Releases and Failures

The most common metric for reporting pipeline performance is the number of incidents per 1000 kilometres of pipeline per year. This metric is useful when comparing companies but does not tell the whole story. A lot goes into determining how a pipeline company performs, and the results might differ depending on the metric used.

For a meaningful comparison of pipeline performance between companies, we must compare companies with similar operations, including the number, size, and type (pipeline materials and substances transported) of pipelines they operate.

We use the following performance metrics:

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

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

The following table summarizes the high consequence incidents for 2023.

Figure 5 shows data by company for each performance metric.

In 2023, the total volume of hydrocarbon liquid and produced water released from pipelines was 150% higher than in 2022. This increase was a result of a single produced water release of 2600 m³. The cause of the release was a pipe body failure on an eight-year-old composite pipeline. Improvements were made to operator leak detection training programs and internal leak indicator systems. The licensee abandoned the pipeline as a result of the failure. The AER requested a third-party review of the licensee’s leak detection program to identify any deficiencies and to implement improvements. Significant improvements were made to the program because of the review. Improvements were also made to the integrity management program. The operator is going to add leak detection events to its emergency response planning, and it continues to look for ways to improve the leak detection program.

Forty-six per cent of composite pipeline failures were ruptures, and composite ruptures resulted in 51% of the total liquid volume released in 2023. Leak detection systems are important for all pipelines; however, they are imperative on composite pipelines because they are effective in minimizing release volumes in the event of a failure. Leak detection programs must be periodically assessed for their adequacy and effectiveness.

The following table lists the top five incidents with the largest release volumes. The top five incidents account for 67% of the total volume of hydrocarbon liquid and produced water released.

* Incident numbers can be used to look up additional information on the Compliance Dashboard.

As a result of any given incident, the AER requires the licensee to identify the causes and gaps in their integrity management programs and to implement improvements to the program.

Figure 6 shows the volume and category of liquids released by year.

Leaks and ruptures are categorized as pipeline failures. Of the 354 pipeline incidents in 2023, 281 were pipeline failures.

If a failure occurs, companies must investigate the cause, implement a plan to prevent it from happening again, and provide us with the details of the investigation and remedial actions.

Leading Causes of Failure

Incidents are categorized by their leading cause of failure. However, it is sometimes difficult to identify the root cause as it could include poor design or poor operations and maintenance. For companies to select a suitable pipeline material, an assessment based on a thorough understanding of the intended service conditions, potential upset conditions, future development or changes in services, temperature and pressure variations, production rates, and other factors is required on a project-by-project basis. In addition, companies must continually monitor and assess their pipelines for these conditions throughout the life of the pipeline.

In 2023, the following were the most common types of pipeline failure:

• internal corrosion (42%)
• pipe body failure (19%)
• external corrosion (9%)
• construction deficiency (7%)
• contact damage (damage by others) (5%)

85% of the pipelines we license are steel pipelines and highly susceptible to corrosion. Effective programs must be in place to monitor and prevent these pipelines from corroding to an unacceptable level – and confirming that companies have such programs is the focus of our pipeline inspections and assessments.

Figure 7 shows the percentage of failure types and a ranking of causes.

Internal Corrosion

In 2023, internal corrosion remained the leading type of pipeline failure, representing 42% of all pipeline leaks and ruptures. This is down 5% from 2022. Ninety per cent of internal corrosion failures were on uncoated steel pipelines, with the remainder occurring on the metallic risers and piping of otherwise non-metallic pipelines. 

In 2023, 42% of pipeline failures from internal corrosion were caused by multiple corrosion mechanisms (called multimechanism corrosion). Other causes of internal corrosion include the following:

• under-deposit corrosion (19%)
• microbiologically influenced corrosion (14%)
• CO₂ corrosion  (6%)
• corrosion under internal coating (5%)

Forty-seven per cent of internal corrosion failures were on pipelines transporting oil-well effluent, which is attributable to the corrosive nature of these fluids and operating conditions.

