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Pipeline Accident Number: DCA-96-MP-004

Type of System: Petroleum products

Accident Type: Release of hazardous liquid

Location: Near Gramercy, Louisiana

Date and Time: May 23, 1996, about 10 p.m. (CDT)

Owner/Operator: Marathon Pipe Line Company1

Fatalities/Injuries: None

Damage: In excess of $7 million

Material Released: Gasoline

Quantity Released: About 475,000 gallons (about 11,300 barrels)

Pipeline Pressure: 1,094 psig

Component Affected: 20-inch steel pipe

Description of the Accident

On May 23, 1996, a pipeline controller was on duty in Marathon Pipe Line Company’s

pipeline operations center in Findlay, Ohio, operating and monitoring a 68-mile-long segment of

Marathon pipeline located in Louisiana. This pipeline is used to transport hazardous liquids

between a refinery at Garyville, Louisiana, and a station at Zachary, Louisiana. Pumps at the

Garyville refinery pressurize the pipeline and generate the power to transport the liquids to the

Zachary station.

About 9:53 p.m. central daylight time on May 23, the pipeline controller had just

completed operations to transport a batch of unleaded gasoline through the pipeline. He then

remotely executed commands to introduce into the pipeline (behind the gasoline) a batch of

125,000 barrels of low-sulfur diesel fuel.

About 10 p.m., unknown to the controller, the pipeline ruptured at a location near

Gramercy, Louisiana. At 10:01:53 p.m., the supervisory control and data acquisition (SCADA)

system2

 reported high-pump-case pressure at Garyville. The SCADA system activated an audible

 1 Because of a merger that took place since the accident, the name of the owner of the affected pipeline is

now Marathon Ashland Pipe Line LLC.

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

pipeline. Controllers can monitor flow rates and pressures along the lines and control valves and mainline pumps to

adjust the flow and make product deliveries. According to Marathon, the company had, on May 1, 1996, put into

operation a new SCADA system. The new system was functional at the time of the accident, and the controller had

been trained in its use.
2

alarm and also displayed a message on a display screen. Almost immediately, the SCADA

system sounded and displayed alarms reporting that certain pumping units at the Garyville station

had automatically shut down because of low suction pressure (low liquid pressure on the inlet

side of the pump).3 At 10:02:30 p.m., the SCADA system reported a line balance alarm.4

The pipeline controller said he initially believed that the alarms resulted from activity at

the refinery adjacent to the Garyville station. He said that on occasion the refinery would deliver

product from the pipeline to river barges, an operation that sometimes decreased the pipeline

pressure sufficiently to cause the SCADA system to alarm and to automatically shut down

pumping units. According to the controller, this scenario had, in fact, occurred a few days before

the accident.

The pipeline controller continued to receive alarms. Initially, he acknowledged each one

individually, but believing that each subsequent alarm was related to operations at the refinery,

he elected to simultaneously acknowledge all the alarms and the alarm text messages without

attending to the nature of each alarm. The controller said he had anticipated a positive differential

line balance alarm because of the shutdown of the pumping units. He said he therefore did not

read the full alarm message on the SCADA screen and consequently did not notice that the line

balance alarm was reporting a negative differential (indicating that less product was exiting the

pipeline at Zachary than was being introduced at Garyville).

The controller said he called Garyville and discussed the situation with the station

operator there. The station operator confirmed the automatic pump shutdowns. The station

operator determined that the Garyville refinery was, indeed, loading product to a barge. Even

though refinery personnel reported that the volume of product being delivered was insufficient to

have caused the SCADA system to alarm, the pipeline controller and the station operator

concluded that the loading of the barge had precipitated the alarms and the pump shutdowns.

About 10 minutes after the initial alarm, the controller attempted to restart the pumps that

had shut down automatically. The pumps restarted, but went down again. At 11:00:30 p.m.,

about 1 hour after the pipeline rupture, the controller received another line balance alarm. This

time, he closely examined the data and also checked the readings of the flow meters for the

Zachary station. Determining that product was leaking from the pipeline, he immediately

initiated emergency action. Marathon crews were dispatched to the site, determined the

approximate leak location, and completed manual closure of valves on either side of the rupture

 3

 The high-pump-case pressure alarm would also have triggered a pump shutdown.

