NTSB/PAB-01/01

Accident Number: DCA99-MP005

Owner/Operator: Colonial Pipeline Company

Type of System: Hazardous liquid petroleum products pipeline

Accident Type: Pipe rupture

Location: Knoxville, Tennessee

Product Released: Diesel fuel, high sulfur, 86 Grade

Time: 11:58 p.m. EST 

Date: February 9, 1999

Fatalities/Injuries: None

Property Damage: $7 million 

Quantity Released: About 53,550 gallons (1,275 barrels)

Pipeline Pressure: Approximately 91 psig

Component Affected: 10-inch-diameter, Grade 5L X-42, 0.250-inch wall 

thickness, electric resistance weld steel pipe

The Accident

On the afternoon of February 9, 1999, Colonial Pipeline Company (Colonial)

successfully completed a delivery of diesel fuel to the East Knoxville delivery facility

(East Knoxville) in Knoxville, Tennessee, using its Atlanta Junction/Knoxville stubline.1

To initiate the delivery, an operator at Colonial’s Knoxville Terminal began operating

valves that directed product into a 10-inch-diameter steel pipeline leading to the East

Knoxville facility, about 8 miles away. At about the same time, a valve was opened at the

other end of that line to allow the product to flow into the East Knoxville facility tanks. At

the completion of the delivery, the valves were closed, which left the pipeline filled with

diesel fuel at a pressure of about 91 psig. 

About 11:58 p.m. on February 9, the supervisory control and data acquisition

(SCADA) system2 at Colonial’s Atlanta control center registered and recorded a sudden

drop in pressure from 91 to 72 psig at East Knoxville. After several minutes of oscillation,

the pressure stabilized at 73 to 74 psig. The controller on duty in the Atlanta control center

at the time of the accident stated that he normally displays the SCADA pressure strip

charts3 across the two CRT screens at the top of his operating console. The SCADA

National Transportation Safety Board

Washington, D.C. 20594

Pipeline Accident Brief

1 A Colonial stubline is a smaller diameter, lateral pipeline system that emanates from one of the

company’s larger mainline pipelines that run from Texas to New York.

2 Pipeline controllers use the SCADA system to remotely control and monitor movement of product

through the pipeline. Controllers can monitor flow rates and pressures along the lines and control valves and

pipeline pumps to adjust the flow and make product deliveries.

E PLURIBUS UNUM

NATIONAL TRA SPORTATIO

N

B OAR D

SAFE T Y

N
NTSB/PAB-01/01



system did not alarm in response to the decrease in pressure, and the controller said he was

not aware of the pressure drop. As determined later, the pressure drop occurred when the

pipeline leading to East Knoxville ruptured on a Pitner Place residential property near

Knoxville’s Goose Creek.

On the east side of the Tennessee River, Colonial’s pipeline crosses Scottish Pike

and then Pitner Place. Between midnight and 12:15 a.m. on February 10, a Scottish Pike

resident walking outside his home smelled a kerosene odor, but he said he took no action

in regard to the smell. At 1:02 a.m. on February 10, a resident of Pitner Place called 911 to

report a very strong diesel or gasoline odor in the area. The Knoxville Fire Department

responded and concluded that the reported odors came from an asphalt plant across the

river from the community. Thus believing this odor did not pose any further concern but

was merely a nuisance odor, the firefighters cancelled the fire call and left the scene.

About 2:05 a.m., another Pitner Place resident closer to the pipe rupture, called 911

to report a very strong petroleum gas odor in the area. The fire department returned to the

scene to investigate. Again, the fire company attributed the odor to the nearby asphalt

plant. At 2:17 a.m., a Knoxville area resident called 911 to report oil on the Tennessee

River.

Meanwhile, the Atlanta controller (still unaware of the drop in the pipeline

pressure) called the Knoxville operator to start another product delivery to East Knoxville.

About 2:31 a.m., the Knoxville operator began operating valves to send product to the

East Knoxville delivery facility. The Atlanta controller observed that the East Knoxville

meter indicated no flow rate and that the pressure did not rise as expected at Knoxville.

The Knoxville operator said that after waiting 4 to 5 minutes for the flow rate to register

on his CRT screen, he called the Atlanta controller about the situation. The Atlanta

controller called the senior controller for his shift over to the console to discuss the

pipeline data, at which point the senior controller decided to terminate the delivery on the

East Knoxville line. About 2:39 a.m., the Knoxville operator began shutting down the East

Knoxville pipeline section and resumed using the stubline to make a delivery to another

Knoxville terminal. 

