Strong, rapid (by 2030), and sustained reduction of global anthropogenic methane emissions is a required component of every scenario in the Intergovernmental Panel on Climate Change’s (IPCC) Sixth Assessment Report that sees humanity avoiding the most catastrophic outcomes of climate change1. Along with 148 other countries, Canada has signed on to the Global Methane Pledge2 (GMP) with a promised 30% cut in its methane emissions by 2030, led by a 75% or greater reduction in the oil and gas sector3,4. There are now just six years remaining to achieve this vital goal. New regulations are under development to drive the necessary reductions, but this critical effort is hampered by official bottom-up inventories that are thought to significantly underestimate emissions, and even more critically, by a general lack of accurate data on the breakdown of sources to be mitigated.

The province of Alberta is Canada’s largest producer of oil and gas resources5,6 and largest emitter of oil and gas sector methane, with the official inventory estimating 2.1 times the emissions of the rest of Canada combined7. However, multiple studies using a variety of measurement approaches have pointed to substantial underestimates in both reported emissions and official inventories for Alberta8,9,10,11,12, such that the true magnitude of emissions from the province are likely higher. Most critically, uncertainty on the true breakdown of sources driving emissions creates a fundamental barrier to the development of effective and efficient regulations, which are needed to meet 2030 methane reduction targets13. At the same time, Alberta has been a leader piloting alternative fugitive emissions management plans (Alt-FEMP)14 in place of regulated manual leak detection and repair (LDAR) surveys15 but public data assessing the performance of these programs are lacking and their relative impacts on mitigation and inventories are currently unknown.

The primary objective of this work is to derive and prove a robust, source-resolved methane inventory for conventional (non-oil sands) upstream oil and gas production in Alberta, Canada. Leveraging the capabilities of high-sensitivity LiDAR-based methane detection16,17,18,19, analyzed considering the condition-dependent probability of detection during multi-pass measurements19,20, a measurement-based, source-resolved, hybrid top-down/bottom-up 2021 methane inventory is created. This inventory is directly compared with an independent top-down estimate created from parallel aerial mass-balance21 surveys and a provincial inventory derived from recent satellite measurements in western Canada22. The alignment of all three approaches demonstrates how it is possible to “close the gap” between traditional bottom-up vs. top-down approaches to produce a comprehensive source-resolved inventory that matches independent top-down measurements. A second key objective is to contrast sources in the derived hybrid inventory with those in the most recent official federal inventory. This reveals the key sources driving 2021 methane emissions, where the differences from those assumed in the official bottom-up inventory breakdown have important implications for regulations currently under development. Third, the inventory results are used to calculate methane intensities of produced hydrocarbons, enabling direct comparisons with results from a range of recent studies across North America. Finally, the inventory and detailed uncertainty analysis protocol is applied to quantify and contrast methane intensities of anonymized companies operating comparable upstream oil and gas facilities, consistent with the goals of monitoring, reporting, and verification (MRV) efforts such as the oil and gas methane partnership (OGMP 2.0)23. This reveals order of magnitude differences among companies while demonstrating that independently verified, objectively low methane intensities can be achieved in practice.

Results and discussion

Survey overview

Two independent aerial surveys using unique measurement technologies were performed to quantify oil and gas methane emissions in Alberta during 2021. The primary, source-resolved survey deployed Bridger Photonics Inc.’s Gas Mapping LiDAR (GML) technology16,17 to complete high spatial resolution (~1–2 m) measurements of upstream oil and gas facilities and wells (i.e., sites) within five representative sub-regions of Alberta as detailed below. This survey was led by the Energy and Emissions Research Laboratory (EERL) and was specifically designed to enable creation of a hybrid, source-resolved, measurement-based methane inventory for Alberta following the detailed methodology described by Johnson et al.20. A parallel region-level survey, led by the Environmental Defense Fund (EDF), deployed an aircraft from Scientific Aviation to complete aerial mass-balance flights21 around nine geographically distinct conventional oil and gas production regions within Alberta. These flights enabled an independent estimate of total methane emissions for comparison with the total obtained from the source-resolved inventory. Finally, a third independent total emissions estimate for comparison was derived from the satellite measurements of Shen et al.22 as further detailed below.

Figure 1 shows a map of Alberta identifying all facilities and wells that were active during one or more months of the survey period, September–November 2021. Facilities and wells were deemed active based on volumetric reporting in the public Petrinex database24 (see online supplementary information (SI) for further details and ref. 25 for a glossary of oil and gas terminology) and are coloured according to their inclusion in the source-resolved survey as summarized in the legend. Blue and dashed red polygons in the figure represent the five and nine regions surveyed by Bridger Photonics and Scientific Aviation, respectively. As further described in the Methods section below and in Section S1 of the SI, the facilities and wells within these regions encompassed the diversity of upstream conventional oil and gas activities in Alberta, while excluding “unconventional” mined and in situ oil sands, which were not considered.

Source:  (