Methane Leaks from North American Natural Gas Systems

Temporal patterns and influences of monthly, seasonal and annual temperatures on methane emissions in Greece, Armenia and Russia over two decades

This study explores methane emission trends across Greece, Armenia, and Rostov Oblast region of Russia from 2004 to 2023. Our analyses, based on remote sensing and advanced statistical techniques, showed a 1.3-1.8 °C increase in mean annual temperature over this 20-year period in all these three regions, with the highest and the lowest rates of annual warming in Armenia (0.104 °C) and Rostov Oblast of Russia (0.052 °C), respectively. Mean annual methane concentrations increased distinctly in these regions over this period. Greece showed the trend of highest correlations between methane emissions and temperatures, including mean annual and seasonal temperatures, highlighting substantial role of climate change in emission trends. The emission trends with on-ground observations revealed intricate connections between reduced precipitations, farming practices, waste disposal methods, and naturally occurring emissions in Greece. In contrast, Armenia exhibited weak correlations between temperature and methane emissions, with its farming, waste management, energy and manufacturing sectors playing a significant role in determining emission quantities. The Rostov Oblast of Russia demonstrated weaker association between methane emissions and temperatures than Greece and Armenia, with emission trends being primarily shaped by agricultural activities and natural discharges from wetlands. The forecast models predicted further rise in methane emissions over the 7-year period (2024-2030), with the highest elevation rate estimated for Russia. This study emphasizes the need for tailored mitigation strategies to address methane emissions effectively, considering region-specific factors. Advanced monitoring technologies provide crucial insights into the assessment and management of methane emissions in these diverse geomorphological regions.

Relating Multi-Scale Plume Detection and Area Estimates of Methane Emissions: A Theoretical and Empirical Analysis

Surface emissions of atmospheric trace gases like methane are typically inferred through two methodologies: plume detection and area-scale estimation. Integrating these methods can enhance emission monitoring but remains challenging due to irregular sampling, variable detection sensitivities, and differing spatial resolutions among plume-detecting instruments. In this study, we develop a theoretical framework to link plume-scale and area-scale emission estimates for regions with dense point-source emissions. Our analysis demonstrates that the spatial resolution of plume-detecting instruments influences the observed distribution of plume emission rates. Empirical tests using oil and gas emissions data from the Permian Basin reveal a robust linear relationship between summed gridded plume emission rates and area-scale estimates. After accounting for variability in sampling of the plume detectors, area-scale estimates derived from TROPOMI flux inversions strongly correlate with weekly plume sums (R2 > 0.94, P < 0.005). We also assess the feasibility of using plume data to inform area-scale estimates within a Bayesian assimilation framework and find that plume assimilation improves the constant EDF inventory, bringing it into agreement with independent TROPOMI-derived emission estimates. This work highlights that, given sufficient sampling and favorable observational conditions, plume observations from aircraft, satellites, and in situ instruments can inform and enhance area-scale methane emission estimates, particularly within the oil and gas sector.

