A leaky endeavor: Considerable amounts of the greenhouse gas methane leak from the U.S. oil and natural gas supply chain. Alvarez et al. reassessed the magnitude of this leakage and found that in 2015, supply chain emissions were ∼60% higher than the U.S. Environmental Protection Agency inventory estimate. They suggest that this discrepancy exists because current inventory methods miss emissions that occur during abnormal operating conditions. These data, and the methodology used to obtain them, could improve and verify international inventories of greenhouse gases and provide a better understanding of mitigation efforts outlined by the Paris Agreement. Science , this issue p. 186

Using new satellite observations and atmospheric inverse modeling, we report methane emissions from the Permian Basin, which is among the world’s most prolific oil-producing regions and accounts for >30% of total U.S. oil production. Based on satellite measurements from May 2018 to March 2019, Permian methane emissions from oil and natural gas production are estimated to be 2.7 ± 0.5 Tg a⁻¹, representing the largest methane flux ever reported from a U.S. oil/gas-producing region and are more than two times higher than bottom-up inventory-based estimates. This magnitude of emissions is 3.7% of the gross gas extracted in the Permian, i.e., ~60% higher than the national average leakage rate. The high methane leakage rate is likely contributed by extensive venting and flaring, resulting from insufficient infrastructure to process and transport natural gas. This work demonstrates a high-resolution satellite data–based atmospheric inversion framework, providing a robust top-down analytical tool for quantifying and evaluating subregional methane emissions.

Methane (CH₄) emissions from oil and natural gas (O&NG) systems are an important contributor to greenhouse gas emissions. In the United States, recent synthesis studies of field measurements of CH₄emissions at different spatial scales are ~1.5–2× greater compared to official greenhouse gas inventory (GHGI) estimates, with the production-segment as the dominant contributor to this divergence. Based on an updated synthesis of measurements from component-level field studies, we develop a new inventory-based model for CH₄emissions, for the production-segment only, that agrees within error with recent syntheses of site-level field studies and allows for isolation of equipment-level contributions. We find that unintentional emissions from liquid storage tanks and other equipment leaks are the largest contributors to divergence with the GHGI. If our proposed method were adopted in the United States and other jurisdictions, inventory estimates could better guide CH₄mitigation policy priorities.

There is a need for continued assessment of methane (CH₄) emissions associated with natural gas (NG) production, especially as recent advancements in horizontal drilling combined with staged hydraulic fracturing technologies have dramatically increased NG production (we refer to these wells as “unconventional” NG wells). In this study, we measured facility-level CH₄ emissions rates from the NG production sector in the Marcellus region, and compared CH₄ emissions between unconventional NG (UNG) well pad sites and the relatively smaller and older “conventional” NG (C_vNG) sites that consist of wells drilled vertically into permeable geologic formations. A top-down tracer-flux CH₄ measurement approach utilizing mobile downwind intercepts of CH₄, ethane, and tracer (nitrous oxide and acetylene) plumes was performed at 18 C_vNG sites (19 individual wells) and 17 UNG sites (88 individual wells). The 17 UNG sites included four sites undergoing completion flowback (FB). The mean facility-level CH₄ emission rate among UNG well pad sites in routine production (18.8 kg/h (95% confidence interval (CI) on the mean of 12.0—26.8 kg/h)) was 23 times greater than the mean CH₄ emissions from C_vNG sites. These differences were attributed, in part, to the large size (based on number of wells and ancillary NG production equipment) and the significantly higher production rate of UNG sites. However, C_vNG sites generally had much higher production-normalized CH₄ emission rates (median: 11%; range: 0.35—91%) compared to UNG sites (median: 0.13%, range: 0.01—1.2%), likely resulting from a greater prevalence of avoidable process operating conditions (e.g., unresolved equipment maintenance issues). At the regional scale, we estimate that total annual CH₄ emissions from 88 500 combined C_vNG well pads in Pennsylvania and West Virginia (660 Gg (95% CI: 500 to 800 Gg)) exceeded that from 3390 UNG well pads by 170 Gg, reflecting the large number of C_vNG wells and the comparably large fraction of CH₄ lost per unit production. The new emissions data suggest that the recently instituted Pennsylvania CH₄ emissions inventory substantially underestimates measured facility-level CH₄ emissions by >10—40 times for five UNG sites in this study.

Facility-level methane emissions were measured at 114 gathering facilities and 16 processing plants in the United States natural gas system. At gathering facilities, the measured methane emission rates ranged from 0.7 to 700 kg per hour (kg/h) (0.6 to 600 standard cubic feet per minute (scfm)). Normalized emissions (as a % of total methane throughput) were less than 1% for 85 gathering facilities and 19 had normalized emissions less than 0.1%. The range of methane emissions rates for processing plants was 3 to 600 kg/h (3 to 524 scfm), corresponding to normalized methane emissions rates <1% in all cases. The distributions of methane emissions, particularly for gathering facilities, are skewed. For example, 30% of gathering facilities contribute 80% of the total emissions. Normalized emissions rates are negatively correlated with facility throughput. The variation in methane emissions also appears driven by differences between inlet and outlet pressure, as well as venting and leaking equipment. Substantial venting from liquids storage tanks was observed at 20% of gathering facilities. Emissions rates at these facilities were, on average, around four times the rates observed at similar facilities without substantial venting.

Reducing methane emissions from fossil fuel exploitation (oil, gas, coal) is an important target for climate policy, but current national emission inventories submitted to the United Nations Framework Convention on Climate Change (UNFCCC) are highly uncertain. Here we use 22 months (May 2018-Feb 2020) of satellite observations from the TROPOMI instrument to better quantify national emissions worldwide by inverse analysis at up to 50 km resolution. We find global emissions of 62.7 ± 11.5 (2σ) Tg a⁻¹ for oil-gas and 32.7 ± 5.2 Tg a⁻¹ for coal. Oil-gas emissions are 30% higher than the global total from UNFCCC reports, mainly due to under-reporting by the four largest emitters including the US, Russia, Venezuela, and Turkmenistan. Eight countries have methane emission intensities from the oil-gas sector exceeding 5% of their gas production (20% for Venezuela, Iraq, and Angola), and lowering these intensities to the global average level of 2.4% would reduce global oil-gas emissions by 11 Tg a⁻¹ or 18%.