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Updated June 2021



The most common metric for reporting pipeline performance is the number of incidents per 1000 kilometres of pipelineper year. It's useful when comparing different companies, but it doesn't tell the full story. A lot goes into determining how a pipeline company is performing, and the results might differ depending on the metric used.

For an accurate comparison of pipeline performance between companies, it's critical that we compare companies who are similar not only in how they operate, but also in the number, size, and type (materials, substance) of pipelines they operate.

Metrics that we use include

  • the number of incidents per 1000 kilometres per year of pipeline,
  • the total number of incidents,
  • the consequence rating (low, medium, high), and
  • the volume of product released.

Some companies are examined more closely than others because of their compliance history or because of the location of their pipelines and the products those pipelines carry. For example, pipelines near a water body that are transporting a hazardous substance, such as sour gas, produced water, or oil-well effluent, may pose a greater risk to the public, wildlife, and the environment.

Products Released

In 2020, the total volume of hydrocarbon liquid and produced water released was 66 per cent higher than in 2019 because of three pipeline incidents with greater than 500 m3 of liquids released. Based on liquid release volumes, the top five incidents rated as high consequence in 2020 made up 74 per cent of the total volume of hydrocarbon liquid and produced water released.

Company Liquid volume released (m3) Substance released Incident date Field centre Strike area
1. ARC Resources Ltd. (incident number:* 20202961) 5000 Produced water December 25, 2020 Drayton Valley Pembina
2. Husky Oil Operations Limited
(incident number: 20202516)
714 Produced water October 26, 2020 Grande Prairie Rainbow
3. Ipc Canada Ltd.
(incident number: 20201366)
410.4 Produced water June 13, 2020 Medicine Hat Suffield
4. Bonavista Energy Corporation.
(incident number: 20200717)
379 Produced water March 22, 2020 Red Deer Carol
5. Inter Pipeline Polaris Inc.
(incident number: 20202020)
333 Diluent August 29, 2020 Bonnyville N/A

* Additional information about incidents can be found in the Data section of this report.

Causes and Prevention

Leaks and ruptures are the only two incident types that could have a medium or high consequence rating. We therefore grouped them together into a category called pipeline failures. Of the 344 pipeline incidents that occurred in 2020, 252 were pipeline failures.

All pipeline failures give us an opportunity to see where we can improve pipeline safety.

If a failure occurs, companies must investigate why the failure happened, put in place a plan to prevent it from happening again, and share the details of the investigation and plan with us.

We review every pipeline failure to determine if a company correctly determined the cause and if they followed our pipeline requirements. We also see if there are areas for improvement in the company's pipeline integrity management program. 

Leading Causes of Failures

In 2020, the most common reasons for a pipeline failure were

  • internal corrosion (46%),
  • external corrosion (11%), and
  • construction deficiency (9%).

More than 86 per cent of the pipelines we license are made of steel, which is highly susceptible to corrosion. Effective programs to prevent these pipelines from corroding to an unacceptable level must be in place, and confirming that companies have such a program is a focus of the pipeline inspections and assessments that we do.

Internal Corrosion

Internal corrosion remained the leading type of pipeline failure, representing 46 per cent of all pipeline leaks and ruptures in 2020. More than 74 per cent of internal corrosion failures were on uncoated steel pipelines; the remaining failures were on aluminum or nonmetallic pipelines.

The majority of internal corrosion pipeline failures in 2020 were due to multiple mechanisms of corrosion (34%). The most dominant internal corrosion cause types following that were under deposit corrosion (12%), CO2 corrosion (12%), and microbial-influenced corrosion (10%).

Thirty-three per cent of internal corrosion failures were on pipelines transporting oil-well effluent, which can be attributed to the corrosive agents in these fluids.

When transporting corrosive fluids, companies must develop a program to monitor for corrosion and, where corrosion is occurring, minimize its progression or replace the pipe as required.

Typically, internal corrosion can be mitigated by

  • doing effective cleaning (called "pigging") of pipeline segments to remove solids and debris,
  • using biocide chemical treatments to kill microbial organisms in the pipeline,
  • periodically applying or batching large quantities of a corrosion inhibitor as a protective barrier on the inside of the pipeline,
  • continuously injecting an inhibitor chemical to reduce how corrosive a transported fluid is or to act as a protective barrier on the inside of the pipeline,
  • removing water from the pipeline, and
  • applying a protective internal coating on the inside of the pipeline.

The risk of internal corrosion increases whenever a pipeline has been inactive for long periods of time and not purged, because water and solids left inside a pipeline accelerate the rate of corrosion. Companies must properly clean out inactive pipelines and apply corrosion inhibitors to prevent corrosion from happening whenever a pipeline is to be inactive for a long period of time to preserve it for future use.

External Corrosion

The steel surface on the outside of a pipeline is susceptible to external corrosion, which was the second leading type of pipeline failure in 2020, representing 11 per cent of all failures. Buried pipelines must be externally coated, and these coatings must be inspected before the pipeline can be buried. Any underground steel pipelines must use cathodic protection (a technique using electrical current) to counteract corrosion at areas where the external coating may be compromised. Cathodic protection must be measured periodically to make sure that there's enough current for the whole pipeline.

Most (36%) of the external corrosion pipeline failures in 2020 were because the coatings had disbonded (i.e., no longer adhered to the pipe), preventing the cathodic protection system from being effective. Disbonding can occur due to improper installation, age, or excessive operating temperature. Other key cause types for external corrosion failures were missing or damaged coating on the pipeline (32%) and corrosion under insulation (14%).

Construction Deficiency

In 2020, the third leading type of pipeline failures was construction deficiency (9%). This includes incidents caused by overstressing or improper support or restraint at tie-in points or where the pipeline transitions from below ground to above ground (the riser) (45%) and handling damage on nonmetallic pipelines (27%).

Seventy-three per cent of construction deficiency failures were on nonmetallic pipelines and fifty-eight per cent of those pipelines were carrying oil-well effluent.

Most often, damage during installation is unintentional and results from trying to install nonmetallic pipelines using practices similar to those required for steel pipelines. Nonmetallic pipelines are corrosion-resistant but require careful handling and specific installation practices.

The AER conducts construction inspections focused on ensuring that proper practices are being employed, as well as educating operators about our requirements, industry best practices, and emerging issues around nonmetallic pipeline installation, which is critical in preventing pipeline failures.

Additional Information

Additional data about pipeline performance in Alberta is available in the full workbook.