Rupture of Enbridge Pipeline and Release of Crude Oil

near Cohasset, Minnesota

July 4, 2002

Pipeline Accident Report

NTSB/PAR-04/01

PB2004-916501

Notation 7514A

National 

Transportation

Safety Board

Washington, D.C.

Pipeline Accident Report

Rupture of Enbridge Pipeline and Release of 

Crude Oil near Cohasset, Minnesota

July 4, 2002

NTSB/PAR-04/01

PB2004-916501 National Transportation Safety Board

Notation 7514A 490 LíEnfant Plaza, S.W.

Adopted June 23, 2004 Washington, D.C. 20594
National Transportation Safety Board. 2004. Rupture of Enbridge Pipeline and Release of Crude Oil

near Cohasset, Minnesota, July 4, 2002. Pipeline Accident Report NTSB/PAR-04/01. Washington, DC.

Abstract: About 2:12 a.m., central daylight time, on July 4, 2002, a 34-inch-diameter steel pipeline owned

and operated by Enbridge Pipelines, LLC ruptured in a marsh west of Cohasset, Minnesota.

Approximately 6,000 barrels (252,000 gallons) of crude oil were released from the pipeline as a result of

the rupture. The cost of the accident was reported to the Research and Special Programs Administration

Office of Pipeline Safety to be approximately $5.6 million. No deaths or injuries resulted from the release. 

The safety issues identified in this accident are the effectiveness and application of line pipe transportation

standards and the adequacy of Federal requirements for pipeline integrity management programs.

As a result of its investigation of this accident, the Safety Board issues safety recommendations to the

Research and Special Programs Administration, the American Society of Mechanical Engineers, and the

American Petroleum Institute.

The National Transportation Safety Board is an independent Federal agency dedicated to promoting aviation, railroad, highway, marine,

pipeline, and hazardous materials safety. Established in 1967, the agency is mandated by Congress through the Independent Safety Board

Act of 1974 to investigate transportation accidents, determine the probable causes of the accidents, issue safety recommendations, study

transportation safety issues, and evaluate the safety effectiveness of government agencies involved in transportation. The Safety Board

makes public its actions and decisions through accident reports, safety studies, special investigation reports, safety recommendations, and

statistical reviews.

Recent publications are available in their entirety on the Web at <http://www.ntsb.gov>. Other information about available publications also

may be obtained from the Web site or by contacting:

National Transportation Safety Board

Public Inquiries Section, RE-51

490 LíEnfant Plaza, S.W.

Washington, D.C. 20594

(800) 877-6799 or (202) 314-6551

Safety Board publications may be purchased, by individual copy or by subscription, from the National Technical Information Service. To

purchase this publication, order report number PB2004-916501 from:

National Technical Information Service

5285 Port Royal Road

Springfield, Virginia 22161

(800) 553-6847 or (703) 605-6000

The Independent Safety Board Act, as codified at 49 U.S.C. Section 1154(b), precludes the admission into evidence or use of Board reports

related to an incident or accident in a civil action for damages resulting from a matter mentioned in the report. 
iii Pipeline Accident Report

Contents

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv

Factual Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Accident Synopsis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Accident Narrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Emergency Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Postaccident Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Tests and Research . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Preaccident Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Fatigue Cracking in Enbridge Pipe Manufactured by U.S. Steel . . . . . . . . . . . . . . . . . . 8

Operational Reliability Assessments of the Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Elastic Wave In-Line Inspection at Rupture Location . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Pipe Movement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Railroad Transportation of Thin-Walled Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Railroad Transportation of Accident Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Safety Board Materials Laboratory Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

RSPA Postaccident Corrective Action Order . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Enbridge Postaccident Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

American Society of Mechanical Engineers Pipeline Codes . . . . . . . . . . . . . . . . . . . . . . . . 23

Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

The Accident . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Transportation of Accident Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Transportation Fatigue Cracking in Line Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Natural Gas Pipeline Safety Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Liquid Pipeline Safety Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Marine Transportation of Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Truck Transportation of Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

ASME Pipeline Codes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Pipeline Integrity Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Probable Cause . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Appendix A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Investigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
iv Pipeline Accident Report

Executive Summary

About 2:12 a.m., central daylight time, on July 4, 2002, a 34-inch-diameter steel

pipeline owned and operated by Enbridge Pipelines, LLC ruptured in a marsh west of

Cohasset, Minnesota. Approximately 6,000 barrels (252,000 gallons) of crude oil were

released from the pipeline as a result of the rupture. The cost of the accident was reported

to the Research and Special Programs Administration Office of Pipeline Safety to be

approximately $5.6 million. No deaths or injuries resulted from the release. 

The National Transportation Safety Board determines that the probable cause of

the July 4, 2002, pipeline rupture near Cohasset, Minnesota, was inadequate loading of the

pipe for transportation that allowed a fatigue crack to initiate along the seam of the

longitudinal weld during transit. After the pipe was installed, the fatigue crack grew with

pressure cycle stresses until the crack reached a critical size and the pipe ruptured.

The following safety issues were identified during this investigation:

ï The effectiveness and application of line pipe transportation standards.

ï The adequacy of Federal requirements for pipeline integrity management

programs.

As a result of its investigation of this accident, the Safety Board issues safety

recommendations to the Research and Special Programs Administration, the American

Society of Mechanical Engineers, and the American Petroleum Institute. 
1 Pipeline Accident Report

Factual Information

Accident Synopsis

About 2:12 a.m., central daylight time, on July 4, 2002, a 34-inch-diameter steel

pipeline owned and operated by Enbridge Pipelines (Lakehead), LLC1

 ruptured in a marsh

west of Cohasset, Minnesota. (See figure 1.) Approximately 6,000 barrels (252,000

gallons) of crude oil were released from the pipeline as a result of the rupture. No deaths

or injuries resulted from the release. 

Accident Narrative

The crude oil pipeline involved in the accident originated at Edmonton, Alberta,

Canada, and terminated at Superior Terminal in Superior, Wisconsin. The 34-inchdiameter pipeline, designated line no. 4 at the time of the accident, was operated by

pipeline controllers in the Enbridge control center in Edmonton using a supervisory

control and data acquisition (SCADA) system.2 About 2:12 a.m. on July 4, 2002, the

1 Enbridge Pipelines (Lakehead), LLC is the operator of the pipeline system formerly named Lakehead

Pipe Line Company. 

Figure 1. Enbridge pipeline system.

2 Pipeline controllers use a computer-based SCADA system to remotely monitor and control

movement of oil through pipelines. The system makes it possible to monitor operating parameters critical to

pipeline operations, such as flow rates, pressures, equipment status, control valve positions, and alarms

indicating abnormal conditions.
Factual Information 2 Pipeline Accident Report

controller operating the line observed a SCADA system indication of a loss of suction and

discharge pressure at the Deer River pump station. (See figure 2.) At 2:13 a.m., the

Floodwood pump station suction pressures began dropping, and then audible and visual

alarms were received for an invalid suction pressure. The controller initially suspected an

inaccurate pressure transmitter at Floodwood, because the suction pressure had gone to

zero. Subsequently, he noticed that the discharge pressure for Floodwood was also

dropping and realized that he had an abnormal condition. The controller showed the shift

coordinator the situation, and, suspecting a possible leak, they agreed at 2:14 a.m. to shut

the pipeline down. At 2:15: a.m., the controller initiated closure of the pipeline injection

valve at the Clearbrook Terminal and began shutting down pumps and remotely closed

valves to isolate the suspected leak. The upstream valve at Deer River and the downstream

sectionalizing valve at milepost (MP) 1017.9 were remotely closed by 2:21 a.m., which

isolated the ruptured section. All remotely controlled valves on the pipeline from

Clearbrook to Superior Terminal were closed by 2:32 a.m.

About 2:25 a.m., the Enbridge control center notified the Deer River and

Floodwood police departments of the suspected leak, and about 2:30 a.m., Enbridge field

personnel were notified. About 5:20 a.m., Enbridge field personnel dispatched to

investigate along the pipeline right-of-way detected the odor of crude oil in a marshy area

near Blackwater Creek and manually closed the closest valve to the failure. This valve was

near MP 1007.32, about 4 1/2 miles downstream (east) of the rupture.

Figure 2. Enbridge pipeline facilities and rupture site.
Factual Information 3 Pipeline Accident Report

At 7:00 a.m., after Enbridge field employees verified the release, Enbridge notified

the National Response Center of a crude oil leak in the companyís 34-inch pipeline. This

notification indicated that an unknown amount of crude oil had been released. The pipe

was found to have ruptured at MP 1002.73, about 7 miles downstream of the Deer River

pump station. The company then contacted local, State, and Federal officials, as well as

Enbridge spill response contractors, who proceeded to the spill site. Enbridge also had

right-of-way representatives contact landowners in the vicinity of the spill. At 12:09 p.m.,

Enbridge called the National Response Center again and updated the spill volume to 6,000

barrels of crude oil. At the time of the accident, Enbridge had not designated the area

where the rupture occurred as a high-consequence area3 based on the criteria defined in 49

Code of Federal Regulations (CFR) Part 195, ìTransportation of Hazardous Liquids by

Pipelines.î

Emergency Response

Booms were placed in Blackwater Creek as a precaution to prevent crude oil from

moving away from the spill site toward nearby waterways, including the Mississippi

River. Enbridge started building a 1/4-mile-long road along the right-of-way to the spill

site using wood mats. With heavy rain forecast, responders were concerned that the crude

oil might spread farther and contaminate the Mississippi River. The unified command for

the accident response was established and included the Cohasset Fire Department,

Enbridge, the Minnesota Pollution Control Agency, the Minnesota Department of

Emergency Management, and the Forestry Division of the Minnesota Department of

Natural Resources. 

The unified command decided that the best way to prevent the crude from entering

nearby waterways was to perform a controlled burn. As a precaution, the command

designated 12 homes in the local area to be evacuated, and seven residents were

evacuated. Later in the afternoon, the Minnesota Department of Natural Resources coated

the spillís perimeter with chemical fire retardant from tanker planes. After the chemical

was placed, flares were shot into the crude oil to ignite the oil. 

The controlled burn was ignited about 4:45 p.m. (See figure 3.) The burn created a

smoke plume about 1 mile high and 5 miles long. (See figure 4.) The controlled burn

lasted until about 5:00 p.m. the next day, July 5. While they monitored the fire, Enbridge

personnel, firefighters, and environment authorities also monitored the spill perimeter to

ensure that no crude was getting into area waterways. Reportedly, no free-flowing product

reached any of the boomed areas. 