Measurements of organic compound emissions from a produced water disposal vault

We measured organic compound emissions from a produced-water, evaporative disposal facility's oil-water separation vault in May 2022 and March-May 2023. Produced water is water pulled from the subsurface of a well along with the oil and natural gas; some produced water is disposed of by allowing it to evaporate from surface impoundments. The vault measured in this study separated residual oil from produced water before evaporative disposal. Because the vault's surface contained many potential small emission sources, we used a large plastic chamber to cover the entire vault and simultaneously capture all emissions. We also measured organic compounds in ambient air upwind and downwind of the vault and estimated emissions via a backward Lagrangian stochastic model (Windtrax). The total non-methane organic compound (TNMOC) emission rate from the vault ranged from 0.27 to 3.05 kg/h, averaging 1.99 kg/h in 2022 and 0.49 kg/h in 2023. The average TNMOC emission rate determined by the bLS method was 48% higher than the emission rate determined by the chamber method in 2023 (average of 0.73 kg/h). Still, the range of the chamber results fell within the range of TNMOC emissions from the model. Methanol emissions were much higher than the bLS method, averaging 85.3 g/hr, but were highly variable. We surmise that the water condensation on the chamber retained methanol and biased the results low. The extrapolated annual average emissions of methane, TNMOC, and methanol from the vault were 0.1, 15.5, and 1.4 U.S. tons/yr, respectively, within the range of emissions from uncontrolled oil storage tanks. The extrapolation considers bias in the chamber method and differences across the two years of measurements.Implications: The findings from our study indicate that emissions of non-methane organic compounds (TNMOC) from the oil-water separation vault at the produced-water evaporative disposal facility exhibit significant variability between years, with a notable decline in average emissions from 2022 to 2023. The higher emission rates recorded using the backward Lagrangian stochastic (bLS) model compared to the chamber method suggest that further investigation into measurement techniques is warranted to ensure accurate assessments of emissions. Additionally, the substantial variability in methanol emissions highlights the need for more controlled conditions during sampling to avoid potential biases. Overall, these results imply that while emissions from the vault are within the range of those from uncontrolled oil storage tanks, there is an ongoing necessity for improved monitoring and regulatory practices to mitigate environmental impacts associated with produced water disposal.

Ozone management in Colorado: Why aren't we there yet?

Since 2004, the state of Colorado in the United States of America has created multiple nonattainment State Implementation Plans (SIPs) that are supposed to comprise air pollution mitigation actions, that have so far been unsuccessful at ensuring Front Range Communities have reduced ozone levels to below the United States Environmental Protection Agency (EPA) standards. By interviewing eight stakeholders and decision-makers involved in ozone SIP rulemaking and drawing on secondary literature, this paper examines shortcomings in the SIP process in Colorado. We found that ozone precursor measurement and the modeling of attainment could be improved by better factoring in uncertainties in emissions inventories and conducting appropriate sensitivity analyses that would require more investment of state staff time and resources. Structural issues with the way the process is organized in Colorado limit optimum overlap between state: Air Pollution Control Division (APCD) and quasi-state: Regional Air Quality Council (RAQC) agencies during the SIP process. Specifically, although the RAQC is currently charged with developing and submitting SIPs to the State for approval, it does not have the power to implement control strategies for several key sources and therefore does not have the authority to propose key policies to be included in the SIP. In recent years, Colorado SIPs have largely focused on the bare minimum emissions controls to demonstrate attainment via modeling. Interviewees recommend that state political leaders take more of a leadership role to lower ground-level ozone levels and bring the Denver Metropolitan Area/North Front Range back into attainment with EPA standards.Implications: We evaluate why the State Implementation Plan (SIP) process has failed to achieve the attainment of the ozone standards in the Denver Metropolitan and North Front Range Area. Specifically, through interviewing several experts we identified several problems, namely: 1) errors in emissions inventories and modeling of ozone levels that have resulted in incorrect determinations that the ozone standards would be met with proposed emissions controls, and 2) structural problems in the way the SIP process is organized in Colorado, and the lack of political leadership.

Structural shifts in China's oil and gas CH4 emissions with implications for mitigation efforts

Methane (CH4) is a potent and short-lived climate pollutant, with the oil and gas sectors emerging as an important contributor. China exhibited a substantial expansion of oil and gas infrastructures over recent years, but the CH4 emission accounting tends to be incomplete and uncertain. Here, we construct a CH4 emission database of China's oil and gas systems from 1990-2022 with 80% of emissions tracked as refineries, facilities, pipelines, and field sources. Results show that China's oil and gas CH4 emissions have risen from 0.5[0.5-0.6] TgCH4 yr-1 in 1990 to 4.0[3.7-4.4] TgCH4 yr-1 in 2022, primarily driven by the growing demand for natural gas during the energy transition. The spatial details provided are critical for characterizing emission hotspots, especially in unconventional gas production fields and densely populated eastern regions. This long-time series and spatially explicit CH4 emission database can contribute to informed policy decisions and swift climate action.