After shutting down the line, about 2:44 a.m., the Knoxville operator called

another Colonial employee at home and asked him to check out the East Knoxville

delivery facility. In a discussion with the Knoxville operator at 3:01 a.m., the Atlanta

controller suggested that the pipeline might have been in a slack condition (only partially

filled with product) when the delivery started, but he added that the pipeline pressure

should have increased faster at that time. In that discussion, he also said that the pipeline

was 600 to 700 barrels short. 

The hourly over/short calculation shown on the controller’s log for the line showed

a shortage of 725 barrels at 3:00 a.m. After the accident, the Atlanta controller said he

considered the shortage “high.” He also said that 300 barrels is “getting high,” although he

believed that 300 barrels could be explained as a characteristic of the opening of a

delivery. According to Colonial procedures, a sudden loss of pressure and/or a change in

3 The SCADA system provides pressure data on a strip chart graphical display on a CRT screen, which

displays the pressure history for about the previous hour.
NTSB/PAB-01/01



flow rate are to be interpreted as conclusive evidence of a leak. As part of Colonial’s leak

detection strategy, controllers are to immediately investigate and correct any shortage

calculation. 

At 3:45 a.m., Knoxville Fire Department responders found fuel running into Goose

Creek, which discharges into the Tennessee River about 1/2 mile downstream. Noting a

nearby Colonial pipeline marker with contact information, the incident commander

directed a Knoxville Fire Department dispatcher trainee to contact Colonial about the

leak; however, Colonial was not notified at that time.

Meanwhile, the Colonial employee who had been asked to check the East

Knoxville facility had driven by the site where an internal inspection tool had been

removed from the pipeline on February 9 (discussed below in the “Pipeline Information”

section). About 4:00 a.m., he reported that he saw no evidence of a failure in the pipeline

at that location, nor did he find any problem at the East Knoxville facility.

Still unaware of the nature of the problem, the Knoxville operator and the calledout Colonial employee discussed the situation with the Atlanta controller. At the end of the

discussion, the Atlanta controller decided that the Knoxville operator should attempt

another delivery to East Knoxville. The senior controller was not involved in the decision

to restart delivery. This time, the called-out operator would be observing at East

Knoxville. About 4:03 a.m., the operator attempted to pressure up the line between

Knoxville and East Knoxville, but the pressure did not rise as expected. About 4:20 a.m.,

he again opened the East Knoxville valve to operate this pipeline section, and initially no

flow was noted at East Knoxville. After a few minutes, the pressure began to fluctuate and

a lower-than-expected flow rate was indicated. The hourly flow rate was expected to be

more than 3,000 barrels per hour (bph); however, it peaked at approximately 2,000 bph.

About 4:30 a.m., the Knoxville Fire Department found diesel fuel spraying from a

pipeline onto a Pitner Place residence and running downhill into Goose Creek, which was

about 170 feet from the rupture site. The incident commander asked the fire department

communications center dispatcher to contact Colonial and have the company shut down

the pipeline. The fire department dispatcher, who was talking to Colonial’s senior

controller in Atlanta at that time, notified him of the leak and asked that the pipeline be

shut down. The senior controller immediately ordered that the Knoxville stubline be shut

down. The East Knoxville segment shutdown was completed at 4:35 a.m. At 4:46 a.m.,

the East Knoxville delivery valve was opened, and the pipeline segment was then allowed

to drain into the East Knoxville terminal. According to Colonial records, the temperature

of the product was approximately 61° F at East Knoxville.

The ruptured pipeline released approximately 53,550 gallons (1,275 barrels) of

diesel fuel. Fifteen people were reported to have voluntarily evacuated the immediate area

of the leak. During the first 24 hours, the leading edge of the oil slick on the Tennessee

River advanced about 6 miles downstream from Goose Creek. For the next several days,

the Tennessee River in the Knoxville area was closed to navigation as containment booms

were placed downriver. Nine collection points for escaped petroleum product were placed

downstream of the accident site. Colonial estimated that 44,016 gallons (1,048 barrels) of

product have been recovered. No fire resulted, and no injuries were reported.
NTSB/PAB-01/01



On March 3, 1999, Colonial submitted a Corrective Action Plan for Impacted Soils

and Groundwater at the Goose Creek Knoxville, Tennessee, Release Site to the Tennessee

Division of Solid Waste Management and Tennessee Division of Water Pollution Control.