3 High-consequence area refers to commercially navigable waterways, high population areas,

concentrated population areas, or unusually sensitive areas that might be affected by an accident involving

the pipeline in that area. Title 49 CFR 195.450, 195.452, and 195.6 contain the criteria for designating an

area a high-consequence area for hazardous liquid pipelines.
Factual Information 4 Pipeline Accident Report

Figure 3. Controlled burn surrounded by white fire retardant.

Figure 4. Smoke plume 1 mile high and 5 miles long.
Factual Information 5 Pipeline Accident Report

Damage

The cost of the accident was reported to the Research and Special Programs

Administration (RSPA) Office of Pipeline Safety to be approximately $5.6 million.4

Enbridge recovered 2,574 barrels of oil and estimated that the in situ burn consumed

approximately 3,000 barrels, with the remainder being lost to evaporation or entrapment

in the soil.

Postaccident Inspection

On July 6, after vacuum trucks had removed the remaining oil and water, the

ruptured pipe was exposed. The pipe was fractured along the edge of a longitudinal weld.

When the pipe that failed was installed, the longitudinal weld was at the 5:30 clock

position when viewed facing downstream (eastward). The rupture was about 69 inches

long and gapped open about 6 1/4 inches at the center. (See figure 5.) At the rupture

location, the pipeline was rated for a regulatory maximum operating pressure of 687

pounds per square inch, gauge (psig). The pressure at this location at the time of failure

was calculated to be 526 psig. The United States Steel Corporation (U.S. Steel)

manufactured the pipe at its National Tube Works in McKeesport, Pennsylvania.

4 This total includes estimated property damage, including cost of cleanup and recovery, value of lost

product, and damage to the property of the pipeline operator and others.

Figure 5. Rupture in accident pipe.
Factual Information 6 Pipeline Accident Report

Tests and Research

Two sections of pipe, one containing the rupture and one from the same length of

pipe, were removed and sent to the Safety Boardís Materials Laboratory for metallurgical

examination. The pipe that ruptured was manufactured in accordance with American

Petroleum Institute (API) standard 5L, grade X52, indicating that the steel had a specified

minimum yield strength5 of 52,000 pounds per square inch (psi). The 34-inch outside

diameter pipe was specified as 0.312-inch nominal wall thickness with a double

submerged arc weld (DSAW) longitudinal seam weld. The pipe had a diameter-to-wall

thickness (D/t) ratio of 109:1. The pipe was coated with a spiral wrap tape that was applied

in the field during construction in 1967. 

Surface corrosion was visible on the outer surface of the pipe adjacent to the

rupture, but no dents, scratches, or gouges were present at any location on the pipe

sections examined. The corrosion was assessed as light, with no apparent pitting and little

apparent loss of wall thickness. Both pipe sections were ultrasonically inspected for cracks

along the longitudinal seam weld, and, other than the rupture that caused the accident, no

additional cracks or discontinuities were uncovered. Fatigue cracking6

 has been shown to

initiate at seam welds because of changes in geometry, residual stress, and material

properties associated with the weld. Metallurgical testing and examination of the ruptured

area found no material or manufacturing defect in the steel or the welded seam of the pipe.

Initial examination of the rupture revealed a preexisting fatigue region at the center

of the rupture. The fatigue region was 13 inches long adjacent to the inside surface of the

pipe and did not extend all the way through the pipe wall. (See figure 6.) More detailed

examination showed that the fatigue cracking initiated at multiple locations along the

inside surface (see figure 7) at the toe of the longitudinal weld bead. (See figure 8.)

Examination of the cleaned fracture surface revealed a darker, more heavily oxidized band

adjacent to the inside surface of the pipe that extended the entire length of the fatigue area.

The more heavily oxidized portion of the fatigue area penetrated a maximum of about 0.04

inch deep at the center of the rupture. The oxidized band was visible for almost the entire

length of the fatigue area. Near its ends, the oxidized portion of the fatigue crack extended

about 0.010 inch into the pipe wall. The remainder of the fatigue crack was less oxidized

and extended more deeply into the pipe wall over the central 6 inches of the fatigue

region. Along approximately 2.5 inches in the central region, the fatigue crack almost

penetrated the pipe wall. At its maximum depth, the fatigue crack penetrated through 0.270 

5 Yield strength is a measure of the pipeís material strength and is the stress level, expressed in pounds

per square inch, at which the material starts to exhibit permanent deformation. Although yield strength is

expressed in pounds per square inch, this value is an expression of a pipe materialís strength, which is not

equivalent to a pipeís internal pressure.

6 The term fatigue cracking is used to describe a progressive cracking of structural material that occurs

under repeated loading and may eventually lead to failure. The fatigue crack grows with cyclic loading until

the crack reaches a critical length at which the stresses cause it to grow unstably leading to structural failure.

Fatigue cracks can initiate at microscopic flaws or weak spots in the material. Once initiated, cracks can

grow at stress levels that are quite low in comparison to the materialís yield strength.
Factual Information 7 Pipeline Accident Report

inch of the 0.297-inch measured wall thickness.7 Measurement and testing of the pipe

showed that it met thickness and strength requirements. The pipe fracture beyond the

fatigue crack contained features typical of overstress fracture.

7 The 0.297-inch measured wall thickness is within the allowable range for a pipe with 0.312-inch

specified nominal wall thickness.

Figure 6. View of top fracture surface of 13-inch-long crack, showing penetration nearly 

through pipe wall in center.

Figure 7. Face of fracture in accident pipe.
Factual Information 8 Pipeline Accident Report

Preaccident Events

Fatigue Cracking in Enbridge Pipe Manufactured by U.S. Steel

Enbridgeís 34-inch U.S. Steel DSAW pipe had a documented history of

longitudinal seam weld failures due to fatigue cracks. Metallurgical analysis reports of

longitudinal seam weld failures in Enbridgeís U.S. Steel pipe in 1974, 1979, 1982, 1986,

1989, and 1991 identified the causes as fatigue cracking at the toe of the weld. Enbridgeís

34-inch pipeline system also used A.O. Smith flash-welded pipe, Canadian Phoenix

electric resistance welded pipe, and Kaiser Steel submerged arc welded (SAW) pipe. All

of the longitudinal seam weld failures caused by fatigue cracks in this pipeline have

occurred in pipe manufactured by U.S. Steel.

Operational Reliability Assessments of the Pipeline

After the 1991 pipe rupture at the toe of the weld in the 34-inch pipeline resulted in

the release of 40,500 barrels (1,701,000 gallons) of crude oil, Enbridge signed a consent

order with RSPAís Office of Pipeline Safety to conduct an operational reliability

assessment of the 34-inch pipeline from Gretna, Manitoba, Canada, to Superior,

Wisconsin. The assessment was to include a review of pipeline operating conditions and

an analysis of the previous pipe failures. The operator was also required to restrict

Figure 8. Fatigue initiating at toe of weld on interior surface of pipe.
Factual Information 9 Pipeline Accident Report

allowable operating pressures, to hydrostatically pressure test8 the pipeline to establish

that the line was safe to operate, and to develop a program to ensure that the line would

continue to be safe in the future.

In December 1992, Enbridge performed an operational reliability assessment9 of

the 34-inch pipeline in the United States. As a result of the study, changes were made in

pipeline operations that reduced the number of pressure cycles10 and their associated

pressure ranges. Among other actions it took as a result of the 1991 rupture, Enbridge

financially and technically supported British Gasís development of the Elastic Wave inline inspection tool to identify pipe cracks before they precipitate a failure. British Gas did

the inspections in 1995 and 1996. PII North American, Inc. (PII), the successor to British

Gas, currently provides the inspection tool data report of the Elastic Wave inspection tool

in the United States. 

The pipeline section in which the 2002 rupture occurred was pressure tested to 835

psig after its construction in 1967. Enbridgeís first longitudinal seam weld in-service

failure of U.S. Steel pipe from a fatigue crack occurred in July 1974. The entire pipeline,

including the pipe joint11 containing the failure, was pressure tested between 1974 and

1976 at a test pressure of 764 psig. The entire 34-inch pipeline was pressure tested in 1991

and 1992 at higher stress levels than had been used before. Because of variations in pipe

wall thickness and changes in elevation in each section of the pipeline, the test pressure

range was from 85 percent to 105 percent of the specified minimum yield strength of the

pipe, or up to 1,002 psig.12 The 1991 test pressure at the point of the July 4, 2002, rupture

was 937 psig. The operator agreed in 1991 to pressure test the pipeline again in 5 years

unless an in-line inspection tool capable of identifying cracks in the longitudinal seam of

the pipe was developed. RSPA did not allow the operator to raise the pressures above

those in effect at the time of the 1991 accident while the consent order was in effect.

During the 1991 and 1992 pressure testing program, Enbridge found four cracklike/manufacturing defects, four corrosion defects, and one blister. Two subsequent leaks

occurred that resulted from pressure-cycle-induced growth of fatigue cracks in U.S. Steel

pipe. The two in-service leaks occurred in the first 6 months of 1994 at the site of fatigue

cracks that had survived the pressure test levels of the 1991ñ1992 program. A reassessment

report was completed in December 1994 following those two failures. Enbridgeís

metallurgical report indicated that the initiating fatigue cracks were readily apparent

adjacent to the inside pipe wall and had been introduced during the transportation of the

pipe, as they were smoother and darker than subsequent fatigue crack growth. The report

8 A hydrostatic test of a pipeline involves filling the pipeline with water or similar liquid, gradually

increasing the pressure of the liquid to a predetermined maximum, and examining the line and/or test

records for indications of a leak. 

9 The 1992 assessment was updated in 1994, 1995, and 1998.

10 One pipeline pressure cycle is the pressure variation from a minimum to a maximum pressure and to

the minimum again.

11 A joint is a single length of pipe, nominally 40 feet long.

12 Using the internal design strength formula in 49 CFR Part 195, a test pressure of 954 psig is calculated

at 100 percent of specified minimum yield strength for line pipe with the specification of the pipe that ruptured.
Factual Information 10 Pipeline Accident Report

noted that both defects at the point of failure showed evidence of having grown during the

1991ñ1992 pressure tests and concluded that ductile tearing of the metal caused the growth

of these existing defects. Another Enbridge conclusion was that the operating histories of

the upstream operating stations showed that pressure cycles also contributed to the failures. 