Innovative drone-based methodology for quantifying methane emissions from landfills

An accurate measurement of anthropogenic methane emissions is essential for improving the representation of greenhouse gas inventories and for mitigating the effects of climate change. Often, theoretical models overestimate actual emission values, while field measurements tend to be costly and/or labour-intensive. Landfills represent an important emission sector, necessitating continued investment in innovation and technology to limit fugitive emissions, particularly of methane. This study presents a novel method based on a mass balance approach to estimate fugitive methane emissions from landfills and has been tested at a solid waste landfill in Italy. Measurements were acquired using a drone equipped with a sensor, completed in just a few minutes and processed directly in the field. Results from two tests conducted a month apart are provided, each consisting of two downwind flights at the site. Emission rates varied from 320 ± 280 mg m-2h-1 to 578 ± 385 mg m-2h-1. The data was subsequently compared with the results obtained using the flux chamber method during the second test, highlighting values that were 2 to 4 times higher than those from the ground-based method. The findings of this study highlight the potential of UAV-based methodologies for measuring methane emissions compared to traditional methods. The speed of execution and processing is indeed crucial to providing accurate data and optimising both timings and flight models during an investigation.

Controllable surface carrier type of metal oxide nanocrystals for multifunctional photocatalysis

Selectively harnessing photo-induced carriers to control surface photo-redox reactions can enable currently limited specificity in photocatalytic applications. By using a new approach to switching between dominant electron and hole charge transfer on the surfaces of metal oxide nanocrystals, depending on the optimal carrier for specific application functionality in photocatalytic pollutant degradation, H2 production, CO2 reduction, and gas sensing. The approach is based on the surface redox properties of custom-designed p-n hetero-structured hybrid nanoparticles (NPs) containing copper oxide, and wide-gap metal oxide semiconductors (MOSs). The customized CuxO/ZnO (CXZ) heterostructures ensure effective charge separation and surface reactions driven by UV-vis excited highly reactive holes and show high performance in the photo-oxidative degradation of organic dyes and NO2 gas sensing. By switching the dominant surface carrier type from holes to electrons, the hybrids exhibit excellent performance in photocatalytic H2 evolution and CO2 reduction. This work offers a generic approach to engineering multipurpose photocatalytic materials.

A Deep Learning Based Framework to Identify Undocumented Orphaned Oil and Gas Wells from Historical Maps: A Case Study for California and Oklahoma

Undocumented Orphaned Wells (UOWs) are wells without an operator that have limited or no documentation with regulatory authorities. An estimated 310,000 to 800,000 UOWs exist in the United States (US), whose locations are largely unknown. These wells can potentially leak methane and other volatile organic compounds to the atmosphere, and contaminate groundwater. In this study, we developed a novel framework utilizing a state-of-the-art computer vision neural network model to identify the precise locations of potential UOWs. The U-Net model is trained to detect oil and gas well symbols in georeferenced historical topographic maps, and potential UOWs are identified as symbols that are further than 100 m from any documented well. A custom tool was developed to rapidly validate the potential UOW locations. We applied this framework to four counties in California and Oklahoma, leading to the discovery of 1301 potential UOWs across >40,000 km2. We confirmed the presence of 29 UOWs from satellite images and 15 UOWs from magnetic surveys in the field with a spatial accuracy on the order of 10 m. This framework can be scaled to identify potential UOWs across the US since the historical maps are available for the entire nation.

Robust Two-Dimensional Hydrogen-Bonded Organic Framework for Efficient Separation of C1-C3 Alkanes

Separating natural gas to obtain high-quality C1-C3 alkanes is an imperative process for supplying clean energy sources and high valued petrochemical feedstocks. However, developing adsorbents which can efficiently distinguish CH4, C2H6, and C3H8 molecules remains challenging. We herein report an ultra-stable layered hydrogen-bonded framework (HOF-NBDA), which features differential affinities and adsorption capacities for CH4, C2H6, and C3H8 molecules, respectively. Breakthrough experiments on ternary component gas mixture show that HOF-NBDA can achieve efficient separation of CH4/C2H6/C3H8 (v/v/v, 85/7.5/7.5). More importantly, HOF-NBDA can realize efficient C3H8 recovery from ternary CH4/C2H6/C3H8 gas mixture. After one cycle of breakthrough, 70.9 L·kg-1 of high-purity (≥ 99.95%) CH4 and 54.2 L·kg-1 of C3H8 (purity ≥99.5%) could be obtained. Furthermore, excellent separation performance under different flow rates, temperatures, and humidities could endow HOF-NBDA an ideal adsorbent for the future natural gas purification.

