No abstract

[1] Variations in the Earth's surface energy balance are recorded in the subsurface as perturbations of the steady state thermal field. Here we invert 558 temperature-depth profiles in the Northern Hemisphere (NH), in order to estimate the energy balance history at the continental surface from heat flux anomalies in the subsurface. The heat gain is spatially variable and does not appear to have been persistent for the last 200 years at all locations, but overall continental areas have absorbed energy in the last 50 years. J for the last 50 and 200 years respectively. We suggest that our results may be useful for state-of-the-art General Circulation Model (GCM) validation and for land-surface coupling schemes.

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.