Safety

Bulletin

U.S. Chemical Safety and Hazard Investigation Board

BP TEXAS CITY, TX REFINERY FIRE

No. 2005-04-B|October 12, 2006

Summary

On July 28, 2005, 4 months after a devastating

incident in the Isomerization (Isom) Unit that killed

15 workers and injured 180, the BP Texas City refinery

experienced a major fire in the Resid Hydrotreater Unit

(RHU) that caused a reported $30 million in property

damage. One employee sustained a minor injury during

the emergency unit shutdown and there were no fatalities.

The RHU incident investigation determined that an

8-inch diameter carbon steel elbow inadvertently installed

in a high-pressure, high-temperature hydrogen line

ruptured after operating for only 3 months. The escaping

hydrogen gas from the ruptured elbow quickly ignited.

This incident occurred after a maintenance contractor

accidentally switched a carbon steel elbow with an alloy

steel elbow during a scheduled heat exchanger overhaul

in February 2005. The alloy steel elbow was resistant to

high temperature hydrogen attack (HTHA) but the carbon

steel elbow was not. Metallurgical analyses of the failed

elbow concluded that HTHA severely weakened the

carbon steel elbow.

The U.S. Chemical Safety and Hazard Investigation Board

(CSB) issues this Safety Bulletin to focus attention on

process equipment configuration control and positive

material verification of critical alloy steel piping

components. The CSB recommends that the refining,

petrochemical, and chemical industries review material

verification programs to ensure that maintenance

procedures include sufficient controls and positive

material identification (PMI) testing to prevent improper

material substitutions in hazardous process systems.

BP Texas City Refinery

The Texas City refinery is the third-largest in

the United States with a capacity in excess of

450,000 barrels per day of crude oil. More than

1,600 BP employees and hundreds of contract

personnel operate and maintain the facility.

Residual material from the crude oil processing

unit is processed in the RHU to remove

nitrogen, sulfur, and metals. Hydrogen is

pressurized to about 3000 psi, and then preheated in the RHU heat exchangers (Figure 2) to

about 600o

F. The preheated hydrogen next

passes through a furnace to increase the

hydrogen temperature, and then is injected into

the reactor feedstock. Hydrogen combines with

nitrogen compounds and sulfur within the

feedstock in the presence of the catalyst inside

the RHU reactors to form hydrogen sulfide and

ammonia. Light hydrocarbon, such as

gasoline, is then processed in downstream

refinery units.

POSITIVE MATERIAL VERIFICATION: PREVENT ERRORS

DURING ALLOY STEEL SYSTEMS MAINTENANCE

Figure 1. Carbon steel RHU heat exchanger outlet

pipe (arrow) ruptured after operating only 3

months in high-temperature hydrogen service.
2

CSB Investigation Reports are

formal, detailed reports on

significant chemical accidents and

include key findings, root causes,

and safety recommendations. CSB Hazard

Investigations are broader studies

of significant chemical hazards. 

CSB Safety Bulletins are short,

general-interest

publications that

provide new or

noteworthy

information on

preventing chemical

accidents. CSB

Case Studies are short reports on

specific accidents and include a

discussion of relevant good

practices for prevention. All

reports include safety

recommendations when

appropriate. CSB Investigation

Digests are plain-language

summaries of Investigation

Reports.

Incident

Description

On July 28, 2005, at about 6:00 pm,

an RHU hydrogen gas heat

exchanger process pipe ruptured.

The venting hydrogen gas ignited

and a huge fireball erupted in the

unit. One employee sustained a

minor injury while assisting with

the RHU emergency shutdown.

The RHU sustained major damage

from the hydrogen-fed fire that

burned for two hours. There were

no offsite impacts but, as a

precaution Texas City ordered a

shelter-in-place for nearby

residents until the fire was

contained.

BP personnel examined the extensively damaged unit and determined that an 8-inch diameter pipe

elbow on an RHU heat exchanger

hydrogen gas outlet pipe ruptured

(Figure 3). The BP investigation

team recovered the elbow segments

that remained attached to the pipe

and three pieces found in the

debris (Figure 4).