The intent of the action plan was to determine the extent of the underground diesel fuel

plume and the further action needed to ensure site remediation acceptable to the State. The

corrective action plan called for the excavation of all contaminated soils at the leak site

that exceeded 500 parts per million, in accordance with Tennessee underground storage

tank guidance cleanup guidelines.

Approximately 18,000 tons of contaminated soil were excavated at the leak site

area during March and April 1999. The excavated soil was transported to Waste

Management’s Chestnut Ridge Landfill for disposal under the approval of the Tennessee

Division of Solid Waste Management. A well survey conducted shortly after the release

found no residential wells in the leak site area. The limited amount of affected

groundwater encountered was treated on site. The March 3 plan stated that because the

affected groundwater immediately discharges to Goose Creek, it would not contaminate

other portions of the shallow groundwater system and would not affect deeper

groundwater. It was therefore determined that it was not necessary to install monitoring

wells at the leak site.

Community Awareness 

At the time of the spill, Colonial had in place a 14-point public education program

that it had designed to meet the requirements of 49 Code of Federal Regulations (CFR)

Part 195.440, which requires oil pipelines to conduct public educational programs.4

Colonial’s public education program included mailing safety flyers to a targeted audience,

including apartment dwellers, living within 1/8 mile of a pipeline. The company also

provided direct mail pieces to those individuals who owned property where Colonial held

easements. These materials included an annual wall calendar and a Colonial road atlas

with a companion booklet that contained general information about the company. The

atlas and booklet were distributed every 5 years. 

In areas where Colonial deemed excavator risk particularly high, company

representatives participated in meetings to educate public officials, emergency responders,

and excavators. Additionally, the company distributed its atlas and companion booklet to

some public officials and contractors. In both 1997 and 1998, Colonial had pipeline maps

available for review at its tank farm during the emergency response coordination drills it

held with the Knoxville Fire Department. 

A review conducted in the immediate area of the pipeline failure disclosed that

Colonial pipeline easements crossed five residential properties. Colonial records indicate

that various public education items were mailed to two of these residences in November

and December 1997. These items addressed questions such as how to detect a pipeline

accident, what to do in case of an accident, and how to report an accident. Thirteen

4 Under 49 CFR 195.440, each operator shall establish a continuing education program to enable the

public, appropriate government organizations, and persons engaged in excavation-related activities to

recognize a hazardous liquid pipeline emergency and to report it to the operator or the fire, police, or other

appropriate public officials.
NTSB/PAB-01/01



residents were interviewed. Of those, residents from two households stated that they were

aware of a pipeline in the immediate area. One resident recalled receiving a pamphlet

explaining Colonial’s brush-clearing operation; however, no one was aware of any

specific reporting action or personal protection measures to take in the event of a pipeline

release, nor could they recall any safety awareness mailings from Colonial. 

The Knoxville Fire Department hazardous materials emergency response

procedures were last revised and approved in January 1999 by the Knoxville County

Emergency Management Agency. Fire department personnel have received training in

hazardous materials team operations provided by the Tennessee Emergency Management

Agency. These training courses cover hazardous materials incident response (incident

command system, hazardous material identification, notification, protective equipment,

etc.) at the responder, operations specialist, and technician levels.

According to fire department officials, the department conducts disaster drills

annually. The most recent disaster drill before the accident was on September 9, 1998. The

scenario involved a joint multiagency response to an aircraft crash at the Knoxville

Airport. The last chemical transportation accident drill was conducted in November 1998.

This simulated an accident that involved a highway cargo tank containing acid and the

release of a toxic cloud that caused two injuries. In November 1997, the Knoxville Fire

Department and Colonial conducted a joint training drill at a petroleum products terminal

in Knoxville. The scenario involved a pipeline rupture at a storage tank and a 1,000-gallon

gasoline spill. During a tour of its facility during December 1998, Colonial discussed with

Knoxville Fire Department personnel its pipeline delivery system, spill response

procedures, and pipeline location maps for the city of Knoxville. In its review of this

accident, the Knoxville Fire Department identified internal operations problems in its

response, including the use of trainees and the fact that some of the communications

channels monitored by the fire department were not recorded. Also, fire department

officials identified an issue regarding the lack of pipeline location maps during the early

stage of the emergency, which might have helped them locate pipelines in the complaint

area. 

