Updated July 2020
The most common metric for reporting pipeline performance is the number of incidents per 1000 kilometres of pipeline per 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, salt water, or oil-well effluent, may pose a greater risk to the public, wildlife, and the environment.
In 2019, the total volume of hydrocarbon liquid, salt water, and produced water released was 58 per cent higher than in 2018 because of four pipeline incidents with greater than 500 m3 of liquids released. Based on liquid release volumes, the top 5 incidents rated as "high consequence" in 2019 made up 55 per cent of the total volume of hydrocarbon liquid, salt water, and produced water released.
|Company||Liquid volume released (m3)||Substance released||Incident date||Field centre||Strike area|
|1. Razor Energy Corp. (incident number: 20191915)||1200||Produced water||June 26, 2019||Edmonton||Judy Creek|
|2. Torxen Energy Ltd. (incident number: 20193165)||600||Produced water||October 21, 2019||Calgary||Wayne-rosedale|
|3. NuVista Energy Ltd. (incident number: 20192692)||500||Produced water||September 9, 2019||Grande Prairie||Wapiti|
|4. Razor Energy Corp. (incident number: 20190871)||500||Produced water||March 19, 2019||Edmonton||Judy Creek|
|5. Enerplus Corporation (incident number: 20190049)||243||Produced water (238.43 m3) and crude oil (4.87 m3)||January 6, 2019||Wainwright||Provost|
Causes and Prevention
All pipeline failures give us an opportunity to see where we can improve pipeline safety. The AER reviews every pipeline failures to determine what caused the incident and whether the company operating the pipeline followed all of the rules in place for pipelines. Companies must also investigate their own incidents to determine why the failure happened, create and put in place a plan to prevent it from happening again, and share the details with us.
Leading Causes of Failures
In 2019, the most common reasons for a pipeline failure (leak and rupture) were
- internal corrosion (46%),
- external corrosion (12%), and
- construction deficiency (7%).
More than 85 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 inspections and assessments that we do.
Internal corrosion remained the leading type of pipeline failure, representing 46 per cent of all pipeline leaks and ruptures in 2019. More than 80 per cent of internal corrosion failures were on uncoated steel pipelines; the remaining failures were on internally coated pipelines metallic risers (vertical portion of pipeline) and metallic connections on nonmetallic pipelines.
The majority of internal corrosion pipeline failures in 2019 were because of multiple corrosion mechanisms, meaning there were influences from more than one mode of corrosion (42%). The next most dominant internal corrosion failures types were under deposit corrosion (22%), microbial-influenced corrosion (9%), or corrosion under internal coating (5%).
Thirty-five 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.
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.
The steel surface on the outside of a pipeline is susceptible to external corrosion, which was the second leading type of pipeline failure in 2019, representing 12 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 (41%) of the external corrosion pipeline failures in 2019 were because the coatings had disbonded, preventing the cathodic protection system from being effective. Coating damage can occur due to improper installation, age, or excessive operating temperature. Another key contributor to external corrosion failures is missing or damaged coating on the pipeline.
In 2019, the third leading type of pipeline failures was construction deficiency (7%). 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) (50%) and improper joint alignment (14%).
Construction deficiency failures were mostly on nonmetallic pipelines (73%), with the majority of these failures (52%) on nonmetallic oil-well effluent pipelines.
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 data about pipeline performance in Alberta is available in the full workbook.