The venting hydrogen gas ignited

and a huge fireball erupted in the

unit.

z

Upper left & top arrow --

Alloy steel elbows 2 and 3

Lower left arrow --

Carbon steel elbow 1

Figure 2. Dimensionally identical piping elbows on RHU heat exchangers A and B.
3

BP personnel examined

the extensively damaged

unit and determined that

an 8-inch diameter pipe

elbow on an RHU heat

exchanger hydrogen gas

outlet pipe ruptured . . .

The BP investigation team

recovered the elbow

segments that remained

attached to the pipe and

three pieces found in the

debris . . .

Figure 3. Ruptured 8-inch pipe elbow on heat exchanger A outlet.

Figure 4. Ruptured 8-inch carbon steel pipe elbow pieces

recovered after the fire

Upper left -- Carbon steel elbow

segments (view of inside surface)

Above -- Flange segments

Lower left -- Close-up of fissure on

middle elbow segment

z

z
4

5

 The cost of 1.25 percent chrome low

alloy pipe is approximately three to four

times more expensive than carbon steel

pipe.

4

 The metallurgical analysis did not

calculate the actual service life of the

carbon steel elbow. Rather, it compared

the observed extent of carbon steel

degradation to total time in service of

more than 100,000 hours or fewer than

3,000 hours assuming the carbon steel

and low alloy steel elbows were swapped

either in the 1991 or 2005 maintenance

overhaul.

Incident Analysis

HTHA Failure Mechanism

Incidents involving HTHA date

back to the 1940s. Carbon steel in

hydrogen service at temperatures

above about 450oF and pressures

above 100 psia is susceptible to

HTHA. At these operating

conditions, atomic and molecular

hydrogen permeates the steel and

reacts with dissolved carbons or

carbides1 to form methane gas. The

loss of carbon in the steel, or

“decarburization,” significantly

degrades the steel’s mechanical

properties, including tensile

strength and ductility.2 The

methane gas creates high localized

stresses, which combine with the

normal piping system stresses to

create voids and fissures in the

steel, which ultimately causes the

pipe to rupture (API, 2004).

The American Petroleum Institute

(API) Recommended Practice 941,

Steels in Hydrogen Service at Elevated

Temperatures and Pressures in

Petroleum Refineries and

Petrochemical Plants, recommends

operating limits for carbon steel

and low alloy steel piping systems

in hydrogen service. Experiments

and operating plant data show that

HTHA is typically avoided by

using low alloy steels3 containing

1

 A carbide is a chemical compound

formed between carbon and a metal or

metals (e.g., chromium carbide, iron

carbide).

2

 Ductility is the ability of a metal to

plastically deform without breaking or

fracturing.

3

 Low alloy steels typically contain less

than 0.3% carbon and 2-8% total alloying

elements.

1.25–3.0 percent chrome, as the

chrome combines with carbon to

form chromium carbide, which is

resistant to reacting with hydrogen.

Failed Elbow Metallurgical

Analyses

The elbow segments recovered from

the damaged unit were examined

to identify the steel and the failure

mechanism. Chemical analysis

and microscopic examination

determined that the elbow was

made from carbon steel.

Microscopic examination also

revealed that the segments were

severely decarburized and had

deep fissures on the inside surface

(see Figure 4). The decarburized

steel and severe fissuring

confirmed that HTHA caused the

catastrophic elbow failure.

Detailed metallurgical

examinations and micro-hardness

testing quantified the extent of

hydrogen damage to estimate the

total time the elbow could have

been in the high-temperature, highpressure hydrogen service before it

failed. The results, compared to

existing experimental data and

empirical service life predictions,

concluded that the elbow failed

after being in service for fewer than

3000 hours.4

RHU System Design

Designed in the early 1980s, the

RHU has three parallel operating

systems. Each system contains a

heat exchanger assembly that

consists of two series-connected

heat exchangers to preheat the

hydrogen. For high-temperature

hydrogen gas service piping to

resist HTHA, the piping design

specification requires 1.25%

chrome “low alloy” steel, but for

piping in hydrogen service at low

temperatures, or those below 450oF,

non-HTHA resistant carbon steel is

specified, as using this material

minimizes material cost.5 Because

heat exchanger B inlet piping and

components operate at

temperatures below 450oF, they are

carbon steel; heat exchanger B

outlet and all downstream piping

and components (Figure 5) are

required to be low alloy steel

because they operate at

temperatures above 500oF.