Pipeline Information

The pipeline was constructed in 1962 and put into service in early 1963. The pipe

installed was 10-inch-diameter, Grade 5L X-42, 0.250-inch wall thickness, electric

resistance weld (ERW) steel pipe. At the rupture site, the pipeline was installed on a slope

and had a slight side bend to the left below the rupture (figure 1) in the downstream flow

direction. Colonial records indicate that the pipe had asphalt enamel coating. A coating

defect (wrinkled coating) was also evident 2 to 3 feet upstream of the rupture (figure 2).

Safety Board investigators and Colonial personnel observed no visible damage to the pipe

coating that remained immediately adjacent to the rupture area before the pipe was

removed for examination. Colonial did not have a toughness requirement5

 for pipe when it

was purchased for this pipeline, and no pipeline industry standards had been established at

that time. Since July 13, 1990, Colonial’s line pipe purchasing specifications have had

minimum toughness requirements that include, among other factors, a minimum

acceptance criteria of 25 ft/lbs of absorbed energy at 32° F for Charpy V-Notch (Charpy)

impact tests.6

 
NTSB/PAB-01/01



5 As a result of its investigation of a March 23, 1994, pipeline accident in Edison, New Jersey, the

Safety Board issued the following safety recommendation to the U.S. Department of Transportation’s

Research and Special Programs Administration (RSPA):

P-95-2

Develop toughness standards for new pipe installed in gas and hazardous liquid pipelines,

especially in urban areas.

In June 1995, in response to a request from RSPA, the American Petroleum Institute (API) organized a task

group to revise the specification for line pipe, API Specification 5L, to include minimum toughness

requirements. In January 2000, the revised 42nd Edition of API Specification 5L was published. It contains

two pipe product specification levels with Product Specification Level 2 (PSL-2) having a required

minimum fracture toughness level for new pipe. Safety Recommendation P-95-2 remains “Open-Acceptable

Response.”

6 Charpy V-Notch impact tests that measure the energy absorbed by a given thickness of material at a

given temperature were used to evaluate the fracture toughness of materials. 

Figure 1. Pipeline on slope showing side bend to the left 

beyond the rupture.

Rupture 

Site
NTSB/PAB-01/01



A hydrostatic pressure test to 649 psig was completed on February 4, 1995, on the

East Knoxville pipeline segment. The maximum operating pressure (MOP) for the

pipeline was determined to be 519 psig at the Knoxville station, which calculates to 552

psig at the rupture location. The allowable surge pressure, based on pipeline Federal safety

regulations (1.1 x MOP), is 571 psig at the Knoxville station and 607 psig at the rupture

location. Colonial records indicate that the typical operating pressure at the rupture

location ranges between 72 and 250 psig, and the number of operating cycles for that

range is at least 144 per year for the East Knoxville section of the pipeline.

Internal inspections with different types of “smart pigs” were performed in 1989

and 1999. The 1989 inspection was done using a conventional magnetic flux internal

inspection tool. The internal inspection company graded the inspection log, and no defects

were indicated at the rupture point. Colonial reported that repairs were made to other areas

of the pipeline as a result of the 1989 inspection. 

The pipeline was internally inspected again using a high-resolution magnetic flux

inspection tool on February 8, 1999. The inspection tool became stuck at one of several

dents about 4,000 feet upstream of the East Knoxville station (about 1.7 miles downstream

of the rupture site). The pipeline was pressurized a number of times to dislodge the

inspection tool and push it ahead. SCADA logs indicate that the pressure on the pipeline

reached 546 psig at the Knoxville station, which calculates to approximately 580 psig at

the rupture location. The effort to dislodge the tool using pressure was unsuccessful, and

on the afternoon before the rupture, the section of pipe containing the tool was cut from

the pipeline and replaced with new pipe. Product was transported through the line after the

Figure 2. Wrinkled coating 2 to 3 feet upstream of the circumferential crack that 

terminates at the 9 o’clock position.

Rupture

Wrinkled

Coating
NTSB/PAB-01/01



repair. The high-resolution magnetic flux inspection indicated no defects such as dents,

gouges, or significant corrosion at the failure location.

