• Natural Gas News

    Canada takes a harsh line on emissions [NGW Magazine]


As a third producing province gains equivalency with federal methane emission regulations, Canada takes the lead in cutting the most intense of greenhouse gases. [NGW Magazine Volume 5, Issue 13]

by: Dale Lunan

Posted in:

Top Stories, Insights, Premium, NGW Magazine Articles, Volume 5, Issue 13, Carbon, Canada

Canada takes a harsh line on emissions [NGW Magazine]

Canada could have a unified plan in place by the end of the summer to cut methane emissions from upstream oil and gas operations by 45% by 2025. This would fulfil a key part of its Paris climate-change commitment.

Over the next few weeks, Environment and Climate Change Canada (ECCC) will gather comments about a preliminary equivalency agreement with Alberta – the country’s largest producing jurisdiction – that would see regulations set out by the Alberta Energy Regulator (AER) in its Directive 060, released May 12, supersede federal regulations.

ECCC will issue a report summarising those comments after the review period closes on August 5, a department spokesman told NGW, and would then finalise the agreement with an order in council.

Alberta’s and Ottawa’s regulations are being implemented in two stages, the first of which took effect on January 1 this year. It sets overall vent gas limits – with certain exemptions until 2022 and 2023 – and mandates leak detection and repair (LDAR) programmes from three times a year to once yearly to identify fugitive emissions at gas plants, compressor stations, hydrocarbon and produced water storage tanks and other facilities. The second stage, introducing facility-wide venting limits and standards for pneumatic equipment and glycol dehydrators, will take effect on January 1, 2023.

Under the Alberta regulations, overall vent gas volumes will be limited to 15,000 m3/month/site for all sites beginning January 1 this year, with limits reduced to 3,000 m3/month for new sites beginning January 1, 2022; federal regulations limiting general facility production venting to 1,250 m3/month take effect January 1, 2023.

If the equivalency agreement is implemented, federal rules would be waived for the Alberta oil and gas industry, which would instead have to meet the provincial regulations. Similar equivalency agreements are already in place for industry operations in British Columbia and Saskatchewan.

“As we make plans for economic recovery and set a course for our province’s future prosperity, it is critical for industry to have the regulatory certainty needed to operate and further invest in Alberta,” provincial energy minister Sonya Savage said. “This preliminary agreement will give Alberta the ability to achieve methane emission reductions through one of the strongest regulatory systems in the world.”

In 2014, the baseline for Alberta’s regulations, the province’s upstream oil and gas operators were responsible for an estimated 31.4mn mt of CO2-equivalent (mtCO2e) methane emissions. Nationwide, methane accounted for 91mn mtCO2e of Canada’s 729mn mtCO2e of total emissions in 2018, according to Ottawa’s national Greenhouse Gas Inventory (Figure 1). Canada’s energy sector – stationary combustion, transport and fugitive sources – accounted for nearly 82%, or 596mn mtCO2e, of Canada’s total GHG emissions the same year (Figure 2).

Under Alberta’s regulations, cumulative methane emission reductions between 2020 and the end of 2024 would reach 18.6mn mtCO2e, slightly less than the 18.71mn mt projected under federal regulations. Over a 10-year time horizon, reductions under the Alberta rules would reach 57.28mn mtCO2e, slightly more than the 56.48mn mtCO2e under the federal regulations.

“The provincial framework supports a flexible, results-oriented approach to reducing emissions while stimulating technology and innovation essential to meeting our environmental performance goals at this critical time,” the CEO of the Canadian Association of Petroleum Producers (Capp) Tim McMillan said. “Our country has some of the most stringent regulatory standards for methane emissions and our upstream oil and natural gas industry remains committed to achieving the federal methane emissions reduction targets.”

The Florence School of Regulation, which has been studying regulatory initiatives to reduce methane and other GHG emissions, said in a late May report authored by research associate Maria Olczak and senior fellow Andris Piebalgs that the federal regulations employ a “prescriptive or command-and-control” model, which directs operators to take specific actions: replace or repair high-emitting sources, or inspect equipment for methane leaks on a prescribed timetable.