Catalytic Heaters at Oil and Gas Sites May be a Significant yet Overlooked Seasonal Source of Methane Emissions

Successful reduction of oil and gas sector methane emissions to meet near-zero intensity targets requires the identification and mitigation of all possible sources. One potentially important source is catalytic heaters, which have largely escaped attention in regulatory and mitigation efforts despite being ubiquitous at upstream production sites in cold climate regions. This study reports direct in situ measurements of the exhaust streams of 38 natural gas-fired catalytic heaters at upstream production sites in British Columbia, Canada. All heaters in the sample showed consistently poor methane conversion with mean destruction efficiencies of 61 ± 5% while releasing 235 [+31/-28] g of methane per cubic meter of fuel. Although individual units are generally small methane sources (mean of 0.28 ± 0.04 kg/h), their prevalence means they could represent 6% of the total provincial upstream methane inventory and as an aggregate methane source could be 5× more significant than abandoned wells. Notably, these heaters are seasonal sources whose emissions would be missed in measurement campaigns occurring solely in summer months. However, additional measurements from a small number of heat medium burners demonstrate that, where feasible, methane emissions can be reduced by approximately 425× by replacing catalytic heaters with centralized heat systems.

Assessing the Progress of the Performance of Continuous Monitoring Solutions under a Single-Blind Controlled Testing Protocol

The recent regulatory spotlight on continuous monitoring (CM) solutions and the rapid development of CM solutions have demanded the characterization of solution performance through regular, rigorous testing using consensus test protocols. This study is the second known implementation of such a protocol involving single-blind controlled testing of 9 CM solutions. Controlled releases of rates (6-7100 g) CH4/h over durations (0.4-10.2 h) under a wind speed range of (0.7-9.9 m/s) were conducted for 11 weeks. Results showed that 4 solutions achieved method detection limits (DL90s) within the tested emission rate range, with all 4 solutions having both the lowest DL90s (3.9 [3.0, 5.5] kg CH4/h to 6.2 [3.7, 16.7] kg CH4/h) and false positive rates (6.9-13.2%), indicating efforts at balancing low sensitivity with a low false positive rate. These results are likely best-case scenario estimates since the test center represents a near-ideal upstream field natural gas operation condition. Quantification results showed wide individual estimate uncertainties, with emissions underestimation and overestimation by factors up to >14 and 42, respectively. Three solutions had >80% of their estimates within a quantification factor of 3 for controlled releases in the ranges of [0.1-1] kg CH4/h and > 1 kg CH4/h. Relative to the study by Bell et al., current solutions performance, as a group, generally improved, primarily due to solutions from the study by Bell et al. that were retested. This result highlights the importance of regular quality testing to the advancement of CM solutions for effective emissions mitigation.

Modelling spatial & temporal variability of air pollution in an area of unconventional natural gas operations

Despite the growing unconventional natural gas production industry in northeastern British Columbia, Canada, few studies have explored the air quality implications on human health in nearby communities. Researchers who have worked with pregnant women in this area have found higher levels of volatile organic compounds (VOCs) in the indoor air of their homes associated with higher density and closer proximity to gas wells. To inform ongoing exposure assessments, this study develops land use regression (LUR) models to predict ambient air pollution at the homes of pregnant women by using natural gas production activities as predictor variables. Using the existing monitoring network, the models were developed for three temporal scales for 12 air pollutants. The models predicting monthly, bi-annual, and annual mean concentrations explained 23%-94%, 54%-94%, and 73%-91% of the variability in air pollutant concentrations, respectively. These models can be used to investigate associations between prenatal exposure to air pollutants associated with natural gas production and adverse health outcomes in northeastern British Columbia.