Colonial uses an impressed current cathodic protection7 system to protect its

pipelines. Company records indicate that the rectifier system was operating properly

before the accident. Annual corrosion survey records for 3 years prior to the accident

indicate the pipe-to-soil potential levels8 were –0.85 volt or more negative with reference

to a copper-copper sulfate reference electrode.9

Materials Laboratory Examination

When the pipe was exposed, a circumferential crack was found around the top half

of the pipe’s diameter (figure 3), and no pipe coating remained in the area of the crack.

The crack was not located in a girth weld, visible dent, or gouge; however, the crack ran

through an area of surface corrosion. Close examination of the fracture surface established

that the crack initiated at an area with at least nine separate darkly colored thumbnailshaped corroded regions (thumbnails). The failure initiation region was centered at the

3 o’clock position (looking downstream, toward East Knoxville) in the area of the external

surface corrosion. The thumbnail shape, dark coloration, and fracture surface features

were consistent with corroded preexisting cracks that initiated on the external surface of

the pipe and propagated radially inward. None of these preexisting cracks penetrated

through the pipe wall, with 0.120-inch being the deepest penetration observed, which was

48 percent of the nominal pipe wall thickness. Similar corroded preexisting cracks were

noted nearby in the surface corrosion area.

The crack ran in both directions from its initiation point. The crack propagated

clockwise past the longitudinal weld seam. In the clockwise direction, the brittle fracture

extended less than 0.5 inch before changing to a ductile fracture. In the counterclockwise

direction, the brittle fracture extended over the top of the pipe to approximately the

9 o’clock position, where it also terminated in a ductile fracture. (Refer to figure 2.) 

Scanning electron microscope examination of the fracture face revealed heavy

oxide deposits on the thumbnails that obscured some and obliterated other fracture details;

however, sufficient detail was visible to indicate that the thumbnails originated at shallow

corrosion pits on the external surface. Each of the thumbnail regions was associated with

surface corrosion damage and typically had one or two crack origin sites. In some

7 Cathodic protection is a corrosion mitigation method used by the pipeline industry to protect

underground metal pipes. The system uses rectifier stations along the pipeline to supply protective electrical

current. Cathodic protection current is forced to flow in the opposite direction of currents produced by

corrosion cells. A rectifier converts alternating current from the utility service to direct current and supplies

it to a ground bed that typically contains a string of suitable anodes, with soil as an electrolyte, to provide a

path for the current from the rectifier to the pipeline. A cable connected to the pipeline provides the return

path to complete the circuit.

8 The pipe-to-soil potential is defined as “the voltage difference between a buried metallic structure

[pipe] and the electrolyte [soil], measured with a reference electrode in contact with the soil.” From

H.L. Gordon, Cathodic Protection, Power Plant Electrical Reference Series, Project 2334, Electric Power

Research Institute, Palo Alto, California, 1991, vol. 11, p. 11.2.

9 Pipeline companies perform pipe-to-soil potential surveys by measuring and recording the voltages

and currents at test stations along the pipeline and at rectifiers. Measurement intervals vary widely from less

than 100 feet in some locations to several miles in others.
NTSB/PAB-01/01



instances, crack arrest marks were visible within the thumbnail regions. The preexisting

crack features in the failure initiating area were consistent with environment-induced

cracking.10

After the accident, Colonial had an independent lab perform Charpy tests on

specimens prepared from the failed pipe joint. Longitudinal pipe specimens were tested at

temperatures ranging between 25° and 170° F. The full-size energy values11 for absorbed

energy in the longitudinal direction were from 3.4 to 21.8 ft/lbs between 25° and 65° F,

and 40.2 ft/lbs at 85° F. The results between 105° and 170° F were from 62 to 77.1 ft/lbs.

The Safety Board also had Charpy testing performed on test specimens taken in

proximity to the rupture. The tests were conducted in both the longitudinal and

circumferential direction at a range of temperatures between 0° and 85° F. The test results

in the longitudinal direction indicate absorbed energy values from 4.2 to 15 ft/lbs between

0° and 65° F, and 54 ft/lbs at 85° F. The results in the circumferential direction indicate

values from 4.6 to 22 ft/lbs between 0° and 85° F. 

Figure 3. Circumferential crack on top half of pipe with failure initiation region at the 

3 o’clock position.

10 Environment-induced cracking occurs due to the combined effects of tensile stress and a corrosive

environment. If a susceptible material under static tensile stress is exposed to a specific corrosive medium,

the failure is defined as stress corrosion cracking. If the material is exposed to cyclic tensile stresses in a

corrosive environment, the failure is defined as corrosion fatigue.

