 571. “Damage Mechanisms Affecting Fixed Equipment in the Refining Industry.” Pages 5–56, 2003. 
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ensure that gaps between current industry best practices and existing Tesoro practices are identified, 

evaluated, and considered when creating recommendations to reduce risk of damage mechanism hazards. 

Tesoro should maintain an incident database on damage mechanism incidents, both for Tesoro and 

industry-wide. The DMHR and IOW teams should conduct a review of these incidents that should be 

included in the DMHR and IOW reports.284

As a result of separating the evaluation of damage mechanisms from the formal PHA process, potential 

gaps exist when the PHA team reviews MOCs and incident reports during the PHA process.285 In 

addition to a review by the PHA team, MOCs relevant to potential damage mechanisms should be 

reviewed by the IOW team to fully evaluate the impact of proposed and planned changes within the 

refinery on relevant damage mechanism hazards. The IOW standard requires integration of IOWs into 

the MOC process, but the MOC standard currently has no provision to consider IOWs. 

The Tesoro DMHR is one component of the Tesoro RBI program, which determines potential 

consequences for hazards such as equipment failure from damage mechanisms. Tesoro currently 

determines the consequences of damage mechanism hazards as a separate activity from the PHA, and 

there is no verification that the consequences determined by the DMHR are consistent with the PHA. To 

improve the Tesoro PHA process, PHA teams should review and validate the relevant consequence of 

hazards identified by the RBI program.286 

Tesoro requires a corrosion expert to lead the DMHR process. However, the qualifications of the 

corrosion expert are not defined. Minimum qualifications should be clearly defined, and additional 

personnel should be added to the team if the identified corrosion expert does not meet all of the minimum 

qualifications. 

The Tesoro requirement for DMHR meeting participants is confusing and should be clarified. The 

refinery corrosion and materials engineer is listed as a required participant, but then the DMHR document 

uses the language “if present.” It is not clear why or under what conditions Tesoro would conduct a 

DMHR without the participation and expertise of the refinery corrosion and materials professional. 

 

284 The identification of any previous incident that had a likely potential for catastrophic consequences in the 

workplace is a requirement of the State of Washington PSM rule. See: 

http://www.lni.wa.gov/wisha/rules/hazardouschemicals/#WAC296-67-017 (accessed December 29, 2013). 285 The Tesoro PHA standard requires PHA revalidations to address “Changes since the last PHA(s)—Management 

of Change (MOC).” The Tesoro PHA standard also requires the PHA to evaluate previous incidents. The 

standard requirements mirror the language of the State of Washington PSM rule, “The identification of any 

previous incident which had a likely potential for catastrophic consequences in the workplace.” 

286 For these hazards, the PHA team should ensure that there are effective safeguards to control damage mechanism 

hazards. The PHA team should also evaluate alternatives that consider the hierarchy of controls and 

opportunities for inherently safer design to the greatest extent feasible. 
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Appendix E Inspection Techniques 

The most basic nondestructive examination (NDE) technique is simply a visual examination that typically 

evaluates for physical damage such as dents or cracks, discoloration, or the presence of foreign material 

(such as process fouling or corrosion products similar to rust). However, significant damage is not 

always visible to the naked eye. Much like a doctor uses of X-rays or an MRI, or a CAT scan, the 

inspector uses more sophisticated tools and techniques to determine the condition of the refinery 

equipment. Typical NDE techniques include the following: 

 Ultrasonic Technique (UT)—is the primary NDE technique for determining the extent of general 

corrosion attack. UT uses high frequency sound waves that are transmitted into a material and 

travel in a straight line and at a constant speed until they encounter a surface. The surface 

interface causes some of the wave energy to be reflected, and the rest of it is transmitted. The 

quantity of reflected versus transmitted energy is detected. Expert examination of the data 

provides information such as the presence of discontinuities and the thickness of the material or 

coating.287

 Radiographic Technique (RT)—also referred to as X-ray, is commonly performed using two 

different sources of radiation, X-ray and gamma ray. Advantages include a minimum surface 

preparation requirement and sensitivity to changes in thickness, corrosion, voids, cracks, and 

material density. The disadvantages are safety precautions required for the safe use of radiation, 

and access constraints in the field.288

 Dye Penetrant Inspection (DPI)—also called Liquid Penetrant Inspection (LPI) or Penetrant 

Technique (PT), is a widely applied and low-cost inspection method used to locate surfacebreaking defects in all non-porous materials (such as metals, plastics, or ceramics). DPI is used 

to detect cracks, surface porosity, lack of penetration in welds and defects resulting from inservice conditions (for example fatigue cracks of components or welds) in castings, forgings, and 

welding surface defects.289

 Magnetic Particle (MT)—is used for finding surface and near surface defects in ferromagnetic 

material and is a versatile inspection method for field and shop applications. Magnetic particle 

testing works by magnetizing a ferromagnetic specimen using a magnet or special magnetizing 

equipment. If the specimen has discontinuity, the magnetic field flowing through the specimen is 

interrupted and leakage field occurs. Finely milled iron particles coated with a dye pigment are 

applied to the specimen. These are attracted to leakage fields and cluster to form an indication 

directly over the discontinuity. The indication is visually detected under proper lighting 