After Enbridge ran tests with the Elastic Wave inspection tool, the results were

reviewed and recommendations were included in Enbridgeís 1995 integrity assessment

report. As a result of the recommendations, Enbridge proposed to RSPA an in-line crack

inspection program as the most appropriate means of reducing or eliminating the risk of

pipeline failures. The detection level specification for the Elastic Wave tool stated that the

tool would find a defect equal to or greater than 2.5 inches long with an accuracy of ±0.4

inch at 4.5 mph. The detection level specification for crack depth was 25 percent of the

pipe wall thickness with a sizing accuracy of ±25 percent of the wall thickness. For an

indication to be reported to the operator as a defect, both the crack length and the crack

depth threshold requirements had to be met.

RSPA agreed in 1995 to the use of the in-line crack inspection program in lieu of

hydrostatic pressure testing. As a condition for accepting the proposal for 1996, RSPA

stipulated that it would review the inspection program before deciding on future pressure

testing. One of the reasons for conditional approval in RSPAís stipulations was that RSPA

wanted to know whether the Elastic Wave inspection tool would identify not only pipe

crack defects that would fail during hydrostatic pressure testing but also considerably

smaller defects that could then be repaired or removed before they could grow and lead to

failure of the pipe.

In 1995, Enbridge began inspecting its 34-inch pipeline with the Elastic Wave inline inspection tool and found that the tool was identifying more pipe crack defects than

had been identified by previous hydrostatic pressure testing. Twice during 1995 and again

in early 1996, PIIís tool was used to inspect the pipeline section that contained the crack

that ruptured in this accident, but various mechanical problems with the inspection tool

resulted in unusable data. PII acquired usable data in a May 1996 inspection. (The details

of this inspection are discussed later in this report.)

In the 4 years from 1995 through 1998, 216 miles (66 percent) of the 325 miles of

34-inch pipe from Gretna, Manitoba, to Superior, Wisconsin, had been inspected with the

Elastic Wave tool, and pipeline repairs were made according to the pipeline operatorís

policy. All crack defects identified by the inspections were repaired with pipe sleeves, and

none were removed and subjected to metallurgical examination. During this period of

time, in-line inspections were performed on all U.S. Steel manufactured DSAW pipe. As a

result of these inspections, the operator excavated the pipe at 74 locations. An evaluation

concluded that none of the defects found with the Elastic Wave tool would have failed a

pressure test to 100 percent specified minimum yield strength. Following completion of

the Elastic Wave tool inspections in the 34-inch U.S. Steel pipe, Enbridge submitted an

assessment report dated April 28, 1998, that proposed reinspecting the pipeline

approximately 10 years from the previous inspection. A number of reviews were made by

RSPA before closure of the consent order on May 5, 1999. After the consent order was

closed, Enbridge operated the pipeline up to the pressures allowed by 49 CFR Part 195.
Factual Information 11 Pipeline Accident Report

Before the accident, Enbridgeís unwritten defect inspection practice for Elastic

Wave data was to excavate all crack-like indications that were found by the Elastic Wave

tool. Enbridge ran Elastic Wave tool inspections in all of its 34-inch pipeline sections in

the United States between 1995 and 2001. Based on the results of these inspections, the

company excavated 23 crack-like features; 23 weld/manufacturing defects; 16 other

defects, including corrosion and laminations; and 41 spurious13 indications and made

repairs where needed.

Elastic Wave In-Line Inspection at Rupture Location

The in-line inspection company, PII, performed a computer analysis of the May

1996 Elastic Wave inspection tool log data as part of its interpretation process after the

tool was run. An indication was present at the point where the pipe ruptured on

July 4, 2002. PII interpreters reviewed the indication in their initial screening of the data

in 1996, but the indication did not exhibit the diamond-shaped signature signifying a crack

and did not meet PIIís standard that an anomaly must meet at least 6 of 10 feature

selection criteria in order to be identified as a crack. After the accident, PII stated that, at

most, the indication would have met two of the feature selection criteria. An important

feature selection criterion that the indication did not meet was confirmation of the signal

from both the clockwise and counterclockwise views as the tool records data while

moving downstream through the pipe. PII representatives stated that during the May 1996

inspection run, one of the toolís two sets of wheel sensors was close to the longitudinal

weld, which placed the weld in proximity to the source of the toolís ultrasonic signal and

could have resulted in the masking of the signal. 

PIIís postaccident review of the May 1996 data also evaluated the size of the

indication at the rupture and determined that it was below the detection level specification

for a reportable defect (25 percent of pipe wall thickness and 2.5 inches long). The data on

this indication have been recorded in a database, and PII and Enbridge have worked to

determine how this information will be used to improve the feature selection criteria. Also

after the accident, RSPA had an independent consultant and PII analyze the May 1996

inspection log data for the area from 0.5 mile upstream to 0.5 mile downstream of the

rupture location. No indications were found with characteristics similar to those of the

July 4, 2002, rupture.

In addition, PII personnel reviewed the log data from two 1995 Elastic Wave tool

inspections that had shown no significant defect at the point of the 2002 rupture. They found

that on the first run, the clockwise sensor was functioning properly and was not on the

longitudinal weld at the point that ruptured. The counterclockwise channel was working but

was electronically noisy and provided a weak signal at the point that ruptured. Thus the

signal on this run did not meet feature selection criteria for confirmation of the signal from

both the clockwise and counterclockwise views. The signal on this run also did not exhibit

the diamond-shaped crack signature. On the second 1995 log, the clockwise channel was not

providing acceptable quality data when it was in the area of the point of rupture.

13 Spurious features were those that did not have a corresponding defect associated with them, had

qualities not considered a defect (for example, weld profile), or were under sleeves and could not be assessed.
Factual Information 12 Pipeline Accident Report

All of the 1995ñ1996 in-line Elastic Wave tool inspections were performed by the

Mark II version of the device. In 1997 the tool was upgraded to the Interim Mark III,

which contains an additional set of wheel sensors that are offset so at least one set of

sensors is not riding on the longitudinal seam weld.

Both before and after the accident, Enbridge provided PII with feedback on its

findings from actual excavations and field inspections. This feedback is a part of the

continuing development effort on Elastic Wave technology. PII advised the Safety Board

that it always requests feedback from its customers on field excavation data to improve

accuracy and reliability. However, the amount and quality of feedback for in-line

inspection tools varies with each pipeline company.

Pipe Movement

On February 5, 2002, Enbridge detected movement in the 34-inch pipeline in the

same marsh where the subsequent July 4 failure occurred. The movement occurred as

Enbridge was excavating a ditch for the construction of a parallel 36-inch-diameter

pipeline. At this point, the existing and new lines were separated by about 20 feet. As the

ditch for the new line was being opened, the peat began to settle down toward the ditch,

and the existing 34-inch pipeline began to move laterally toward the ditch. Enbridge

workers saw the movement of the line and had the pipeline shut down for evaluation.

The pipeline was found to have moved down and laterally a maximum of 18

inches. The maximum movement had occurred at MP 1002.8 and involved more than 750

feet of pipeline. Enbridge stated that it had calculated the stresses in the pipe caused by the

movement and found them to be well within the parameters for movement of an in-service

pipeline as specified in API recommended practice RP 1117, Movement of In-Service

Pipelines. Enbridge continued to monitor the site after the construction of the parallel

pipeline and observed that the 34-inch pipeline had returned to within 6 inches of its

original position. The return toward the original position was believed to have been caused

by the rehydration of the peat.

Railroad Transportation of Thin-Walled Pipe 

A 1962 technical paper14 prepared from research by Battelle Memorial Institute

discusses the prevention of pipe stresses that can occur during the transportation,

handling, and laying of thin-walled pipe. As noted in the paper, advances in technology

and the availability of higher strength materials have led to the widespread use of thinner

walled, larger diameter pipe that is more susceptible than thicker walled, smaller diameter

pipe to stresses that could be introduced during transportation. The paper states: 

14 Atterbury, A. T., ìStresses During Shipping, Handling and Laying Thin Walled Pipe,î Pipe Line

News, December 1962, pp. 44ñ47.
Factual Information 13 Pipeline Accident Report

Damage to line pipe during shipment has been confined to a very small number of

pipe shipped. This damage has mostly taken the form of local abrasions and dents

caused by contact with rivet heads or other protrusions in the rail car or truck. In a

few instances, however, leaks have been attributed to fatigue cracks initiated due

to cyclic stresses that are induced during shipment. It is possible for these cracks

to initiate with no noticeable surface damage to identify them.

The paper goes on to say:

The stresses developed during shipment (usually most severe during rail

shipments because of higher stacks and higher g-loadings) depend on the

diameter, thickness, loading configuration, and number of bearing strips. The

potential damage done, of course, depends on the number of cycles of stress

which are imposed during shipment.

In January 1965, the API addressed the prevention of fatigue cracks initiating

during railroad transportation of pipe by publishing a recommended practice, API RP 5L1,

Railroad Transportation of Line Pipe. API RP 5L1, which applied to 24-inch- to 42-inchdiameter pipe, included recommendations on the design of bearing strips, banding,

separator strips, and longitudinal weld placement during pipe loading. The weld was to be

placed at the point of least stress during loading, approximately 45° from the vertical

(clock positions 1:30, 4:30, 7:30, or 10:30) and not in contact with adjacent pipes.

Subsequently, APIís April 1972 revision of RP 5L1 expanded the applicability of the

recommended practice to include a range of diameters, 2 3/8 inches and larger, and

specified that it applied to pipe having a D/t ratio of 70:1 and larger. 

The hazardous liquids pipeline safety regulations in 49 CFR Part 195 do not

contain requirements that address railroad transportation or any transportation of pipe. The

natural gas pipeline safety regulation contained in 49 CFR 192.65, ìTransportation of

Pipe,î which became effective on November 12, 1970, states:

In a pipeline to be operated at a hoop stress of 20 percent or more of the specified

minimum yield strength, no operator may use pipe having an outside diameter-towall thickness ratio of 70 to one, or more, that is transported by railroad unless the

transportation was performed in accordance with API RP 5L1.

When the natural gas pipeline safety regulations became effective, pipeline

operators were prohibited from using an estimated $13 million of stockpiled pipe because

operators were unable to verify that the pipe, which had been transported by railroad, was

transported in accordance with API RP 5L1. On February 14, 1973, RSPA amended

section 192.65 of the natural gas pipeline safety regulations with paragraph (b) of the

regulation, which allowed pipe meeting the above criteria that was transported before

November 12, 1970, to be installed in pipelines if the pipe was pressure tested to certain

requirements detailed in the section.