For pipelines transporting corrosive fluids, companies must develop programs to monitor for corrosion and, where corrosion occurs, minimize its progression, or replace the pipe if needed.

Typically, internal corrosion can be mitigated by the following:

• doing effective cleaning (called "pigging") of pipeline segments to remove solids, water, bacteria, 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 pipe
• continuously injecting an inhibitor chemical to reduce the corrosiveness of the transported fluid or to function as a protective barrier on the inside of the pipe
• removing water from the pipeline or preventing it from entering
• installing pipe with a permanent protective inner coating or a corrosion-resistant liner inside an uncoated steel pipe
• installing polymeric, fibreglass, or spoolable composite pipe

The risk of internal corrosion increases the longer a pipeline is inactive and not purged. Water and solids left inside a pipeline accelerate the rate of corrosion. Companies must properly clean inactive pipelines and apply corrosion inhibitors to prevent corrosion from happening whenever a pipeline is inactive for extended periods to preserve it for future use. When companies bring an inactive pipeline back into operation, an appropriate engineering assessment and pressure test must be done before resumption to ensure the pipeline still has suitable integrity.

Pipe Body Failure

In 2023, pipe body failure (see the glossary) accounted for 19% of pipeline failure types.

In steel pipe, body failure can occur by cracking of the pipe due to its operating environment. For nonmetallic pipelines, body failure can result from a gradual degradation of the pipe material or an overpressure condition.

As composite pipelines age and are exposed to severe operating conditions, there is potential for gradual loss of strength. Operators should be aware of this and manage it as part of their safety and loss management system.

The statistics show a sizable increase in pipe body failure. This is likely because of two factors: more accurate reporting of failure type in composite pipe and a significant number of stress corrosion cracking (SCC) failures in aboveground high-temperature thermal recovery project pipelines. The AER issued Bulletin 2021-36 in 2021 identifying this issue to industry.

External Corrosion

The exterior surface of a steel pipe is susceptible to corrosion if the pipeline does not have an effective protective coating. In 2023, external corrosion accounted for 9% of pipeline failure types.

Buried pipelines must have an external coating that must be inspected before the pipeline is buried. Cathodic protection is required for all underground steel pipelines to counteract corrosion in areas where the external coating may be compromised. Cathodic protection must be periodically measured and maintained to ensure an appropriate current along the entire pipeline.

In 2023, 46% of the external corrosion pipeline failures were caused by the field-applied coating disbonding from the pipe surface, and 15% was caused by missing or damaged coating   Coatings can disbond due to improper installation, aging, or excessive operating temperature. Field applied coatings at welds and repairs and on risers and bends are frequent failure locations for coatings. Disbonded coatings prevent effective cathodic protection at the area where the disbonding occurs, although overall cathodic protection levels on the pipeline may be acceptable.

Older pipelines were often constructed with tape-wrapped coatings, which have a tendency to degrade and disbond over time, as compared to the factory-applied extruded or fusion-bonded coatings that are typically used now.

Construction Deficiency

In 2023, construction deficiency accounted for 7% of pipeline failure types. The leading cause of these incidents (40%) was improper support or restraint at tie-in points or where the pipeline transitions from underground to aboveground through a riser.

About 80% of construction deficiency failures occurred on nonmetallic pipelines, of which 30% carry oil-well effluent.

Damage during installation is usually unintentional and results from installing nonmetallic pipelines using practices like those used for steel pipelines. Nonmetallic pipelines are corrosion resistant but require careful handling and specific installation practices to avoid physical damage and stresses.

Contact Damage

In 2023, there were 35 pipeline incidents related to contact damage during ground disturbance, down from 42 in 2022. First-party hits decreased from 24 in 2022 to 16 in 2023 (a decrease of 33%). 

Additional Information

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

The following resources provide information on pipeline safety practices:

•  “Safe Excavation Near Pipelines” brochure
• Working Around Oil and Gas Pipelines
• Improving Pipeline Safety