4

 The line balance alarm signals to the controller that the amount of product metered out of the pipeline at

Zachary is different from the amount of product being metered through the Garyville refinery and that the difference

exceeds the preset alarm limits. If the Zachary meter reports a higher volume of product than the Garyville meter, the

alarm message will tend to display a positive line balance differential. If the Garyville meter registers more product

at the beginning of the line than is being removed at Zachary, the alarm message will tend to indicate a negative

differential. (Marathon’s line balance system may be better described as a modified volume balance system in that it

attempts to account for volume changes within the pipe.)
3

at approximately 2:30 a.m. on May 24, 1996. Closing these valves isolated the rupture site within

an approximate 3.5-mile segment of the pipeline.

The ruptured pipeline ultimately released about 475,000 gallons of gasoline into a

common pipeline right-of-way and marsh land. Gasoline also entered the Blind River, causing

environmental damage and killing fish, wildlife, and vegetation in the area. After the accident,

Marathon arranged for the deployment and construction of containment and sorbent booms,

berms, and fencing at several locations to minimize damage and deter public access.

Investigation of the rupture site revealed an approximate 200- by 100-foot excavation

area that extended over the Marathon pipeline and included the rupture site. Safety Board

investigators found a longitudinal crack approximately 53 inches long near the top of the pipe. In

the area of the crack were multiple dents, scrapes, and gouges that were consistent with damage

that would be made by a backhoe or similar digging tool.

The investigation determined that in 1995, LaRoche Industries, Inc., arranged for

excavation of and repairs to various portions of its 8-inch pipeline, which was located about

30 feet from the Marathon pipeline. These excavations took place in September and October

1995 in the vicinity of the Marathon pipeline rupture.

According to Louisiana law, an excavator, before beginning work, must use the Louisiana

One Call system to ensure that no buried utilities will be affected by the excavation. No evidence

was found that LaRoche or its excavation contractor used the Louisiana One Call system or made

any attempt to coordinate the excavation activities with Marathon or any of the other operators

with pipelines in the vicinity of the excavation near the site of the eventual rupture.5

 According to

officials from LaRoche’s contractor, the equipment operators were told by LaRoche

superintendents that no pipelines were located in the area of the Marathon pipeline. A LaRoche

superintendent who supervised the excavation stated that when the excavation work was

completed, the excavation crew did not fill in the excavated area. According to Marathon

officials, the company was not informed by LaRoche or LaRoche’s excavation contractor of any

incident or activity involving its pipeline in the area of the eventual rupture. Other pipeline

operators with pipelines in the area of the Marathon pipeline told the Safety Board that they had

not performed any excavation work in the area of the rupture since at least May 1990.

LaRoche, in April 1998, implemented a written policy for repairing its 8-inch pipeline

that includes requirements to notify the Louisiana One Call system before beginning excavations.

LaRoche has told the Safety Board that all its future excavations will be preceded by notification

of the Louisiana One Call system.

Marathon has reported that since the accident, it has run a “smart pig” (a magnetic flux

internal inspection tool) down the entire 68-mile length of the accident pipeline, with particular

 5

 Records indicate that the excavation contractor used Louisiana One Call once during its work for

LaRoche, but that call involved excavations 1 to 2 miles from the eventual pipeline rupture.
4

attention given to those segments that parallel the LaRoche pipeline. According to the company,

segments that showed indication of significant damage have been repaired or replaced.

Probable Cause

The National Transportation Safety Board determines that the probable cause of the

accident was damage done to the Marathon pipeline during excavations of a nearby pipeline

operated by LaRoche Industries, Inc., which resulted from the failure of LaRoche Industries, Inc.,

either to take adequate measures to ensure that excavations performed under its supervision did not

damage underground utilities or to notify Marathon Pipe Line Company that those excavations may

have damaged the Marathon pipeline. Contributing to the severity of the accident was Marathon’s

delay in recognizing the rupture, which delayed shutting down the pipeline and isolating the

rupture.

Adopted: September 21, 1998