AER GRAPPLES WITH LEAK DETECTION PROBLEMS
Cases of human error teach hard lessons as regulator moves forward
Tragedy or comedy of errors?
After reading through the Alberta Energy Regulator’s report into a 2015 leak at a Murphy Oil pipeline, I can’t decide if this case fits neatly into one bucket or the other.
But there are some headslapping elements that led the province’s energy regulator this week to impose a $172,500 administrative penalty against the Arkansas-based company.
The leak itself went undetected for 45 days, despite the pipeline having a leak detection system in place.
More problematic for the AER is that there has been a spate of issues with leak detection systems on other provincially regulated pipelines since 2013.
And these need to stop because, as the regulator likes to say, “Every incident is preventable.”
For Murphy Oil, problems began in March 2015 when the company noticed oil pooling by its three-inch condensate transfer pipeline, about 65 kilometres east of Peace River.
It notified the regulator of a leak of about 1.4-million litres of condensate, which is used to help heavy oil flow within a pipeline.
Murphy estimates the leak took place from mid-January until March 1, 2015.
The pipeline was built around 2010 and had a leak detection system in place, but it didn’t work for a number of reasons catalogued in the regulator’s investigation.
For example, the regulator found “maintenance was not being performed” on the leak detection system.
Most of the receiving diluent meters at the well pads had not been calibrated since October 2012. If properly calibrated and functioning, “the system would have been able to provide early leak detection capabilities,” the AER reported.
“If you’re not calibrating the meters, if you’re not having a qualified instrumentation technician out there on a regular basis calibrating the meters, then the measurement data can potentially be off,” explains Craig Sinclair, Murphy Oil’s director of health, safety and environment in Calgary.
The company’s operations manual indicated that leak detection system tests — training exercises — would be conducted annually.
Yet during interviews with employees, “most of the inter- viewees were not aware that there was a leak detection system in place and were not trained in leak detection.”
“That is a training issue,” Sinclair says bluntly. “We had some of the proper documents in place at the time, but we were not up to speed in training our personnel, which we have since corrected.”
Ultimately, internal corrosion caused the line failure.
Murphy Oil’s manuals called for a work order to be issued each year to evaluate internal corrosion on steel pipelines. However, the AER found “Murphy failed to implement this requirement for three consecutive years.”
From the company’s perspective, Sinclair says the internal corrosion was caused “from basically not following proper protocols.”
In the end, the leak caused damage to soil, vegetation and water on public lands. Sinclair says a lot of reclamation work has been done on the site and he estimates the company has spent about US$35 million to date on the cleanup. The line has been shut down. The company has made a number of changes since then, such as having management present at pipeline integrity meetings in the field, improving the leak detection system, holding regularly scheduled training and creating work orders to track all required maintenance.
“We’ve made significant efforts over the last couple of years to improve our systems, for sure,” adds Sinclair.
But this isn’t the only recorded problem with a pipeline leak detection system in Alberta for producer-operated lines.
In July 2015, Nexen Energy had a pipeline leak at its Long Lake project where about 31,000 barrels of emulsion spilled. The rupture occurred June 11, but wasn’t discovered until July 15 due to issues with the leak detection system, the company has said.
Pengrowth Energy was hit with a $250,000 administrative penalty from the AER after an oil emulsion leak from a pipeline in December 2013 in northern Alberta went undetected for 48 days.
Last July, the energy regulator issued a bulletin that it has investigated 23 pipeline leaks since its inception in mid-2013. In eight cases, improper leak detection was a “significant contributing factor.”
“The main issue the AER is seeing with leak detection systems is that company personnel responsible for leak detection are not sufficiently trained or fail to immediately identify a leak,” said the AER ‘s Monica Hermary in a statement.
The agency has begun to turn up the heat on these issues, with larger fines and more public transparency on provincially regulated pipeline operations.
Last month, the watchdog began publishing an online database that provides a report card on each pipeline operator it regulates and its record of past incidents.
This is a positive step and will let the public compare a company’s spill history against the rest of the industry.
“We’re starting to see the signals from the Alberta Energy Regulator that they’re starting to understand what they need to do to be a proper regulator with the system they have,” says Duncan Kenyon with Pembina Institute.
Ultimately, more transparency and better technology should propel the industry to improve its performance. The AER reports the number of pipeline incidents, such as ruptures and spills, fell by three per cent last year.
These are all moves in the right direction. But human error and mistakes can’t be overlooked either, and hard lessons must be learned from such cases.
Otherwise, we’ll have more leaks, more environmental damage, more fines — and more headaches for a sector that doesn’t need any more problems.