Construction costs may have been

saved by making elbows 1, 2, and 3

on each heat exchanger assembly

dimensionally identical, as doing

so requires fewer pipe assembly

fabrication drawings and weld

joints in each assembly. Because

the elbows are dimensionally

identical, the piping contractor had

to ensure that the low alloy steel

elbows 2 and 3 were installed in

the correct locations when the RHU

was built. Had the elbow 1 design
5

6

 Portable hand-held test devices, such as

an x-ray fluorescence instrument, quickly

distinguish between carbon steel and

alloy steel piping materials without

damaging the test article.

dimensions been different, elbow 1

would not have been

interchangeable with elbow 2 or 3

(see Figure 2).

Because of this component

interchangeability, any heat

exchanger piping disassembly/

reassembly for maintenance or

repair requires the maintenance

crew to be careful to install each

elbow in the correct location.

Because carbon steel and low alloy

steel are visually indistinguishable,

special test equipment6

 is needed

to distinguish the two low alloy

steel elbows from the carbon steel

elbow. Otherwise, to prevent

switching elbow 2 or 3 with

incompatible carbon steel elbow 1,

the crew must clearly label or mark

each elbow before removing them,

then confirm that each has been

reinstalled in the correct location.

The results, compared to

existing experimental data

and empirical service life

predictions, concluded

that the elbow failed after

being in service for fewer

than 3000 hours.

z

Figure 5. RHU hydrogen heat exchanger piping material requirements.
6

RHU Heat Exchanger

Maintenance

The RHU heat exchangers were

placed in service in 1984.

Scheduled heat exchanger cleaning

and inspection were performed in

1989 and 1991. Elbows 1, 2, and 3

were removed from the heat

exchangers, set aside, and then

reinstalled following the

maintenance.

The next scheduled heat exchanger

maintenance overhaul began in

January 2005. The three elbows

were removed, stored temporarily,

and then reinstalled 39 days later.

The maintenance contractor, JV

Industrial Companies, was

unaware of the material differences

in the elbows and BP did not

require the contractor to implement

any special precautions to prevent

inadvertently switching the elbows

or any post-reassembly testing to

confirm the alloy elbows were

reinstalled in the correct locations.

Metallurgical analyses after the

incident concluded that the carbon

steel elbow could withstand the

high-temperature, high-pressure

service for only a few thousand

hours. X-ray fluorescence testing

confirmed that an alloy steel elbow

was installed in the carbon steel

elbow position on the heat exchanger B inlet. Therefore, the CSB

concluded that carbon steel elbow

1 was inadvertently switched with

alloy steel elbow 3 when the

maintenance contractor reassembled the piping during the winter

2005 heat exchanger overhaul.

Alloy Piping Material

Verification

The BP Texas City refinery has a

material verification program, and

PMI test equipment that quickly

differentiates carbon steel from

alloy steel piping components. The

BP procedure requires alloy steel

components to be verified when

they are received in the warehouse

and when alloy steel components

are shipped from the warehouse for

use in new construction. However,

it does not require PMI during

maintenance, even when there is a

risk of inadvertent substitution of

the wrong material with alloy

piping components.

As this incident demonstrated,

merely disassembling and

reassembling piping components

during maintenance can result in

unacceptable system modifications.

Lacking post-installation PMI

testing, or positive identification of

the alloy steel components before

and after installation (e.g.,

component tagging before

disassembly), the maintenance

crew’s reassembly error went

undetected until the pipe failed.

Key Findings

l Piping systems can be designed

such that incompatible

components cannot be

interchanged. All three elbows

could have been made from the

same low alloy steel material,

even though this would have

meant additional material

expense. Alternatively, elbow 1

could have been dimensionally

different from elbow 2 and 3,

although this would have meant

additional construction costs.

z In February 2005, a carbon steel

elbow was installed in the high

temperature, high pressure

hydrogen line instead of the

required 1.25 percent chrome

low alloy steel elbow. HTHA

caused the carbon steel elbow to

rupture after the unit operated

only a few months.

z The BP Texas City refinery

material verification procedure

did not require critical piping

component PMI testing during

equipment maintenance, even

though the incompatible

components could be

inadvertently switched.7 The test

is simple to perform and quickly

differentiates between carbon

steel and alloy steel.