“This approach makes the regulatory overview much easier, but may compromise the flexibility, the overall environmental effect of regulations and may miss the opportunity coming from the technology innovation, such as the use of satellite and aerial measurements to detect and measure methane emissions,” the FSR report suggested.

Alberta’s regulations, Olczak told NGW, are also of the command-and-control type, but certain provisions outlined in the AER’s Directive 060 are more flexible than the federal regulation, especially those relating to technologies that can be used for leak detection.

The federal regulations prescribe just two types of leak detection equipment, either a portable monitoring instrument that meets US Environmental Protection Agency (EPA) specifications or an optical gas-imaging instrument.

Alberta’s rules, on the other hand, allow for three types of leak detection technology: organic vapour analysers that detect hydrocarbons at concentrations of 500 parts/mn; gas imaging cameras; or “other equipment or methods that are equally capable of detecting fugitive emissions. However, the duty holder (operator) must assess equivalency and, upon request by the AER, demonstrate equivalence,” Directive 060 says.

“In other words, this provision opens the possibility to use drones, aircraft or even satellite observations to detect methane emissions, subject to AER’s approval,” Olczak said. “This is a pretty innovative approach, and it [will] be very interesting to see how this provision works in practice.”

Greens not sold

Environmental non-governmental organisations (Engos) – many of which support the federal regulations – have long held that Alberta’s proposed rules fall well short of the federal mandates, and in September 2019 they published a “fact sheet” outlining their concerns.

“Specifically, these criticisms include the Alberta regulation not requiring specific action to reduce emissions from leaks at oil facilities, pneumatics, and storage tanks, as well as failing to update existing measurement and reporting requirements for

solution gas venting,” the ECCC says in its report on the equivalency agreement, while making the point that the Engo criticisms pre-dated updated regulations proposed by Alberta late last year – which are the subject of the preliminary equivalency agreement and which are much more robust that Alberta first proposed.

“Modelling work conducted by the department shows that the Alberta regulation will result in methane reductions that are equivalent to those of the federal regulations over the 2020–

2024 period,” the ECCC says. “These estimates of methane emission reductions were derived using a consistent and robust modelling approach, which has undergone significant consultation with stakeholders dating back to 2016.”

Engos however still want to have a closer look at Alberta’s rules.

“We are looking forward to evaluating the improvements Alberta has made to its methane regulations as it seeks to achieve equivalency with the federal regulation designed to reduce emissions of this especially potent and long-lasting greenhouse gas,” Jan Gorski, senior analyst at the Pembina Institute – a member of the Engo consortium that was critical of Alberta’s initial rules – said early May, before the preliminary equivalency agreement was reached. “As we evaluate Alberta’s proposed changes, to determine if the province’s regulations will reach the required level of stringency, we will be looking for improvements that address shortcomings in leak detection, repair requirements and venting limits and changes to address inaccurate and outdated measurement and reporting requirements that significantly underestimated the venting problem.”

Cost estimates elusive

What has remained elusive, at least since the federal regulations and the first draft of Alberta’s rules were released in 2018, are the costs to industry of methane mitigation.

In posting the preliminary equivalency agreement, ECCC said Alberta’s regulations, designed with the specific characteristics of the Alberta oil and gas industry in mind, would be as stringent as the federal rules. Additionally, implementation of an equivalency agreement, it said, would reduce regulatory overlap and reporting burdens by suspending the federal regulations.

“As a result, the proposed order is expected to result in incremental compliance and administrative cost savings to industry,” the department said.

In a 2019 study, the Canadian Energy Research Institute (Ceri) released a report estimating total methane emissions across the Canadian gas value chain at about 40.4mn mtCO2e in 2017. Alberta, it said, accounted for 24.5mn mtCO2e of that total, with upstream operations – mainly wells and gathering systems – accounting for about 97% of the total Alberta contribution.

Hitting the 45% reduction target by 2025, the Ceri study found, would cost industry between C$1.4bn (US$1bn) and C$2.6bn, and achieve a total reduction of 18mn mtCO2e. Maximising efforts to reduce methane reductions by 35mn mtCO2e, the study said, would cost between C$3.0bn and C$5.5bn.