Colonial Pipeline Company also has experienced ruptures in its 32- and 36-inch

liquid pipelines that its metallurgical report attributed to fatigue cracking in U.S. Steel

manufactured pipe. Two Colonial 36-inch (D/t ratio 128:1) pipeline fatigue crack ruptures
Factual Information 14 Pipeline Accident Report

in U.S. Steel pipe transported by railroad occurred in Greenville County near Spartanburg,

South Carolina, on May 13, 1979, and June 16, 1979. The May rupture released 136,000

gallons of fuel oil that damaged vegetation and killed fish. The June rupture released

395,000 gallons of fuel oil that damaged vegetation and killed wildlife and fish.

In 1980, the Safety Board investigated an accident involving a 32-inch-diameter

U.S. Steel pipe (D/t ratio 114:1) in a Colonial Pipeline Company pipeline near Manassas,

Virginia, in which 92,000 gallons of fuel oil leaked from a fatigue crack that was initiated

during rail shipment of the pipe.15 The rupture damaged vegetation and killed

approximately 5,000 fish and some waterfowl and small animals. At the time, hydrostatic

pressure testing was the only method available for finding crack defects; however, the

accident report noted that hydrostatic pressure testing is inadequate because the test itself

may cause small cracks to propagate without causing them to fail during the test.

As a result of its investigations of the 1980 accident, the Safety Board issued

Safety Recommendations P-81-13 and P-81-14 to RSPA:

P-81-13

Expedite, in cooperation with the American Petroleum Institute and the

American Gas Association, the jointly sponsored program to determine the

extent of pipe failures in existing pipeline systems with a diameter-tothickness ratio of 70 or greater due to fatigue cracks initiated during the rail

shipment of the pipe.

P-81-14

If it is determined that pipe failures in existing pipeline systems with a

diameter-to-thickness ratio of 70 or greater due to fatigue cracks initiated

during the rail shipment of the pipe are a continuing problem, develop

operating and testing guidelines to assist pipeline operators in minimizing

pipe failures.

RSPA responded that the Materials Transportation Board had reviewed the extent

and seriousness of a series of pipeline failures due to fatigue cracking that developed

during rail transportation. As a result of the review, seven failures were found that were

attributable to fatigue cracking due to railroad transportation. RSPA responded that it

considered this a limited problem that did not require regulatory action at that time but that

the agency would continue to monitor failures for any indications of future problems.

Safety Recommendation P-81-13 was classified ìClosedñAcceptable Actionî on February

23, 1982. Safety Recommendation P-81-14 was classified ìClosedñNo Longer

Applicableî on March 21, 1983.

15 National Transportation Safety Board, Colonial Pipeline Company Petroleum Products Pipeline

Failures, Manassas and Locust Grove, Virginia, March 6, 1980, Pipeline Accident Report NTSB/PAR-81/2

(Washington, DC: NTSB, 1981).
Factual Information 15 Pipeline Accident Report

On December 18, 1989, another fatigue crack failure occurred on Colonialís 32-

inch pipeline in U.S. Steel pipe. As a result of the 1989 failure, RSPAís Office of Pipeline

Safety created a task force to study Colonial pipeline failures attributable to fatigue

cracking. U.S. Steel, Kaiser Steel, A.O. Smith, Bethlehem Steel, and Republic Steel

manufactured the pipe involved in the study, and the pipelines were constructed between

1962 and 1964. Of these manufacturersí pipes, all had a submerged arc weld in the

longitudinal seam except the A.O. Smith pipe, which had a flash-welded longitudinal

welded seam. The RSPA task force concluded in its September 14, 1990, report that six

Colonial pipeline failures from 1970 through 1989 resulted from fatigue cracking that was

probably initiated during rail transportation of the pipe. The task force report stated that

five fatigue crack failures were found in U.S. Steel pipe and that one was found in

Republic Steel pipe. The report stated that crack growth by fatigue is a greater possibility

in liquid lines than in gas lines because liquid lines are subjected to frequent and

substantial cycles of pressure variations during normal operations. 

The RSPA task force report describes the loading method tests that Battelle

Laboratories conducted in 1962 under contract from Colonial Pipeline Company. Battelle

reported that the susceptibility to fatigue cracking during rail transportation increases for

pipe with larger D/t ratios because such pipe is more susceptible both to static stresses

from the weight of the pipe and to cyclic stresses during transportation. RSPAís report also

noted that the American Gas Association conducted research to develop solutions to

transportation fatigue and found that the higher the D/t ratios, the more susceptible the

pipe to fatigue crack initiation. The American Gas Association research concluded that

pipe with a D/t ratio greater than 70:1 has a possibility of fatigue crack initiation and

requires special care in railcar loading. RSPAís 1990 task force report stated that with the

implementation of API RP 5L1 in 1965, the occurrence of railroad transportation cracks

had been virtually eliminated.

A 1988 paper16 documented numerous transit fatigue crack failures that occurred

during initial hydrostatic pressure testing of the pipe. The types of pipe included DSAW,

electric resistance weld, and seamless steel pipe that had been shipped by rail or marine

vessels. In nine fatigue failures that occurred between 1969 and 1982, the pipe had been

transported by railroad and the diameters ranged from nominal 6-inch to 20-inch pipe with

D/t ratios from 42:1 to 64:1. In 17 fatigue failures that occurred between 1976 and 1987,

the pipe had been transported by marine vessel and ranged from 6 inches to 24 inches in

diameter with D/t ratios from 28:1 to 85:1. The paper stated:

Transit fatigue results from cyclic stresses induced by gravitational and inertial

forces. The weight of a load of pipe imposes a steady stress of a given magnitude.

As the load moves up and down, the pipe flexes, inducing alternating tension and

compression at both the inside and outside surfaces. The alternating stresses

initiate cracks.

16 Bruno, T.V., ìTransit Fatigue of Tubular Goods,î Pipe Line Industry, July 1988, pp. 31ñ34. (This

paper is also referenced in the foreword of the sixth edition of API RP 5L1, July 2002.)
Factual Information 16 Pipeline Accident Report

The D/t ratios that could lead to fatigue cracking during transportation were

changed in the 1990 edition of API RP 5L1. The ratio was reduced from 70:1 to 50:1

because fatigue cracking had been reported in pipe with D/t ratios lower than 70:1. The

latest edition of API RP 5L1, issued in July 2002, also states that pipe with D/t ratios well

below 50:1 may suffer fatigue in transit under some circumstances.

No statistics on transportation damage were specifically tracked before RSPA

instituted a change in 2002 to gather more detailed accident statistics. However, RSPA is

now gathering information on whether an accident is caused by pipe damage sustained

during transportation and whether the failure is a longitudinal tear or crack.

Railroad Transportation of Accident Pipe

The section of pipeline where the rupture occurred was constructed in 1967. The

Enbridge 1966 purchase specification for the pipe included a requirement that pipe

loading details be provided subject to its approval. In its quotation, U.S. Steel provided a

diagram for railroad car loading (see figure 9), which Enbridge subsequently approved.

The railcar loading instructions consisted of a drawing with notes specifying the blocking

supports and banding to be used under and around the pipe and the required positioning of

the longitudinal weld. U.S. Steel also noted in its specifications that the purchaser would

spot-check railcar loadings at the mill before transportation. U.S. Steel transported the

pipe by railcar to its storage facility near the mill, where it was unloaded and stored. Later,

U.S. Steel loaded the pipe for transportation by rail. Finally, the pipe was loaded on trucks

for transportation to the construction sites.17 Enbridge had arranged with Moody

Engineering Company (Moody) to inspect the manufacturing of the pipe. The handling

and loading of the pipe for transportation from the mill to storage was a part of that

inspection. These activities were summarized in Moodyís final report. The Moody report

indicates that the pipe was periodically inspected at a nearby storage facility to ensure that

the pipe was being handled and unloaded with care. The report indicates that the pipe was

accepted for shipment subject to the operatorís shipping instructions. U.S. Steel did not

document inspections of pipe loading. No records were found to indicate that the

engineering company or the pipeline operator inspected the loading of the pipe on railroad

cars for transportation from the U.S. Steel storage facility.

17 Records related to the production activities at U.S. Steelís McKeesport pipe mill were destroyed

several years ago after the mill was closed for a period of time.
Factual Information 17 Pipeline Accident Report

The U.S. Steel employees who had loaded the 1966 DSAW pipe order could no

longer be found. According to a former shipping department employee (who was not

present at the time of the Enbridge pipe loading), a typical pipe loading practice before

and after this pipe order was to position the longitudinal weld at the 2, 4, 8, or 10 oíclock

position so the pipe weld would not touch lumber, bands, or other pipe. If a 40-foot joint

Figure 9. U.S. Steel loading diagram for railcars.
Factual Information 18 Pipeline Accident Report

of pipe was not loaded in this position, it was to be rotated as necessary to attain one of

these positions. Except for the loading diagram, there were no written procedures for

loading pipe, nor did U.S. Steel use checklists or other methods to confirm that the pipe

was loaded according to specifications.

U.S. Steel does not currently manufacture DSAW or SAW pipe. U.S. Steel Tubular

Products does produce seamless and electric resistance weld pipe, and the current loading

procedures for the pipe are described in the companyís Pack, Mark, and Load Manual.

The procedures to be used for each order are entered into the order entry system from the

purchase order and are designated on the mill order sent to the production mill. All pipe

manufactured to API standards and destined for railroad transportation from the pipe mill

is to be loaded to the requirements of the Association of American Railroadsí Open Top

Loading Rules Manual18 and the supplementary recommended practices in API RP 5L1.

Any additional transportation requirements are referenced in the mill order for the

shipping department personnel and, if applicable, are attached to the mill order. A

preproduction meeting is held at the mill to review the order and shipment requirements.

At pipe mills currently producing tubular products for U.S. Steel, shipping

department workers are trained in the departmentís standard operating procedures. The

group leader in the loading area discusses the loading requirements for each order with the

crew. A load tally sheet is created that shows the length of each pipe joint with the

referenced heat number for the material. The yard foreman checks the railcars periodically

to confirm that the pipe is loaded according to the written requirements. 