7

 The Mechanical Integrity Quality

Assurance element in the OSHA Process

Safety Management Standard requires

“...appropriate checks and inspections to

assure equipment is installed properly...”

(OSHA, 1992)
7

Lessons Learned

Human Factors Based

Design

Designers should consider the

entire process system life cycle,

including planned maintenance, to

avoid piping configurations that

allow critical alloy piping

components to be interchanged

with non-compatible piping

components.

Positive Material

Verification Programs

In-situ alloy steel material

verification using x-ray

fluorescence, or other nondestructive material testing, is an

accurate, inexpensive, and fast

PMI test method. Facility owners,

operators, and maintenance

contractors should ensure that the

verification program requires PMI

testing, such as specified in API

Recommended Practice 578, or

other suitable verification process,

for all critical service alloy steel

piping components that are

removed and reinstalled during

maintenance.

At a minimum, piping components

and their respective locations

should be tagged or marked before

removal, and the correct installed

location is verified after

reinstallation.

Recommendations

BP Texas City Refinery

2005-04-B-R1

Revise the maintenance quality

control program to require

positive material identification

testing or another suitable

material verification process for

all critical service alloy steel

piping components removed and

reinstalled during maintenance,

and inform work crews of special

material handling precautions.

JV Industrial Companies

2005-04-B-R2

Develop/update the written

piping component installation

quality control procedure to

require positive material

identification testing or other

suitable verification or tracking

process for all alloy steel piping

components removed during

maintenance.

z BP did not alert the maintenance

contractor that two of the three

elbows were alloy steel piping

components and must not be

interchanged with the carbon

steel elbow.

z The maintenance contractor, JV

Industrial Companies, did not

adequately control the

disassembly, storage, and

reassembly of the piping

components to ensure that all

the piping components were

returned to their original

installed locations.

z The maintenance contractor

inadvertently switched carbon

steel elbow 1 (Figures 2 and 5)

with the alloy steel elbow 3

during the January 2005 RHU

heat exchanger overhaul.

As this incident

demonstrated, merely

disassembling and

reassembling piping

components during

maintenance can result in

unacceptable system

modifications.

z

At a minimum, piping

components and their

respective locations should

be tagged or marked . . .

z
8

The U.S. Chemical Safety and Hazard Investigation Board (CSB) is an independent Federal agency whose

mission is to ensure the safety of workers, the public, and the environment by investigating and preventing

chemical incidents. The CSB is a scientific investigative organization; it is not an enforcement or regulatory

body. Established by the Clean Air Act Amendments of 1990, the CSB is responsible for determining the

root and contributing causes of accidents, issuing safety recommendations, studying chemical safety

issues, and evaluating the effectiveness of other government agencies involved in chemical safety.

No part of the conclusions, findings, or recommendations of the CSB relating to any chemical accident may

be admitted as evidence or used in any action or suit for damages. See 42 U.S.C. § 7412(r)(6)(G). The CSB

makes public its actions and decisions through investigation reports, summary reports, safety bulletins,

safety recommendations, case studies, incident digests, special technical publications, and statistical

reviews. More information about the CSB is available at www.csb.gov.

CSB publications can be downloaded at www.csb.gov or obtained by contacting:

U.S. Chemical Safety and Hazard

Investigation Board

Office of Congressional, Public, and Board Affairs

2175 K Street NW, Suite 400

Washington, DC 20037-1848

(202) 261-7600

References

American Petroleum Institute (API),

1999. Material Verification

Program for New and Existing

Alloy Piping Systems,

Recommended Practice 578, May

1999.

API, 2004. Steels for Hydrogen

Service at Elevated Temperatures

and Pressures in Petroleum

Refineries and Petrochemical

Plants, Recommended Practice

941, March 2004.

Oriani, Richard A., John P. Hirth,

and Michael Smialowski, Ed.

1985. Hydrogen Degradation of

Ferrous Alloys, Noyes

Publications, 1985.

U.S. Chemical Safety and Hazard

Investigation Board (USCSB),

2004. Investigation Digest: DPC

Enterprises Chlorine Release.

U.S. Department of Labor,

Occupational Safety and Health

Administration (OSHA), 1992.

Process Safety Management, 29

CFR 1910.119(j)(6)(ii).