Two examples of pipeline failures are presented below. Full details of the failures are given in the referenced accident reports:

  • Case study of Bellingham: Anon., ‘Pipeline Rupture, and Subsequent Fire in Bellingham, Washington. June 10th, 1999’, Pipeline Accident Report. National Transportation Safety Board, USA. Report NTSB PAR-02/02. PB2002-916502. 2002
  • Case study of Marshall: Anon., ‘Enbridge Incorporated Hazardous Liquid Pipeline Rupture and Release, Marshall, Michigan, July 25th, 2010’, Accident Report. National Transportation Safety Board, USA. Report NTSB PAR-12/01. PB2012-912501. July, 2014.

Data in this section are from these two reports.

Readers should ask and answer the following questions as they read through the case studies:

  • who is responsible for the failure (for example, is it the pipeline operator)?
  • could the failure have been prevented, and – if ‘yes’ – how?

1. Bellingham, USA, 1999

An onshore, buried, pipeline, transporting gasolene, failed in Bellingham, Washington, USA in 1999. The section that failed had been constructed in 1966, and had been in operation continuously, since that year. Some details of the pipeline:

  • External diameter of pipeline is 16” (406 mm)
  • Wall thickness of pipeline is 0.312” (8 mm)
  • Strength (specified minimum yield strength, SMYS) of line pipe is X52 (52,000 lbf/in2)
  • Pressure in pipeline is 1433 psig (99 barg)
  • Stress (hoop) in pipeline at a pressure of 1433 psig is 71% SMYS

The pipeline failed, and gasolene leaked into a creek. 1½ hours after the leak started, the gasolene ignited in the creek. This resulted in 3 fatalities, and 8 injuries. Property damage was estimated at $45 million (2002 prices).

The gasolene pipeline was buried below two other pipelines. The fracture was on top of the gasolene pipeline, in the 11 o’clock position, with a length of opening in the pipeline of about 27” (686 mm). The fracture origin was an 8.5” (216 mm) long gouge, about 20% wall thickness deep.

There were many areas of damage (27 gouges) identified on the outside of the pipe, around the failure location, Figure 1. Dents of depth up to 4% the pipe diameter were measured, some associated with gouges, adjacent to the failure location.

Figure 1. Damage on a Pipeline (top), and Cracks in a Pipeline (bottom).

The gouges and dents on the pipeline were introduced during construction work (in 1994) on a nearby water treatment plant, and its 72 inch (1829 mm) pipeline. This work involved deep excavations around the gasolene pipeline, and the use of heavy earth moving equipment above/around the gasolene pipeline.

The gasolene pipeline was below the water pipeline of the treatment plant. The construction company is thought to have damaged the gasolene pipeline, but to have reburied it without repairing the gouges and dents.

The gouges and dents introduced into the gasolene pipeline lower the strength of the pipeline, and, over time, they can develop cracks which further reduce the strength of the pipeline.

The cause of failure was inadequate supervision of the excavation works in 1994, which led to the gasolene pipeline being damaged (gouged and dented). The pipeline was inspected between 1994 and 1999, but the pipeline operator did not act on the findings of these inspections, which did show damage to the gasolene pipeline in the vicinity of the eventual failure. A combination of these inspection data and evidence of excavation activities in 1994 meant the gasolene pipeline should have been excavated and examined for damage before its failure.

2. Marshall, Michigan, USA, 2010

An onshore, buried pipeline, transporting crude oil, failed in Marshall, Michigan, USA in 2010. The fractured pipe released 843,444 gallons (3.2 million litres) of crude oil. The resulting clean-up costs quickly exceeded $US1 billion.

Some pipeline data:

  • Diameter of pipeline: 30” (762 mm)
  • Wall thickness of pipeline: 0.254” (6.5 mm)
  • Pressure at time of failure: 486 psig (33.5 barg)

The pressure in the pipeline had been limited to 523 psig (36 barg) at the time of the accident, due to corrosion defects (not associated with the failure) identified during an inspection of the pipeline.

The pipeline failed at cracking along a longitudinal weld, Figure 1. There were many longitudinal, deep cracks around the weld. The coating around the pipe was in poor condition and disbonding.

The fracture length was 6 ft 8.25 inches (2038 mm), and the failure investigation revealed cracks along almost all this fracture length. The deepest crack was 0.213” deep (5.4 mm) (83.9% of the original wall thickness of 0.254”).

The pipeline had been inspected (2005), five years before the failure (2010), and cracks had been detected, measured, and reported. The inspection had reported long (≤ 51.6” (1311 mm)) ‘crack-like’ defects, with depths ≤ 40% wall thickness, in the area of the eventual failure.

The probable cause of the pipeline rupture was ‘corrosion fatigue cracks’ that grew and coalesced from crack and corrosion defects, under the disbonded coating. The disbonded coating would expose the pipeline to the surrounding environment, leading to both corrosion and associated cracking, which will increase in size with time. Additionally, the operation of the pipeline (continuous pipe pressure changes) would deepen the cracks by the process called ‘fatigue’.

This combination of corrosion attacking the pipeline steel, and its associated cracking growing by fatigue, caused the pipeline failure.