Before 1991, Enbridge specified that the manner of loading pipe for rail

transportation should be provided in the pipe manufacturerís quotation, which was subject

to Enbridgeís approval. Currently Enbridge includes the use of API RP 5L1 in its

specification for purchase of pipe transported by rail from a pipe mill. Enbridge also

inspects the pipe during loading at the pipe mill to confirm that the requirements of API

RP 5L1 are being met.

Safety Board Materials Laboratory Study

The Safety Board performed a finite element study of the U.S. Steel loading

practice to determine the static stresses in pipe loaded for rail transportation. The study

showed that the peak circumferential tensile stresses would have been highly localized to

the areas in contact with the bearing and separator strips and that the stresses would have

occurred at the inner surface of the pipe.

The length of the fatigue crack in this accident was similar to the length over

which the peak circumferential tensile stress was predicted in the finite element model,

and the fatigue crack initiated at the inner surface of the pipe. The finite element model

18 The Association of American Railroadsí Open Top Loading Rules Manual includes Section 1,

General Rules Manual for Loading all Commodities, and Section 2, Loading Metal Products Including Pipe.
Factual Information 19 Pipeline Accident Report

indicated that the circumferential tensile stresses decreased rapidly away from the bearing

or separator strips. Aligning the welded seams at 45° to the vertical results in very small

levels of circumferential tensile stress at the welds during transport. (See figure 10.) The

results of the finite element model also indicate that aligning the welds at the 2, 4, 8, or 10

oíclock positions instead of exactly 45° from vertical does not increase the stress levels

significantly.

Figure 10. Typical pipe configuration on railroad car.
Factual Information 20 Pipeline Accident Report

The Safety Board also studied API loading practices for rail transportation to

determine the static stresses in pipe loaded for transportation. API RP 5L1 provides an

equation for calculating the peak circumferential tensile stress in a pipe at a bearing strip

as a function of the geometry of the loading. API RP 5L1 does not indicate the source of

the equation. The purpose of this equation is to calculate the number of flat bearing strips

needed to keep the stress below a specified level. The stress determined from the finite

element model was compared to the stress calculated by the equation from API RP 5L1

under the same conditions. For a 40-foot-long, 34-inch-diameter, 0.300-inch-wall

thickness pipe, the comparison indicates that the equation from API RP 5L1

underestimates the peak circumferential tensile stress by a factor of approximately 2. 

The API has also published guidelines for loading pipe for transport onboard

marine vessels, API RP 5LW, Recommended Practice for Transportation of Line Pipe on

Barges and Marine Vessels. API RP 5LW also includes an equation for calculating the

peak circumferential tensile stress in a stack of pipe supported by bearing strips. However,

this equation differs significantly from the API RP 5L1 equation, and no source is given

for the equation. The stress determined from the finite element model was also compared

to the stress calculated by the equation from API RP 5LW under the same conditions. For

a 40-foot-long, 34-inch-diameter, 0.300-inch-wall thickness pipe, the comparison

indicates that the equation from API RP 5LW also underestimates the peak circumferential

tensile stress by a factor of approximately 2.

The Safety Board also evaluated the pipe movement attributed to the nearby

excavation on February 5, 2002. The pipeline moved down and laterally a maximum of 18

inches. The deflection of the pipe led primarily to longitudinal tension and compression

stresses that would not have affected the fatigue crack (oriented on a plane radially

outward along the welded seam). Circumferential tensile stresses and shear stresses

associated with the pipe deflection were calculated to be in the range of 1 to 10 psi in

comparison to the circumferential tensile stress of 29,750 psi caused by the internal

pressure of the oil in the pipe at the time of the rupture.

RSPA Postaccident Corrective Action Order

On July 5, 2002, RSPA issued to Enbridge a corrective action order that required

the pipeline operator to conduct a detailed metallurgical analysis of the July 4 failure to

determine the cause and contributing factors. The corrective action order also prohibited

Enbridge from operating the pipeline until it had submitted a return-to-service plan, which

was to incorporate a program to verify the integrity of the 34-inch pipeline from the Deer

River Pump Station to Superior Terminal. The plan was to include, if relevant, an in-line

inspection survey using a technologically appropriate tool capable of assessing the type of

failure that had occurred, including the detection of longitudinal cracks, and remedial

action. If relevant, the return-to-service plan was to include an evaluation of the pipeline

coating system, a hydrostatic pressure test of the line segment, and a review of all

available pipeline data and records.
Factual Information 21 Pipeline Accident Report

Enbridge submitted its return-to-service plan to RSPA on July 8, 2002. On July 9,

RSPA allowed the pipeline to be restarted with pressure restrictions.

On July 11, RSPA amended the corrective action order to include an operating

pressure restriction on pipeline segments between the U.S./Canadian border and Superior

Terminal that contained any U.S. Steel pipe. The amended order required that pump

station pressure discharges be no higher than 80 percent of the pressure in the line at the

time of rupture and that line pressure at the failure site not exceed 80 percent of the

pressure at the time of rupture.

On December 2, RSPA permitted Enbridge to raise pressures at pump stations on

the Gretna to Clearbrook section of pipe from 80 percent of discharge pressures at the time

of the July 4 accident to 80 percent of the highest discharge pressure reached within 30

days of the accident. On June 5, 2003, RSPA allowed the operation of Viking Station,

which did not have pump units installed on the 34-inch line at the time of the accident.

Enbridge Postaccident Actions

Before the accident, the area where the pipeline ruptured was not designated a

high-consequence area. According to the 2000 census, the population in the area had

increased enough to make it a high-consequence area. Enbridgeís data on the crude oil

released in this area were also used in the 2002 evaluation of Enbridgeís highconsequence area pipeline segment identification program. The amount of crude oil

released did not trigger the addition of the Cohasset segment as a high-consequence area.

In May 2003, as a result of the population change only, the pipeline segment containing

the rupture site was classified as a high-consequence area.

Enbridge had begun using a more technologically advanced in-line crack

inspection tool, the UltraScan CD, in Canada in 1997. The company ran the tool for the

first time in the 34-inch line in the United States in 2001. The detection level specification

for the tool states that it will find a defect equal to or greater than 2.50 inches long with an

accuracy of ±0.2 inch at 4.5 mph. The detection level specification for crack depth is

0.040 inch with accuracy of ±0.040 inch. Both the crack length and crack depth thresholds

must be met for the indication to be reported to the operator as a defect. Since the accident,

Enbridge has developed and documented a methodology for determining the need for an

investigative excavation from the data obtained from an UltraScan CD. Enbridge also has

prepared a pipeline inspection procedure, ìExcavation Program for Crack Feature

Assessment,î as guidance for personnel performing field excavations based on data from

the UltraScan CD. The new policy calls for the excavation of all crack-like indications

unless an engineering assessment determines that either the indication is acceptable based

on a fitness-for-purpose calculation or the indication is not a crack.

Enbridge had reviewed its in-line inspection program and updated it to run the

UltraScan CD tool from Gretna, Manitoba, Canada, to Clearbrook, Minnesota, in 2001

and from Clearbrook to Deer River in 2003. The UltraScan CD tool inspected the pipeline
Factual Information 22 Pipeline Accident Report

section from Gretna to Clearbrook in July 2001, about 1 year before the accident. The data

interpretation was completed in September 2002, about 2 months after the accident. No

new crack-like indications19 were reported in the longitudinal seam weld of this pipeline

section by the in-line inspection. One notch-like feature20 identified in a segment of U.S.

Steel pipe was excavated and found to be in the middle of a weld cap. Enbridge

determined that the feature was an external weld shrinkage crack that was not likely to be

related to transportation fatigue. A second notch-like feature was classified as a lowpriority feature to be excavated in the future. Other indications were inspected, and no

longitudinal cracks were found in any of the field inspections.

Enbridge representatives told the Safety Board that, in addition to excavating all

crack-like indications reported by the UltraScan CD tool, the company currently excavates

for field examination all notch-like indications in U.S. Steel pipe that are reported at the

longitudinal weld to determine whether they are cracks. Currently, the UltraScan CD inline inspection report does not include a depth estimate for notch-like indications. PII is

working with Enbridge to develop a depth estimate of notch-like indications for future

inspections. The UltraScan CD inspection tool was run from Clearbrook, Minnesota, to

Superior, Wisconsin, in November 2002, and in February 2003 the analysis of the

indications found in U.S. Steel pipe was completed. Interim reports allowed for an earlier

start of the excavation program for the highest priority indications. The UltraScan CD tool

reported 285 defect indications in 121 pipe joints that Enbridge excavated, inspected, and

assessed by nondestructive test methods. 

Included in these defect indications were 6 crack-like and 29 notch-like indications

that were either adjacent to or in the longitudinal weld on U.S. Steel pipe. Enbridge has

excavated the 6 crack-like indications and 4 of the 29 notch-like indications to visually

inspect and examine the pipe by nondestructive means. The field examination of five of the

crack-like indications showed that three were stress corrosion cracking,21 and two were at the

toe of the longitudinal weld. The sixth crack-like indication was found to be a sharp weld

contour. One notch-like indication was a defect that was found to have a 42-percent-depth

wall thickness crack. Two notch-like indications were an internal gouge and a weld profile (a

higher than normal weld cap) feature. The final notch-like indication that was examined was a

low-priority feature that was found to be an external shrinkage crack in the center of a weld.

The remaining 25 notch-like indications near or in the longitudinal weld were classified as

low priority. Enbridge plans to excavate these notch-like indications. Stress corrosion

cracking was also found by the UltraScan CD tool and reported as crack-field22 indications.

19 In PII terminology, a crack-like indication is one that is interpreted from UltraScan inspection data as

a crack, which is typically at or in the longitudinal weld.

20 Notch-like defects are grooves in the toe of the DSAW longitudinal seam weld, manufacturing

defects in flash-welded or electric resistance welded longitudinal seam welds, weld trimming tool marks

adjacent to the longitudinal seam weld, or handling marks made during transportation or construction.

Although not interpreted to be crack-like features, depending on their characteristics, these indications may

need to be considered for excavation because field inspection may reveal them to be cracks. 

21 Stress corrosion cracking is the formation of cracks, typically in a colony or cluster, as a result of the

interaction of tensile stress, a corrosive environment, and a susceptible material. A colony of very short,

axially aligned cracks seen in the field is the typical result of such cracking.

