PROJECTS
METHANE ACROSS CANADA

Oil and gas developments across Canada are emitting unwanted greenhouse gases into our atmosphere. Our team can detect the presence and origin of these emissions.

METHANE FROM OIL AND GAS

U.S.-based studies have shown that measured energy sector methane emissions (vented, fugitive, flare) are higher than government estimated inventories suggest, due, in part, to occasional “super-emitters”. In Canada, measurements are sparse and more work is needed to quantify an emissions baseline. What is the distribution of super-emitters in Canadian developments? What types of infrastructure emit? At what rate, and at what persistency? Are some developments worse than others?

Policymakers, operators, and NGOs want answers to these questions, so we strung together a ‘xCanada’ emissions measurement initiative, composed of several geographically-defined projects. We received support from about 25 partner companies, regulators, government departments, NGOs, and university partners who all want to reduce methane quickly and sensibly. The funding breakdown: Industry 26%, Industry-Government 52%, Government 7%, Non-Governmental Organizations 15%.

A specialized computing process allowed us to detect small anomalies and to undertake back-trajectory analysis to define the point of emission. We covered a lot of ground quickly between 2016 and 2018, and sampled thousands of wells within a development – much faster than industry’s own tools. We also took a scientific approach that included repetitions, control routes, and defined Minimum Detection Limits (MDLs); all of which helped quantify uncertainties and build data products we can trust. We have published several papers from that work (listed under the Outcomes tab) including a paper on CH₄ inventory in western Canada, and a paper on Environmental Social and Governance (ESG) governance in Alberta.

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QUESTIONS WE ASKED:

Does the frequency of vents and fugitive emissions depend on well class? Well age? Operator size? At what rate is the infrastructure emitting?

Field work – now complete

We have conducted extensive emissions monitoring surveys through upstream oil and gas developments in British Columbia (Montney region of Dawson Creek and Fort St. John), Alberta (Medicine Hat x2; Peace River x2; Lloydminster x3; Red Deer; Rocky Mountain House), Saskatchewan (Bakken; Weyburn-Midale), and New Brunswick (Stoney Creek x2). Maps to the right show driving routes on off-lease roads that we repeated 3-6 times, often over varying seasons. In each development we have repeatedly (2-6 times) sampled air downwind and within 500 m of 1000-3000 wells and facilities. We measure geolocated concentrations of several gases (methane, ethane, hydrogen sulphide, carbon dioxide, carbon isotopic composition of methane), wind speed and direction, temperature, and GPS location data in real-time at one second intervals while we survey.

Analytical procedure

Once back in the lab, we related the gas plumes we measured on-road to upwind infrastructure sources using a geospatial database. Our datasets were robust due to high sample numbers, high degree of replication, the use of control routes as ‘blanks’, and the defined minimum detection limits (high sensitivity). To enhance certainty, we tagged infrastructure as ‘emitting’ only if we have detected anomalies on over half of the survey passes. Our analysis was broken down into two phases. Phase I was used to define; emissions frequency (e.g. wells emitting / wells existing); severity; emissions frequency as a function of infrastructural class, development type, or operator size. Our Phase II analysis products included more refined volumetric inventory estimates, product loss rates (as % of production), and/or methane emissions intensity of oil production. In both phases our focus was on large-scale industry trends. We did not release operator-specific statistics because our sampling routes were determined largely by road access, and we did not design the routes for representative sampling across operators.

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Outcomes

There was five important publications from this work:

1. Montney: This first Phase I analysis manuscript was published as a D-paper in Atmospheric Chemistry and Physics. The good news is that super-emitters were uncommon. The bad news is that we measured emissions from wells more frequently than we expected (about half of well pads), resulting in an emission estimate above the provincial inventory. A ground study using FLIR cameras and bagging/volumetric measurement (the industry-standard technique) was conducted in parallel with the mobile surveys, and although sampled populations were slightly different, statistics were comparable between the mobile and FLIR methods. This study was sponsored by the David Suzuki Foundation.
2. Alberta: This Phase II manuscript published in Elementa compared methane emissions across three contrasting oil and gas developments in Alberta where air issues have been common in recent years. This study was supported by industry. A follow-up study conducted in fall 2017 was made possible through a NSERC CRD grant. This study suggested government estimates of infrastructure affected by incoming regulations may be conservative.
3. Saskatchewan: This Phase II manuscript contrasted emission patterns in the Bakken (unconventional) and Weyburn-Midale (conventional, EOR) oilfields. This is an interesting comparison because the developments are intermixed, contractors are the same and differences are a result in either extraction mode or operator profile. The manuscript was published in 2019 in the International Journal of Greenhouse Gas Control. Emission occurrences and emission rates were substantially lower in comparison to other recent emission studies in Canada and the United States. This study was supported by a combination of industry, government, and a local non-governmental airshed organization.
4. Synthesis: This synthesis paper (2021) applied a more advanced volumetric modelling approach for an industry-wide Canada emissions snapshot. We contrasted developments by metrics like loss rate (gas) and/or methane emissions intensity (oil). The results were published in Scientific Reports. We learned that emissions varied by fluid type and geographic region, with the heavy oil region of Lloydminster ranking highest on both absolute and intensity-based scales. Emission intensities varied widely for natural gas production, where older, low-producing developments such as Medicine Hat, Alberta showed high emission intensities, and newer developments in Montney, British Columbia showed emission intensities that are amongst the lowest in North America. Overall, we estimated that the Canadian upstream oil and gas methane inventory is underestimated by a factor of 1.5, which is consistent with previous studies of individual regions.
5. Environmental, Social, and Governance : Published in 2022 in Cleaner Environmental Systems, this study showed us that methane intensity varied widely among Canadian oil and gas producers and that regulatory submissions comprised only a fraction of emissions. Fifty one percent of Canadian oil and gas producers did not publish ESG (Environmental, Social, Governance) reports. Standardizing ESG reports would improve comparability and reputability.

These datasets offer significant opportunities for re-analysis. In the future we hope to investigate the episodic nature of emissions, summer-winter emission contrasts, and to highlight low-emitting developments, etc. In addition to the above, we’ve also made measurements at seneral oil sands operations, Carbon Capture and Storage sites, legacy wells, and coal operations/shafts in eastern Canada.