Abstract. North American leaders recently committed to reducing methane emissions from the oil and gas sector, but information on current emissions from upstream oil and gas developments in Canada are lacking. This study examined the occurrence of methane plumes in an area of unconventional natural gas development in northwestern Canada. In August to September 2015 we completed almost 8000 km of vehicle-based survey campaigns on public roads dissecting oil and gas infrastructure, such as well pads and processing facilities. We surveyed six routes 3-6 times each, which brought us past over 1600 unique well pads and facilities managed by more than 50 different operators. To attribute onroad plumes to oil-and gas-related sources we used gas signatures of residual excess concentrations (anomalies above background) less than 500 m downwind from potential oil and gas emission sources. All results represent emissions greater than our minimum detection limit of 0.59 g s −1 at our average detection distance (319 m). Unlike many other oil and gas developments in the US for which methane measurements have been reported recently, the methane concentrations we measured were close to normal atmospheric levels, except inside natural gas plumes. Roughly 47 % of active wells emitted methane-rich plumes above our minimum detection limit. Multiple sites that pre-date the recent unconventional natural gas development were found to be emitting, and we observed that the majority of these older wells were associated with emissions on all survey repeats. We also observed emissions from gas processing facilities that were highly repeatable. Emission patterns in this area were best explained by infrastructure age and type. Extrapolating our results across all oil and gas infrastructure in the Montney area, we estimate that the emission sources we located (emitting at a rate > 0.59 g s −1 ) contribute more than 111 800 t of methane annually to the atmosphere. This value exceeds reported bottom-up estimates of 78 000 t of methane for all oil and gas sector sources in British Columbia. Current bottomup methods for estimating methane emissions do not normally calculate the fraction of emitting oil and gas infrastructure with thorough on-ground measurements. However, this study demonstrates that mobile surveys could provide a more accurate representation of the number of emission sources in an oil and gas development. This study presents the first mobile collection of methane emissions from oil and gas infrastructure in British Columbia, and these results can be used to inform policy development in an era of methane emission reduction efforts.

Methane emissions were measured at 6650 sites across six major oil and gas producing regions in Canada to examine regional emission trends, and to derive an inventory estimate for Canada’s upstream oil and gas sector. 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 estimate 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.

Aggressive reductions of oil and gas sector methane, a potent greenhouse gas, have been proposed in Canada. Few large-scale measurement studies have been conducted to confirm a baseline. This study used a vehicle-based gas monitoring system to measure fugitive and vented gas emissions across Lloydminster (heavy oil), Peace River (heavy oil/bitumen), and Medicine Hat (conventional gas) developments in Alberta, Canada. Four gases (CO2, CH4, H2S, C2H6), and isotopic δ13CCH4 were recorded in real-time at 1 Hz over a six-week field campaign. We sampled 1,299 well pads, containing 2,670 unique wells and facilities, in triplicate. Geochemical emission signatures of fossil fuel-sourced plumes were identified and attributed to nearby, upwind oil and gas well pads, and a point-source gaussian plume dispersion model was used to quantify emissions rates. Our analysis focused exclusively on well pads where emissions were detected >50% of the time when sampled downwind. Emission occurrences and rates were highest in Lloydminster, where 40.8% of sampled well pads were estimated to be emitting methane-rich gas above our minimum detection limits (m = 9.73 m3d–1). Of the well pads we found to be persistently emitting in Lloydminster, an estimated 40.2% (95% CI: 32.2%–49.4%) emitted above the venting threshold in which emissions mitigation under federal regulations would be required. As a result of measured emissions being larger than those reported in government inventories, this study suggests government estimates of infrastructure affected by incoming regulations may be conservative. Comparing emission intensities with available Canadian-based research suggests good general agreement between studies, regardless of the measurement methodology used for detection and quantification. This study also demonstrates the effectiveness in applying a gaussian dispersion model to continuous mobile-sourced emissions data as a first-order leak detection and repair screening methodology for meeting regulatory compliance.

Energy development in southeastern Saskatchewan, Canada, is unique because conventional and unconventional oil and gas production is co-located. Mobile surveys are ideal for understanding emissions in this area because the overlap of production makes it difficult for airborne or satellitebased methods to differentiate emissions from each type of infrastructure. In this study, we conducted truck-based mobile surveys in the unconventional Canadian Bakken and conventional Weyburn-Midale fields to enumerate and attribute individual methane plumes, estimate methane (CH 4 ) emission rates, and compare emission vectors. We sampled downwind of 645 conventional and 289 unconventional sites, covering over 4500 km of public roads. We found that 28% of surveyed conventional sites were emitting, compared to 32% of surveyed unconventional sites. Mean emissions intensities in each development were 20 m 3 CH 4 /day per conventional site and 59 m 3 CH 4 /day per unconventional site. Emissions intensities in southeastern Saskatchewan fall on the lower range of other emissions estimates from developments in the US and Canada.

<p><strong>Abstract.</strong> North American leaders recently committed to reducing methane emissions from the oil and gas sector, but information on current emissions from Canadian unconventional developments is lacking. This study examined the incidence of methane in an area of unconventional natural gas development in northwestern Canada. In August to September 2015 we completed almost 8000 km of vehicle-based survey campaigns on public roads dissecting developments that mainly access the Montney formation in northeastern British Columbia. Six survey routes were repeated 3–6 times and brought us past over 1600 unique well pads and facilities developed by more than 50 different operators. To attribute on-road plumes to infrastructural sources we used gas signatures of residual excess concentrations (anomalies above background) less than 500 m downwind from infrastructural sources. All results represent emissions greater than our minimum detection limit of 0.59 g/s at our average detection distance (319 m). Unlike many other developments in the US for which methane measurements have been reported recently, the methane concentrations we measured at surface were close to normal atmospheric levels, except inside natural gas plumes. Roughly 47 % of active wells emitted methane-rich plumes above our minimum detection limit. Abandoned and under-development well sites also emitted methane-rich plumes, but the incidence rate was below that of producing wells. Multiple sites that pre-date the recent unconventional Montney development were found to be emitting, and in general we observed that older infrastructure tended to emit more often (per unit) with comparable severity in terms of measured excess concentrations on-road. We also observed emissions from facilities of various types that were highly repeatable. Emission patterns in this area were best explained by infrastructure age and type. Extrapolating our results across the Montney development, we estimate that the emission sources we located (emitting at a rate > 0.59 g/s) contribute more than 111,800 tonnes of methane annually to the atmosphere. This value exceeds reported bottom-up estimates of 78,000 tonnes for all oil and gas sector sources in British Columbia, of which the Montney represents about 55 % of production. The results also demonstrate that mobile surveys could be used to exhaustively screen developments for super-emitters, because without our intensive 6-fold replication we could have used single-pass sampling to screen 80 % of Montney-related infrastructure. This is the first bottom-up study of fugitive emissions in the Canadian energy sector, and these results can be used to inform policy development in an era of methane emission reduction efforts.</p>

No abstract

<div>Methane emissions were measured at ~7000 sites across major oil and gas producing regions in Canada to examine regional emission trends, and to derive an inventory estimate for Canada’s upstream oil and gas sector. 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 showed high emission intensities, and where emissions intensity in newer developments was amongst the lowest in North America. Emissions from offshore production were in-line with reported estimates. When allocated to individual producers, we found that methane emissions intensity varied more than 1000-fold as determined by geographical factors and infrastructure portfolio. Reporting and disclosure frameworks in Canada are improving but we found that producers could easily under-report emissions and emissions intensity if relying only on regulatory requirements. Overall, we estimate 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. </div>