22 In PII terminology, crack-field refers to a crack interpreted as stress corrosion cracking.
Factual Information 23 Pipeline Accident Report

The UltraScan CD tool found all internal cracks, now under pipe sleeve repairs,

that were previously found by the Elastic Wave tool. No new internal crack-like

indications were reported by the UltraScan CD tool under the sleeves, nor were any found

during nondestructive field examination of the pipe.

During the field excavations, Enbridge found 21 additional external weld toe

cracks on U.S. Steel pipe that were not reported by the inspection tool. According to the

field examinations, all 21 of the cracks were below the detection limit specification of the

tool. The field information gathered from the entire excavation program will help PII

evaluate defect parameters. Of the 285 indications, approximately 60 reported by the tool

had field-verified features that were below the contracted threshold limit of the tool for

depth, length, or both.

The UltraScan CD tool was designed to detect even smaller defects with a higher

degree of reliability than the Elastic Wave tool. Enbridge had an analysis performed that

established ranges of key input parameters for predicting reinspection intervals. Using the

knowledge learned from the July 2002 failure, Enbridge had crack growth rates for a

variety of defect sizes. The most conservative (worst-case) scenario evaluated was a

defect 0.080 inch deep by 7.5 inches long, two times the depth and three times the

detection threshold of the UltraScan CD tool. This defect has a predicted time until failure

of approximately 6.5 years. Enbridge has proposed to RSPA that an alternative to

hydrostatic pressure testing is reinspecting the Clearbrook to Superior section of the 34-

inch pipeline within 3 years of the previous in-line crack tool inspection.

Enbridge currently has a program to evaluate and repair stress corrosion cracking

when it is found in the pipeline. Enbridge has provided field feedback to PII on the

UltraScan CD tool data gathered from Gretna to Superior on stress corrosion cracking in

the pipe. Enbridge also has asked PII to recalibrate the UltraScan CD tool data using

Enbridgeís field information to improve the accuracy of stress corrosion crack depth

estimates. In addition, a metal loss in-line inspection was completed from the

U.S./Canadian border to Superior, Wisconsin. 

As a result of these in-line inspections, Enbridge has stated that repairs have been

made according to company procedures to all defects that were excavated and examined.

American Society of Mechanical Engineers Pipeline Codes

American Society of Mechanical Engineers (ASME) code B31.8, 2003 edition,

Gas Transmission and Distribution Piping Systems, section 816, contains guidance on

transporting pipe in accordance with the API railroad or marine vessel recommended

practices:23

23 API RP 5L5, Transportation of Line Pipe on Barges and Marine Vessels, was created in 1975 and

later was designated API RP 5LW.
Factual Information 24 Pipeline Accident Report

Any pipe having an outer-diameter-to-wall thickness ratio of 70 to 1 or more, that

is to be used in a pipeline at a hoop stress of 20 percent or more of the specified

minimum yield strength that has been or will be transported by railroad, inland

waterway, or by marine transportation, must have been or shall be loaded in

accordance with API RP 5L1 or API RP 5LW, respectively. When it is not

possible to establish that pipe was transported in accordance with the appropriate

practice, the pipe must be hydrostatically tested for at least 2 hours to at least 1.25

times the maximum allowable pressure if installed in a Class 1 location, or at least

1.5 times the maximum allowable pressure if installed in a Class 2, 3, or 4

location.

ASME B31.4, 1998 edition, Pipeline Transportation Systems for Liquid

Hydrocarbons and Other Liquids, section 434.4, states: ìWhen applicable, railroad

transportation of pipe shall meet the requirements of API RP 5L1.î
25 Pipeline Accident Report

Analysis

A metallurgical examination of the failed pipe segment of Enbridgeís 34-inchdiameter crude oil pipeline indicated that the rupture had occurred at a fatigue crack along

a longitudinal seam weld. Hydrostatic pressure testing and an in-line inspection tool

specifically designed to find cracks did not detect the crack before failure. 

In its investigation of this accident, the Safety Board attempted to determine how

and when the initial fatigue crack occurred and to assess methods used to detect cracking

in older pipelines before it propagates to pipe failure. The investigation identified the

following safety issues:

ï The effectiveness and application of line pipe transportation standards.

ï The adequacy of Federal requirements for pipeline integrity management

programs.

The Accident

The Enbridge Control Center SCADA systemís first indication of a release on

line no. 4 was dropping suction and discharge pressures at the Deer River station at 2:12 a.m.

on July 4, 2002. Subsequently, the Floodwood station suction pressures began dropping, and

the controller realized that he had an abnormal condition and suspected a leak. At 2:13 a.m.,

the pipeline controller called for the shift coordinator, and at 2:14 a.m., about 2 minutes after

the rupture, they decided to shut the line down. Within 3 minutes of this decision, all pumps

were shut off, and the valves had begun to close. About 4 minutes later, the final closure of

remotely controlled valves at Deer River and the remotely controlled valve at MP 1017.9

isolated the ruptured section from the remainder of the pipeline.

About 2:25 a.m., the Deer River and Floodwood police departments were notified

of the suspected leak, and at 2:30 a.m. the responsible Enbridge regional personnel were

notified. The control center then began analyzing the SCADA data to locate the leak and

estimate the volume of the release. The Safety Board concludes that Enbridgeís pipeline

control center personnel responded in a timely manner to the indications of a pipeline leak. 

Transportation of Accident Pipe

At the time Enbridge purchased the pipe that ruptured in this accident, the pipeline

industry was aware that thin-wall, large-diameter pipe (such as the 109:1 D/t ratio pipe that

ruptured in this accident) was particularly susceptible to cyclic stresses encountered during

transportation, especially by rail, and that such stresses could lead to the initiation of fatigue
Analysis 26 Pipeline Accident Report

cracking in the pipe unless the pipe was properly loaded and transported. Welded areas were

also known to be the areas most susceptible to fatigue crack initiation during transportation.

To address concerns about pipe stress during transportation, Enbridge had required

in its purchase specification that pipe loading details be provided subject to its approval.

U.S. Steel submitted a diagram with specifications for rail car loading that was designed to

protect the pipe, and Enbridge approved it. Enbridge retained an engineering company to

inspect the manufacturing, handling, and loading of the pipe by U.S. Steel at the mill and

the subsequent unloading at its storage site near the mill. The engineering firmís final

report indicated that the pipe was accepted at the storage site for shipment subject to

Enbridge's instructions. Final transportation of the pipe was done later from storage, with

the pipe traveling by both rail and truck. 

The U.S. Steel loading diagram for the railroad shipment that included the accident

pipe provided for leveling bearing strips and placing separator strips for support of the

pipe, orienting longitudinal welds at 45° to the vertical, and avoiding contact with adjacent

pipes. The U.S. Steel diagram was similar to the loading specifications for railroad

transportation of line pipe in the January 1965 edition of API RP 5L1. As noted

previously, this recommended practice addressed loading pipe to minimize stresses across

the longitudinal welded seams of pipe, which are susceptible to fatigue cracking. The

Safety Boardís review determined that the provisions in the U.S. Steel loading diagram for

rail transportation satisfied the requirements of the January 1965 edition of API RP 5L1. 

The metallurgical testing and examination of the fatigue crack and ruptured area of

the accident pipe found no material or manufacturing defect in the steel or in the welded

longitudinal seam. In the absence of manufacturing or material defects, the creation of a

fatigue crack would be unlikely to result from normal operational pressure cycles.

However, once a fatigue crack has been created it may grow with the repetitive stresses

from normal operational pressure cycles. 

The fracture surfaces of the fatigue crack in the accident pipe had multiple arrest

lines and other indications of progressive cracking starting from the inside surface of the

pipe wall. There were two regions paralleling the inside surface; the region next to the

pipe wall was darkened and oxidized and contained multiple crack initiation sites. The

adjacent region where the crack extended further into the pipe wall was lighter and

cleaner, exhibiting little or no oxidation. The oxidation found in the darkened region most

likely occurred while the faces of the fatigue crack were exposed to the atmosphere before

the pipe was placed in service. The lighter region indicates that the fatigue crack grew

while oil was protecting the crack surfaces from oxidation. 

The Safety Board's finite element analysis revealed that the length of the fatigue crack

was consistent with the high stress region predicted on the inside surface of the pipe at a

bearing or separator strip. Documents show that Enbridge used an engineering company for

the specific purpose of inspecting the U.S. Steel pipe until it was stored near the mill. Further,

the pipe was transported only a few miles before storage, whereas it was transported about

1,000 miles by rail and truck from storage to construction sites in Minnesota, suggesting a

greater likelihood that the pipe was damaged after it was removed from storage. Further, there

is no documentation to substantiate that instructions for loading pipe on railroad cars were
Analysis 27 Pipeline Accident Report

followed after storage, and no evidence was found to indicate whether pipe loading

instructions existed for transportation by truck. Therefore, the stress levels necessary for the

initiation and initial growth of the fatigue crack were most likely caused by cyclic forces

acting on the pipe during transportation after storage. The finite element analysis for the

accident pipe shipment showed that following the rail loading standard, which prescribes size

and placement of bearing/separator strips and alignment of the welded seams at 45° to the

vertical, would not have resulted in stress levels high enough to initiate fatigue cracking

during transportation. Therefore, the Safety Board concludes that, after storage, the accident

pipe was likely inadequately loaded for transportation, which led to the initiation of fatigue

cracking along a longitudinal seam weld before the pipe was placed in service. The Safety

Board further concludes that after installation the preexisting fatigue crack grew with pressure

cycle stresses until the crack reached a critical size and the pipe ruptured. 

 Transportation Fatigue Cracking in Line Pipe

A number of fatigue cracks similar to the one in the Enbridge pipe have led to

failures in DSAW (double submerged arc weld) pipe at other locations. Improper

positioning of welds when loading pipe joints can create stress in the longitudinal weld

during rail transportation that is sufficient to initiate fatigue cracks that are consistent with

the type of damage observed in the Enbridge and Colonial pipeline DSAW pipe. As shown

in the 1988 metallurgical study of pipe referenced in the current API RP 5L1, fatigue

cracks occurring in pipe having various seam types led to 26 pipe failures during initial

hydrostatic testing between 1969 and 1987. All of these failures occurred after the pipe

had been transported by rail or marine mode. 

When compared to the Safety Boardís finite element analysis of the static stress

developed in the area of a bearing or separator strip (see figure 10) in a stack of 34-inchdiameter, 0.300-inch-wall thickness pipe, the equation in API RP 5L1 for calculating static

load stresses underestimated the stresses in the pipe by a factor of approximately 2.

