Mobile measurement of methane emissions from natural gas developments in northeastern British Columbia, Canada

Abstract

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 from conventional and unconventional oil and gas production sites in southeastern Saskatchewan, Canada

“…The survey data was analyzed to isolate CH 4 -rich plumes from the varying ambient atmospheric levels using ratios of super-ambient (or 'excess', denoted by 'e') CO 2 and CH 4 (eCO 2 :eCH 4 ). The gas ratio approach has been used previously by Atherton et al (2017), Williams et al (2018), andO'Connell et al (2019), though the most complete explanation is presented in Hurry et al (2016). Ambient atmospheric CO 2 and CH 4 vary spatiotemporally due to factors such as atmospheric stability, land-use types, and topography.…”

“…To account for these natural variations, the method considers the minimum value of each gas within a moving time window to be representative of background levels for that part of the survey. The size of the window is optimized for each survey to account for the respective level of variance (Atherton et al 2017).…”

“…We used kernel density plots of eCO 2 :eCH 4 from aggregated survey data to determine the target excess ratio for oilfield plume detection as in Atherton et al (2017). The selected target ratio for emissions from conventional and unconventional developments was eCO 2 :eCH 4 <135.…”

“…Peischl et al 2016, Peischl et al 2018, and also facility-level inspections (Allen et al 2013, GreenPath Energy Ltd 2016. This work has established that CH 4 inventory estimates for North American developments are sometimes accurate (Karion et al 2015, Peischl et al 2015, and sometimes underestimated (Pétron et al 2012, Karion et al 2013, Peischl et al 2013, Brandt et al 2014, Pétron et al 2014, Atherton et al 2017, Zavala-Araiza et al 2018. On a global basis, the change in CH 4 isotopes over time suggests that CH 4 inventories are underestimated by 20 to 60 percent (Schwietzke et al 2016).…”

Methane emissions from oil and gas production sites in Alberta, Canada

“…Relevant lessons include (i) identification of major emission sources across the natural gas supply chain Zimmerle et al, 2015;Marchese et al, 2015), (ii) proof that high-emitting sources disproportionately account for the majority of emissions (Brandt et al, 2014;Brandt et al, 2016;Omara et al, 2016;Lyon et al, 2016;Zavala-Araiza et al, 2017), and (iii) examples of smart regulations significantly reducing emissions from different sources (e.g., green completions, replacement of high-emitting pneumatic controllers) (Allen et al, 2013;. With a limited number of studies reporting empirical observations of oil and gas methane emissions outside the US -and specifically in Canada - (Johnson et al, 2017;Atherton et al, 2017) the question remains about whether the same emission characteristics found in the US apply elsewhere.…”