The Likelihood of a Leak or Rupture

Enbridge has horrendous record of spills, averaging one spill every 5-6 days over a 10-year period. Evidence heard during the NEB hearings illuminated this data by evaluating the stats behind Enbridge’s leak detection system, as well as their own reporting regarding the effectiveness of their technology for crack and corrosion detection. This studied approach exposes the scary realities behind the safety of this 1/4” thick pipeline.

LEAK DETECTION

In response to an Information Request brought by the Ontario Pipeline Landowners Association (OPLA), Enbridge admitted that “here are no ILI tools available that can accurately detect pinhole corrosion.” With concern, OPLA then noted that pinhole leaks have resulted in the release of 1,600 barrels of oil from Enbridge’s Norman Wells pipeline in 2011 (a spill that Enbridge initially reported at 4 barrels).

Regarding Enbridge’s leak detection system, they acknowledge that their computation pipeline monitoring system “will not detect a leak below 70.5 [cubic metres], 443 [barrels] over a two-hour period”. That works out to 3.7 barrels per minute. But, even at that rate, it would take 2 hours for the system to signal a spill. Outside of that, foot patrols and fly overs constitute Enbridge’s leak detection system, so it should be no surprise that – by Enbridge’s own admission – more than 30 percent of the releases in Line 9 were first reported by third parties.

Contamination due to small leaks has already been discovered during Enbridge’s integrity digs of Line 9. In their submission to the NEB, OPLA presented the stories of three landowners who were informed by Enbridge, upon conducting integrity digs on their properties, that their soil and water were contaminated. In one case, contamination negatively affected the health of a farmer’s livestock, and in another, has indefinitely shut down a horse farm.

Detecting Cracks and Corrosion: Inline Inspection tools

Enbridge uses inline inspection (ILI) tools to confirm the integrity of its pipeline system. It involves sending a “smart pig” loaded with ultrasound or electromagnetic sensors to check for cracks and corrosion. We know about the accuracy of these tools, because when Enbridge digs up pipe, we can compare the actual damage on the pipe to what the ILI tool predicted would be present. In these instances, we learn that these tools have what Enbridge’s engineering reports call a “non-conservative bias”. This means that they under-report on damage, almost always giving a rosier picture than the reality of their pipeline integrity.

“Features” is the innocuous term that Enbridge uses to describe pipeline defects, specifically cracks andstress corrosion cracking (SCC). In addition to under-reporting the severity of pipeline “features”, their tools often do not detect this damage in the first place! When the ILI tool does not catch a damaged piece of pipe, it is called a “false negative”. These false negatives sometimes make up over 20% of the total “features”, a dismal margin of error.

Results of Crack Excavation Program

Location of Segment Depth of worst SCC Colony, as reported by ILI tool Actual Depth of SCC Colony # of Reported Features # of False Negatives Features

Montreal to Cardinal

0.8 mm (12.5% of wall thickness)

1.6 mm (25% of Wall thickness)

360

43

Cardinal to Hilton

.8 – 1.6 mm (12.5-25% of wall thickness)

2 mm (31% of wall thickness)

492

113

Hilton to Westover

1.6 mm (25% of wall thickness)

2.2 mm (35% of wall thickness)

190

50

This chart is made up of data disclosed in Enbridge’s Engineering Assessment B1-15. The data was collected from an excavation program, based on the three crack tool runs preformed between 2006 and 2009, between the Westover terminal (near Hamilton, ON) and Montreal. Enbridge completed a total of 182 excavations involving 1042 reported features during the four-year excavation program.

Another troubling aspect of Enbridge’s Engineering assessment is that it predicted failure pressures of 687 – 818 psi at several locations. This is troubling because Enbridge is requesting a maximum operating pressure of 1000 psi, despite the fact that historically, Line 9 has not had a pressure of greater than 666 psi in the last 10 years.

HYDROSTATIC TESTING

Surely, one of the upsets of the NEB hearings (from Enbridge’s prespective) happened when the Ontario Ministry of Energy gave their intervention. Despite its historic alliance with industry, the Ministry slammed Enbridge’s safety culture and requested that the board require an independent engineering assessment and hydrostatic test. The request for a hydrostatic test was echoed by both the Equiterre Coalition and the Ontario Pipeline Landowners Association. The engineer behind the Accufacts report went even farther that the pipeline would have a 90% chance of failure in the near term were a hydrostatic test not to be performed.

A hydrostatic test seems to be a fairly simple operation. It involved running high pressure water through the pipe and seeing what happens. According to the Ministry, when a pipeline has been inactive for more than 12 months, as occurred on Line 9 in 1997, Canadian Pipeline Standards require that a hydrostatic test be conducted to re-establish the maximum operating pressure of a pipeline. Line 9B has had two hydrostatic tests, one prior to being placed into service in 1976 and the second prior to the decision to reverse Line 9 in 1997.

Despite the fact that hydrostatic tests seem to be standard in the industry, Enbridge emphatically rejects that this test is needed for Line 9, which has been minimally operating for over a year. Enbridge goes so far as to say that “there are potential detrimental effects of hydrostatic testing; including the potential to induce or grow cracks that do not fail during the test but may continue to grow in-service. Hydrostatic testing that resulted in propagating crack growth would obviously be counterproductive to the efforts to eliminate pipeline failures.”

Perhaps the only clear conclusion to draw from these contradicting reports is that this pipeline is structurally unsafe and should be decommissioned.

DILBIT – Does it pose a greater risk?

We understand that dilbit poses a greater risk to waterways because it is heavier than crude oil, and it is more dangerous to people’s health within the spill zone because of the toxic gases it releases that are specific to the transport of bitumen. But, is a pipeline carrying dilbit more likely to spill?

According to a paper entitled “Tar Sands Pipeline Safety Risks” by the NRDC (National Resources Defence Council), the Alberta pipeline system — which routinely carries dilbit — has […] about 16 times as many spills due to internal corrosion as the U.S. System.

The same document contains a chart of diluted bitumen’s characteristics. Among other characteristics, including viscosity and abrasives, quartz and silicates, the chart shows both a higher acidic content in diluted bitumen and a higher sulphuric content than in conventional oil. Additionally, dilbit must be pumped at a higher pressure, increasing risk of failure.

According to the Accufacts Report, written by pipeline expert Richard Kuprewicz, the variation of pipeline material creates greater risk of spill. ‘Pressure cycling,’ or the variations in operating pressures of a pipeline, increase with dilbit, because dilbit can vary more in composition than light conventional oil. The greater swings in the levels of operating pressures can create cracks in a pipeline. Kuprewicz estimated a 90% chance of a rupture along Line 9.

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