However, the Safety Boardís analysis indicates that the effectiveness of API RP 5L1 in

preventing fatigue crack initiation can be explained by the emphasis on leveling the

bearing strips and on the proper alignment of welded seams at 45° to the vertical, leading

to a significant reduction in stress at the welds, which are the areas most susceptible to the

initiation of fatigue cracking. Although implementation of the recommended practice has

resulted in a reduction of railroad transportation fatigue crack initiation, the Safety Board

concludes that API RP 5L1, Recommended Practice for Railroad Transportation of Line

Pipe, may significantly underestimate the stresses in the pipe at the bearing or separator

strips. In the case of the accident pipe shipment, regardless of whether the stress levels were

underestimated in the rail loading standard, as noted previously, following the rail loading

standard would not have resulted in stress levels high enough to initiate fatigue cracking.

API RP 5LW, Recommended Practice for Transportation of Line Pipe on Barges and

Marine Vessels, also provides an equation for calculating the static load stress in a stack of

pipe for shipment, but this equation is significantly different from the equation in API RP

5L1. When the Safety Board compared the stresses calculated using the equation in API RP
Analysis 28 Pipeline Accident Report

5LW to those determined by the finite element analysis for 34-inch-diameter, 0.300-inchwall thickness pipe, it found that the equation in API RP 5LW also underestimates the

stresses in pipe loaded for transport by a factor of approximately 2. The Safety Board,

therefore, concludes that API RP 5LW may significantly underestimate the stresses in the

pipe at the bearing or separator strips. The Safety Board believes that the API should review

the equations in API RP 5L1 and API RP 5LW for calculating the static load stresses at the

bearing or separator strips and revise the recommended practices based on that review. 

Natural Gas Pipeline Safety Regulations

To prevent the formation of fatigue cracks during railroad transportation of pipe

that is to be used in natural gas service, 49 CFR Part 192.65 (effective November 12,

1970) required shippers to follow the requirements of API RP 5L1 when transporting pipe

for which the expected hoop stress during service was equal to or greater than 20 percent

of the specified minimum yield strength. When the regulation became effective, pipeline

operators were prohibited from using an estimated $13 million of stockpiled pipe that had

been transported by rail because operators were unable to verify that the pipe had been

transported in accordance with API RP 5L1. RSPA granted an exemption in February

1973 that allowed the installation of this pipe if it were pressure tested to higher pressures

than normally required. However, transportation fatigue cracks can grow to failure in

service after the pipeline has been pressure tested. Therefore, the Safety Board concludes

that hydrostatic pressure testing of a pipeline is insufficient to expose all transportation

fatigue cracks that may eventually cause pipe failure. Although the amount of pipe still in

stock that was transported before November 12, 1970, without documentation that API RP

5L1 was followed is likely not significant, such pipe could be placed in service. Therefore,

the Safety Board believes that RSPA should remove the exemption in 49 CFR 192.65 (b)

that permits pipe to be placed in natural gas service after pressure testing when the pipe

cannot be verified to have been transported in accordance with API RP 5L1. 

Liquid Pipeline Safety Regulations

The RSPA task force report noted that crack growth from fatigue in pipelines is a

greater possibility in liquid lines than in gas lines because liquid lines are subject to

frequent and substantial pressure cycle variations during normal operations. In contrast to

the regulations for transport of natural gas pipe, no similar Federal requirements are

applicable to hazardous liquid pipe to ensure that such pipe is protected from fatigue crack

initiation during railroad transportation. In a letter to the Safety Board dated July 21, 2003,

RSPA indicated that it intends to revise 49 CFR Part 195 for hazardous liquid pipelines to

require the use of API RP 5L1, consistent with Part 192 for pipe transportation for gas

pipelines. The Safety Board encourages RSPA to promptly amend 49 CFR Part 195 to

require that hazardous liquid pipeline operators follow API RP 5L1 for railroad

transportation of pipe. 
Analysis 29 Pipeline Accident Report

Marine Transportation of Pipe

Pipe shipped by marine transportation has also exhibited transportation-related

failures, but the pipeline safety regulations have no requirement that a standard be

followed when pipe is transported on a marine vessel. The API recommended practice for

transportation of pipe on marine vessels, API RP 5LW, was first issued in 1975 as API

RP 5L5. In addition to 9 fatigue failures attributed to rail transportation in the 1988

metallurgical study, 17 fatigue failures were attributed to pipe transported by ship that

failed during hydrostatic testing between 1976 and 1987 while the recommended practice

was available to the pipeline industry. The Safety Board concludes that there is a potential

risk of pipe damage due to fatigue crack initiation during marine vessel transportation of

pipe, similar to the risk during rail transportation, for both hazardous liquid and natural

gas pipelines. Therefore, the Safety Board believes that RSPA should amend 49 CFR to

require that natural gas pipeline operators (Part 192) and hazardous liquid pipeline

operators (Part 195) follow API RP 5LW for transportation of pipe on marine vessels. 

Truck Transportation of Pipe

Rail transportation has generally been considered to be the most likely source of

transit fatigue cracking because of the larger number of pipe rows and high loads, long

distances, and long travel times involved. A number of previous pipeline failures have

been attributed to rail transportation fatigue, but the pipe also was transported in the field

by truck following rail transit. Since no information was available regarding truck loading

and transport conditions for the pipe that ruptured, the possibility of fatigue crack

initiation during truck transportation cannot be ruled out.

It is reasonable to assume that pipe, in addition to incurring abrasions or dents,

could incur fatigue damage during truck transportation. A pipeline industry standard does

not exist for the loading requirements for transportation of steel pipe on trucks. Although

the Safety Board does not have any data with which to determine the extent of fatigue

crack initiation that may occur as a result of highway transportation induced stresses, the

Safety Board concludes that the absence of industry loading standards for truck

transportation of pipe might create risks to the integrity of both natural gas and hazardous

liquid pipelines. The Safety Board, therefore, believes that RSPA should evaluate the need

for a truck transportation standard to prevent damage to pipe, and, if needed, RSPA should

develop the standard and incorporate it in 49 CFR Parts 192 and 195 for both natural gas

and hazardous liquid line pipe. 

ASME Pipeline Codes

As noted previously, ASME B31.8, Gas Transmission and Distribution Piping

Systems, section 816, contains an exemption that allows the installation of pipe that may not

have been loaded and transported in accordance with the appropriate API railroad or marine
Analysis 30 Pipeline Accident Report

recommended practice with no restriction on when the transportation took place. The

exemption allows a hydrostatic pressure test in lieu of compliance with the API

recommended practices. The exemption requires a hydrostatic pressure test for a minimum

of 2 hours at higher than normally required test pressures. Even though the Federal pipeline

safety regulations take precedence in cases of a conflict or apparent conflict with any

industry guidance, the Safety Board is concerned that the ASME B31.8 piping code may

lead pipeline operators to erroneously believe that pressure testing exposes all fatigue cracks

initiated during transportation and verifies the integrity of pipe that may not have been

loaded and transported in accordance with API standards. Therefore, the Safety Board

believes that ASME should amend ASME B31.8, Gas Transmission and Distribution Piping

Systems, section 816, to remove the provision that pressure testing may be used to verify the

integrity of pipe that may not have been transported in accordance with the API

recommended practices for transportation of pipe by railroad or marine vessels. 

ASME B31.4, Pipeline Transportation Systems for Liquid Hydrocarbons and

Other Liquids, section 434.4, requires that the transportation of pipe by railroad follow

API RP 5L1 but does not require that marine transportation of pipe follow API RP 5LW.

The Safety Board believes that ASME should amend ASME B31.4, Pipeline

Transportation Systems for Liquid Hydrocarbons and Other Liquids, section 434.4, to

require the use of API RP 5LW for marine transport of pipe. 

Pipeline Integrity Management

Hydrostatic pressure testing was performed on Enbridgeís pipeline after

construction in the 1960s and at various times through the 1980s. As a result of a 1991

fatigue crack rupture, RSPA required Enbridge to develop an operational reliability

assessment that included additional pressure tests and to make changes to pipeline

operations that included lowering pressure cycle stress in order to improve pipeline

integrity. A number of defects failed during the 1991ñ1992 hydrostatic pressure testing,

including some fatigue cracks. By 1995, RSPA had approved Enbridgeís use of an in-line

inspection tool, the Elastic Wave tool, to find pipe cracks, rather than hydrostatic pressure

testing. By using this tool, Enbridge found a number of cracks that the company repaired

before failure. By 1998, the interval for in-line crack tool reinspection had been

established as 10 years from the previous inspection. The pipeline section that failed in

this accident had last been inspected in May 1996 with an in-line crack-detection tool,

which was run approximately 6 years before the rupture. 

In the May 1996 inspection, an indication was present at the point where the pipe

later ruptured on July 4, 2002, but the indication did not exhibit the diamond-shaped

signature typical of a crack and did not meet the inspection companyís interpretation

standard of at least 6 of 10 feature selection criteria to identify it as a crack. After the

accident, the inspection companyís analysis confirmed that the indication did not meet the

feature selection criteria. RSPAís postaccident review concurred with this analysis. The

Safety Board concludes that the Elastic Wave in-line inspection conducted before the

accident recorded an indication at the point where the pipe eventually failed; however,

preaccident and postaccident interpretations of the recorded data found that the indication
Analysis 31 Pipeline Accident Report

did not meet the feature selection criteria to identify it as a crack. Relatively large cracks

can be found when a pipe fails during hydrostatic pressure testing; however, the potential

also exists for smaller cracks to grow but not fail during a pressure test and then continue

to grow due to normal operational pressure cycle stress. In its report of the 1980 accident

in Manassas, Virginia, the Safety Board noted that it is unlikely that all fatigue cracks will

be found during hydrostatic pressure testing. To expose fatigue cracks on the 34-inch

pipeline in 1991, Enbridge used hydrostatic pressure testing. However, smaller fatigue

cracks that remained in the pipe continued to grow to the point of failure before the next

pressure test. Within 2 1/2 years of an Enbridge pressure test, two fatigue cracks failed,

resulting in crude oil leaks. The Enbridge metallurgical evaluation indicated that the stress

developed during hydrostatic testing was sufficient to propagate the cracks but insufficient

to cause an immediate failure. Beginning in 1995, Enbridge inspected its entire 34-inch

pipeline in the United States using the Elastic Wave in-line inspection tool. Enbridgeís

policy was to excavate all reported crack defects for evaluation whether or not the affected

pipeline segment was in a high-consequence area.