11 Sub-size specimens were tested and full-size energy values were calculated in accordance with

ASTM E23 for all Charpy absorbed energy data.
NTSB/PAB-01/01

10

Actions Taken Since the Accident

Since the accident, Colonial has updated its public education program to reach a

target audience within a minimum of 1/4 mile of its pipeline operating area, regardless of

whether the property is traversed by a pipeline easement. Colonial has also updated the

educational information in its safety pamphlet and upgraded the method by which the

safety information is communicated to the target audience. Colonial has also updated its

public education program mailings to better reach its target audience. The first paragraph

of each educational mailing now encourages the initial reader to share the information

with all members of the household.

In addition, Colonial has upgraded its written procedures for establishing and

maintaining liaison with fire, police, and other agencies that might respond to a hazardous

liquid pipeline emergency. The procedures identify the methods to be used, the

information to be shared, and the frequency of the contacts.

Since the Knoxville accident, Colonial’s control center operations manual for

abnormal and emergency operations has been amended to include the following: “Any

time an unscheduled shutdown occurs, the line will only be re-started with the

concurrence of a Senior Controller.” At the time of the accident, Colonial’s control center

operations manual directed that for continuous minor hourly shortages, the controller

would investigate by having all active facilities “prove” (verify the accuracy of) the

meters. If proving meters did not correct the shortages, controllers were to contact the

senior controller for a decision to possibly pressure-test the line or shut it down for

inspection. Colonial’s control center operations manual for emergency operations

involving leaks or suspected leaks has been amended to include the following: 

Any time a line is shut down to investigate a continuous minor hourly shortage,

the line will only be re-started with the concurrence of a representative from the

Engineering Services Team.

Colonial is using the details surrounding this event in various training scenarios

and has added the Knoxville accident scenario to its maximum critical event training.

Colonial uses simulator training as part of its controller training.

Colonial is continuing its efforts to install an automated leak detection system.

Colonial is currently installing a batch tracking system on a Colonial stubline system

similar to the one involved in this accident. This new system is expected to aid the pipeline

controller in identifying variances in the amount of product shipped versus the amount of

product delivered. Any discrepancies identified above a predetermined threshold will be

investigated as a possible leak. Colonial has experienced some difficulty in completing the

installation of this system but anticipates completion in the first half of 2001. Once the

first system is successfully installed, Colonial anticipates installing the batch tracking

system on other stublines. When all the stublines are addressed, Colonial anticipates

attempting to apply the same batch tracking system to the company’s mainlines, although

the company expressed some concern about the effect that the size and the complexity of

the mainlines will have on the performance of the batch tracking system.

Colonial is developing a formal, documented strategic plan on how to approach the

identification, evaluation, and application of technology to leak detection on Colonial’s
NTSB/PAB-01/01

11

system. This plan is scheduled to be fully developed in 2001. The objective of the plan is

to find and implement effective means of leak detection and to comply with the new

Office of Pipeline Safety regulations on integrity management of pipelines that affect

high-consequences areas.

The Knoxville Fire Department incident commander held a postaccident

debriefing with Knoxville communication center personnel, established new procedures

for the communications center, and requested that Colonial provide maps for fire

department use. Because of the delay in notifying Colonial that occurred in this accident,

procedures have been changed so that (1) the communications center will not rely solely

on dispatcher trainees during periods of heavy workload; (2) the supervisors will assist the

dispatcher during periods of heavy workload; and (3) the communications center will

record all communications channels to create a record of emergency response

conversations.

Also at the request of the Knoxville Fire Department, Colonial provided the

department with pipeline location maps to be carried by fire department units responding

to calls involving the possible release of hazardous materials. The department also uses

the maps during annual fire department training sessions at the Colonial terminal facility.

Probable Cause

The National Transportation Safety Board determines that the probable cause of

this accident was pipe rupture initiated by environment-induced cracking in an area of

pipe coating failure. A contributing factor to the failure was the relatively low fracture

toughness of the pipe. Contributing to the severity of the accident was Colonial Pipeline

Company’s failure to determine from the supervisory control and data acquisition system

that a leak had occurred, with the result that the pipeline controller started and restarted the

pipeline, thereby increasing the amount of diesel fuel that was released. 

Approved: March 28, 2001