Canada stands alone

Canada’s actions to reduce methane emissions are part of a tri-partite agreement struck in 2016 by Canada, the US and Mexico to achieve the 40-45% reduction by 2025, but so far, only Canada seems to be making any measurable progress against that target.

Last summer the EPA, acting on an executive order from US president Donald Trump, introduced a proposed rule that would rescind regulations put in place by the preceding Barack Obama administration requiring oil and gas operators in the US to install LDAR technology in all wells, pipelines and methane storage areas.

“The proposal would remove regulatory duplication and save the industry millions of dollars in compliance costs each year – while maintaining health and environmental regulations on oil and gas sources that the agency considers appropriate,” the EPA said at the time. It estimated savings at between $17mn and $19mn annually.

Without a unified national strategy, methane emission reductions in the US are being pursued at the state level – with various degrees of aggression – and voluntarily by the country’s major producers, led by ExxonMobil, which is targeting a 15% reduction in methane emissions by the end of this year.

“Our successful voluntary methane management program includes structured leak detection and repair protocols, prioritised replacement of high-bleed pneumatic devices, technology enhancements to infrastructure and substantial data gathering and research,” the company says. It said that earlier this year it introduced a model framework for industry-wide methane emission reductions that it hoped would be taken up by stakeholders, policy-makers and governments.

It is also working to reduce natural gas flaring – a significant source of methane emissions resulting from inefficient combustion – with the Permian basin as its first target. By installing new equipment to capture emissions, completing new wells only when adequate gas take-away capacity is available, and shutting in production if there is a prolonged mechanical upset, ExxonMobil reduced the flaring intensity in its Delaware and Midland operations of the Permian to 1% in May 2020 from 4.7% in June 2019.

EU looks to Canada

The European Union (EU) first began looking at cutting methane emissions in 1996, when the group’s 15 member states set a target of a 41% reduction by 2010, compared to 1990 levels. Efforts fell short of that target, reaching only a 30% reduction, which was largely achieved by an unexpectedly high level of coal mine closures, the FSR said in April 2019 report.

European Commission president Ursula von der Leyen has since expressed an interest in doubling down on the EU’s GHG reduction target – taking it to as high as 55% by 2030, but to do that, it needs robust methane reduction regulations.

The EU is only now beginning to explore LDAR mandates, Piebalgs told NGW, with a focus on distribution and transmission, since that is where most of the methane emissions come from. And as it develops those regulations, it is looking closely at how Canada’s regulations – relatively rigid by global standards – evolve as new detection and reduction technologies are brought into play.

And the success the gas industry has in staying relevant and controlling methane, Piebalgs said, could define how successful the world is in getting to net-zero by 2050.

“If I see a pathway towards 2050 where you get to a zero emissions economy, you need something that creates the molecules. You could come with renewable electricity and electrolysers to get hydrogen. But you could also get there by just taking natural gas to produce hydrogen and store the CO2 in the ground. That is why for the path forward, gas is in a bit of undefined space, but it is one of the most promising sectors today to cut the greenhouse gas emissions substantially, in a relatively short time and cost-efficiently.”


Montreal-based GHGSat is still awaiting co-operative weather to launch the next generation of its methane monitoring satellite technology, dubbed Iris.

Iris – about the size of a microwave oven – was initially set to ride into orbit June 18 from the Kouru spaceport in French Guiana as part of a multi-satellite deployment package on Arianespace Vega Flight VV16. But high winds and other unstable weather conditions kept the launch grounded through June, and a new launch date has been set for August 17.

Iris is GHGSat’s second greenhouse gas (GHG) monitoring satellite, following Claire, which has performed more than 4,000 observations of CO2 and CH4 (methane) emissions from oil wells in Texas, oil sands facilities in Canada, power plants in Europe, coal mines in China and even rice paddies in Vietnam.

Incorporating lessons learned from Claire, Iris will achieve a ten-fold performance improvement and much higher spatial resolution than her predecessor, with imagery 100 times higher in resolution than any comparable system. Her focus will be primarily on methane emissions, and she will be able to detect emissions from specific sources, such as oil and gas wells, as opposed to regionally-sourced emissions.