After this accident, RSPA reviewed the data from the 1995ñ1996 Mark II Elastic

Wave inspection tool for the failed joint of pipe. That review confirmed that the inspection

log data showed an indication in the pipeline at the point of rupture; however, the data did

not meet the crack identification criteria established by the inspection company. As a

result of this accident, RSPA informed the Safety Board on July 21, 2003, that it plans to

issue an advisory bulletin to all pipeline operators about reevaluating previous Mark II

Elastic Wave tool inspections used to detect crack-like defects near the longitudinal weld

and taking remedial action necessary to ensure the continued integrity of the pipeline. In

addition, according to RSPA, pipeline operators will be issued a directive to monitor

pressure cycles to verify that assumptions made in the original remaining life analyses for

cracks remain valid and to ensure that input parameters are within the tool tolerance range

and detection level when analytical methods are used to establish retesting intervals.

Furthermore, RSPA will modify the forms it uses to guide comprehensive integrity

management audits to ensure that pipeline operators adhere to the requirements of the

advisory bulletin. The Safety Board supports the completion of these actions that can be

taken now by pipeline operators to improve pipeline integrity. 

RSPA, with the financial assistance of industry trade associations, is also

conducting research leading to the development of a quantitative basis for evaluating the

significance of pipe material and construction features having time-, environment-, and

cycle-dependent growth mechanisms (which includes fatigue cracking) that threaten

pipeline integrity in natural gas transmission pipelines. In addition to evaluating the

significance of defects in pipe seams, the study will assess defects in pipe manufacturing,

pipeline construction, pipe base metal, girth welds, and fabrication welds to quantify

conditions under which otherwise benign material and construction features can become

active and grow to failure. The research will examine the threats to natural gas pipeline

integrity including external and internal corrosion, stress corrosion cracking, and fatigue

cracks. The research is intended to identify the conditions that cause the defects to grow

and will not be limited to operating pressure or hydrostatic pressure testing. An evaluation

technique will also be created for pipeline operators to develop effective mitigation

criteria for their pipelines. The Safety Board agrees that, in addition to fatigue cracking,
Analysis 32 Pipeline Accident Report

other types of time-, environment-, and cycle-dependent defects need to be considered

when evaluating threats to hazardous liquid pipeline integrity. If RSPA is satisfied with the

results of the natural gas research, the study could be extended to include hazardous liquid

pipelines, and the Board encourages RSPA to proceed with the hazardous liquid pipeline

research to better evaluate pipeline integrity. 

In the past, Enbridge had modified the expected crack growth rate from pressure

cycle stress based on knowledge gained from investigating prior failures that occurred on

the 34-inch-diameter pipeline system. However, in 2001 Enbridge started using the

UltraScan CD, a more technically advanced in-line crack inspection tool, for in-line

inspections of its 34-inch line in the United States. Since the accident, Enbridge has

studied crack growth due to pressure cycle stress using its current crack growth rate

model. The company based the study on various sizes of potential fatigue cracks that the

UltraScan CD tool was specified to find. For this study, Enbridge assumed that cracks of

various sizes would not be found by the inspection tool, then performed an analysis, with

the reduced pipeline pressure cycles Enbridge intends to achieve, to project how long

those cracks would continue to grow until they might fail. The largest potential crack

evaluated in the study was one that was two times the depth and three times the length of

the threshold size of a crack that the UltraScan CD tool could detect. The analysis

concluded that a crack this large would still have a predicted remaining life of 6.5 years.

As a result of the crack-growth evaluation, Enbridge is now proposing to RSPA that it

perform the next in-line inspection in the Clearbrook to Superior 34-inch pipeline section

using the more advanced in-line crack inspection tool within 3 years of the last inspection. 

On September 5, 2003, RSPA requested modifications to Enbridgeís return-toservice plan, which include running the UltraScan CD tool in 2005 and analyzing crack

growth rate after the reinspection. Enbridge responded that it would reinspect the line

between Clearbrook and Superior in 2005 and use the resulting data to refine crack growth

rates and determine future integrity requirements. Because cycle-dependent growth is a

factor in fatigue crack failures, adhering to operating practices that limit the number and

magnitude of pipeline pressure cycles is critical to limiting crack growth. Enbridge also

has committed to monitoring and analyzing pressure cycle data on a quarterly basis and to

sending each analysis to RSPA at least until the in-line crack tool inspection of the

Clearbrook to Superior section is completed in 2005. The Safety Board supports efforts to

monitor operating data and refine crack growth rate estimates to help determine

appropriate in-line reinspection intervals. 

The Federal pipeline safety regulations require that certain actions be taken when

conditions are found that could affect pipeline safety. Enbridgeís policy regarding fatigue

cracks has been and still is to run an in-line crack inspection tool in the entire 34-inch

pipeline regardless of high-consequence area designation. Before RSPAís integrity

management rule, Enbridge analyzed the crack failure data and established a reinspection

time interval for its 34-inch pipeline based on an engineering evaluation of the crack

growth rate. Now, RSPAís integrity management rule for high-consequence areas, 49 CFR

195.452 (e), requires that a hazardous liquid operator consider all risk factors to establish

an assessment schedule, including the ìresults of a previous assessment, the defect type

and size that the defect assessment method can detect, and the defect growth rate.î 
33 Pipeline Accident Report

Conclusions

Findings

1. Enbridgeís pipeline control center personnel responded in a timely manner to the

indications of a pipeline leak. 

2. After storage, the accident pipe was likely inadequately loaded for transportation,

which led to the initiation of fatigue cracking along a longitudinal seam weld before

the pipe was placed in service.

3. After installation the preexisting fatigue crack grew with pressure cycle stresses until

the crack reached a critical size and the pipe ruptured.

4. The American Petroleum Institute recommended practice 5L1, Recommended

Practice for Railroad Transportation of Line Pipe, and American Petroleum Institute

recommended practice 5LW, Recommended Practice for Transportation of Line Pipe

on Barges and Marine Vessels, may significantly underestimate the stresses in the

pipe at the bearing or separator strips.

5. Hydrostatic pressure testing of a pipeline is insufficient to expose all transportation

fatigue cracks that may eventually cause pipe failure.

6. There is a potential risk of pipe damage due to fatigue crack initiation during marine

vessel transportation of pipe, similar to the risk during rail transportation, for both

hazardous liquid and natural gas pipelines.

7. The absence of industry loading standards for truck transportation of pipe might

create risks to the integrity of both natural gas and hazardous liquid pipelines.

8. The Elastic Wave in-line inspection conducted before the accident recorded an

indication at the point where the pipe eventually failed; however, preaccident and

postaccident interpretations of the recorded data found that the indication did not

meet the feature selection criteria to identify it as a crack.

Probable Cause

The National Transportation Safety Board determines that the probable cause of

the July 4, 2002, pipeline rupture near Cohasset, Minnesota, was inadequate loading of the

pipe for transportation that allowed a fatigue crack to initiate along the seam of the

longitudinal weld during transit. After the pipe was installed, the fatigue crack grew with

pressure cycle stresses until the crack reached a critical size and the pipe ruptured. 
34 Pipeline Accident Report

Recommendations

As a result of its investigation of the July 4, 2002, pipeline rupture near Cohasset,

Minnesota, the National Transportation Safety Board makes the following safety

recommendations:

To the Research and Special Programs Administration:

Remove the exemption in 49 Code of Federal Regulations 192.65 (b) that permits

pipe to be placed in natural gas service after pressure testing when the pipe cannot

be verified to have been transported in accordance with the American Petroleum

Institute recommended practice 5L1. (P-04-01)

Amend 49 Code of Federal Regulations to require that natural gas pipeline

operators (Part 192) and hazardous liquid pipeline operators (Part 195) follow the

American Petroleum Institute recommended practice 5LW for transportation of

pipe on marine vessels. (P-04-02)

Evaluate the need for a truck transportation standard to prevent damage to pipe,

and, if needed, develop the standard and incorporate it in 49 Code of Federal

Regulations Parts 192 and 195 for both natural gas and hazardous liquid line pipe.

(P-04-03)

To the American Society of Mechanical Engineers:

Amend American Society of Mechanical Engineers B31.8, Gas Transmission and

Distribution Piping Systems, section 816, to remove the provision that pressure

testing may be used to verify the integrity of pipe that may not have been

transported in accordance with the American Petroleum Institute recommended

practices for transportation of pipe by railroad or marine vessels. (P-04-04)

Amend American Society of Mechanical Engineers B31.4, Pipeline

Transportation Systems for Liquid Hydrocarbons and Other Liquids, section

434.4, to require the use of the American Petroleum Institute recommended

practice 5LW for marine transport of pipe. (P-04-05)

To the American Petroleum Institute:

Review the equations in American Petroleum Institute recommended practice

5L1, Recommended Practice for Railroad Transportation of Line Pipe, and

American Petroleum Institute recommended practice 5LW, Recommended

Practice for Transportation of Line Pipe on Barges and Marine Vessels, for

calculating the static load stresses at the bearing or separator strips and revise the

recommended practices based on that review. (P-04-06)
Recommendations 35 Pipeline Accident Report

BY THE NATIONAL TRANSPORTATION SAFETY BOARD 

MARK V. ROSENKER

 Vice Chairman

JOHN J. GOGLIA

Member

CAROL J. CARMODY

Member

RICHARD F. HEALING

Member

Adopted: June 23, 2004

Chairman Ellen Engleman Conners did not participate in the adoption of this report.

37 Pipeline Accident Report

Appendix A

Investigation

The National Transportation Safety Board was notified on July 4, 2002, through

the National Response Center, of a pipeline release in an isolated, swampy area west of

Cohasset, Minnesota. The Safety Board dispatched an investigative team from its

Washington, D.C., headquarters. The team comprised investigative groups in pipeline

operations, SCADA, and emergency response. No Board member accompanied the

investigative team. No depositions or hearings were held in conjunction with the

investigation. Enbridge Pipelines (Lakehead), LLC; PII North American, Inc.; United

States Steel Corporation; the Minnesota Office of Pipeline Safety; Minnesota Pollution

Control; the Minnesota Department of Natural Resources; the Cohasset Fire Department;

and RSPAís Office of Pipeline Safety were parties to the investigation.