 

287 See: http://www.mistrasgroup.com/services/traditionalndt/ut.aspx (accessed August 1, 2013). 

288 See: http://www.mistrasgroup.com/services/traditionalndt/rt.aspx (accessed August 1, 2013). 

289 See: http://www.eceglobal.com/services/inspection-approvals/non-destructive-examination-nde/penetrant-testingpt/, (accessed June 3, 2013). 
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conditions. Wet Fluorescent Magnetic Particles (WFMPT) is sometimes applied to increase 

sensitivity for locating very small defects.290

 Ultrasonic Shear Wave—also called Angled Beam Ultrasonic Technique, can be used to inspect 

pipe, critical welds in pressure vessels and plate weldments, and can be used to inspect cracks for 

depth, size, length and orientation. This is a common technique used for weld inspection, which 

provides a sensitive, fast and cost effective method to detect, locate, and validate a range of large 

to small defects and deterioration. 291

 Phased Array Ultrasonic Technology (PAUT)—has the capability of creating multiple beam 

angles and focal points with the use of a multi-element ultrasonic transducer, and providing full 

volumetric sectorial scans (S-Scans), a feature unique to this technology. S-Scans are real-time 

side view images generated from a single inspection point; in essence, it depicts an internal view 

of the component being inspected. With this technology, weld flaw and crack detection and 

sizing can be achieved at a high rate of speed, many times faster than conventional shear wave 

inspection can achieve.292

 Advanced Ultrasonic Backscatter Technique (AUBT)—developed by Shell Oil in the early 

1990s, is currently the best NDE method for detecting and quantifying damage from HTHA. The 

technique uses conventional UT probes and a digital oscilloscope to provide both an A-Scan 

display and frequency analysis.293 AUBT is a sophisticated technique and requires a very high 

level of expertise.294 There is no general certification of inspector competence in the application 

of HTHA detection techniques. 

 Velocity Ratio: HTHA reduces the velocity of both shear and longitudinal waves. When a 

material is attacked by HTHA, the velocity reduction is slightly more with longitudinal than with 

shear waves. This in effect increases the ratio of shear wave to longitudinal wave velocities or 

the ratio of the transit times. This ratio of transit times can be used as an indicator of HTHA. 

Tests have shown that the velocity-ratio approach is only effective at high levels of HTHA and is 

limited to the base metal.295

 

290 See: http://www.mistrasgroup.com/services/magnetic-particle-testing.aspx, (accessed June 3, 2013). 

291 See: http://techcorr.com/services/Inspection-and-Testing/Ultrasonic-Shear-Wave.cfm (accessed July 16, 2013). 

292 See: http://www.autsolutions.net/Phased_array.html (accessed July 16, 2013). 

293 See: http://www.spi-matrix.com/advanced-ultrasonic-backscatter.php (accessed July 16, 2013). 

294 See: http://www.nde.com/hydrogen.htm (accessed June 13, 2013). 

295 See: http://www.ndt-ed.org/EducationResources/CommunityCollege/Ultrasonics/Physics/modeconversion.htm

(accessed January 13, 2013). 
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Appendix F CSB Chevron Reports Incorporated by Reference 

Both the CSB Chevron Interim Report and the draft Chevron Regulatory Report have been incorporated 

into this report on the Tesoro Anacortes Refinery incident by reference to support the regulatory analysis 

and recommendations. The Chevron Interim Report can be accessed at 

http://www.csb.gov/assets/1/19/Chevron_Interim_Report_Final_2013-04-17.pdf and the draft Chevron 

Regulatory Report can be accessed at http://www.csb.gov/chevron-refinery-fire/. 
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Appendix G Spectrum Inspection Reports 

The Spectrum Inspection Reports can be accessed at http://www.csb.gov/tesoro-refinery-fatal-explosionand-fire/. 
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Appendix H Beta Laboratory Reports 

The Beta Laboratory Reports can be found at http://www.csb.gov/tesoro-refinery-fatal-explosion-andfire/. 
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Appendix I Metallurgical Review 

The metallurgical report can be accessed at http://www.csb.gov/tesoro-refinery-fatal-explosion-and-fire/. 

 
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Appendix J Additional HTHA Evaluation Report 

This report can be accessed at http://www.csb.gov/tesoro-refinery-fatal-explosion-and-fire/. 
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Thank you for reading this CSB report. 

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