Point Sensor Networks Struggle to Detect and Quantify Short Controlled Releases at Oil and Gas Sites

This study evaluated multiple commercially available continuous monitoring (CM) point sensor network (PSN) solutions under single-blind controlled release testing conducted at operational upstream and midstream oil and natural gas (O&G) sites. During releases, PSNs reported site-level emission rate estimates of 0 kg/h between 38 and 86% of the time. When non-zero site-level emission rate estimates were provided, no linear correlation between the release rate and the reported emission rate estimate was observed. The average, aggregated across all PSN solutions during releases, shows 5% of the mixing ratio readings at downwind sensors were greater than the site's baseline plus two standard deviations. Four of seven total PSN solutions tested during this field campaign provided site-level emission rate estimates with the site average relative error ranging from -100% to 24% for solution D, -100% to -43% for solution E, -25% for solution F (solution F was only at one site), and -99% to 430% for solution G, with an overall average of -29% across all sites and solutions. Of all the individual site-level emission rate estimates, only 11% were within ±2.5 kg/h of the study team's best estimate of site-level emissions at the time of the releases.

Increased methane emissions from oil and gas following the Soviet Union's collapse

Global atmospheric methane concentrations rose by 10 to 15 ppb/y in the 1980s before abruptly slowing to 2 to 8 ppb/y in the early 1990s. This period in the 1990s is known as the "methane slowdown" and has been attributed in part to the collapse of the former Soviet Union (USSR) in December 1991, which may have decreased the methane emissions from oil and gas operations. Here, we develop a methane plume detection system based on probabilistic deep learning and human-labeled training data. We use this method to detect methane plumes from Landsat 5 satellite observations over Turkmenistan from 1986 to 2011. We focus on Turkmenistan because economic data suggest it could account for half of the decline in oil and gas emissions from the former USSR. We find an increase in both the frequency of methane plume detections and the magnitude of methane emissions following the collapse of the USSR. We estimate a national loss rate from oil and gas infrastructure in Turkmenistan of more than 10% at times, which suggests the socioeconomic turmoil led to a lack of oversight and widespread infrastructure failure in the oil and gas sector. Our finding of increased oil and gas methane emissions from Turkmenistan following the USSR's collapse casts doubt on the long-standing hypothesis regarding the methane slowdown, begging the question: "what drove the 1992 methane slowdown?"

Temporal Variation and Persistence of Methane Emissions from Shallow Water Oil and Gas Production in the Gulf of Mexico

Methane emissions from the oil and gas supply chain can be intermittent, posing challenges for monitoring and mitigation efforts. This study examines shallow water facilities in the US Gulf of Mexico with repeat atmospheric observations to evaluate temporal variation in site-specific methane emissions. We combine new and previous observations to develop a longitudinal study, spanning from days to months to almost five years, evaluating the emissions behavior of sites over time. We also define and determine the chance of subsequent detection (CSD): the likelihood that an emitting site will be observed emitting again. The average emitting central hub in the Gulf has a 74% CSD at any time interval. Eight facilities contribute 50% of total emissions and are over 80% persistent with a 96% CSD above 100 kg/h and 46% persistent with a 42% CSD above 1000 kg/h, indicating that large emissions are persistent at certain sites. Forward-looking infrared (FLIR) footage shows many of these sites exhibiting cold venting. This suggests that for offshore, a low sampling frequency over large spatial coverage can capture typical site emissions behavior and identify targets for mitigation. We further demonstrate the preliminary use of space-based observations to monitor offshore emissions over time.

US oil and gas system emissions from nearly one million aerial site measurements

As airborne methane surveys of oil and gas systems continue to discover large emissions that are missing from official estimates1-4, the true scope of methane emissions from energy production has yet to be quantified. We integrate approximately one million aerial site measurements into regional emissions inventories for six regions in the USA, comprising 52% of onshore oil and 29% of gas production over 15 aerial campaigns. We construct complete emissions distributions for each, employing empirically grounded simulations to estimate small emissions. Total estimated emissions range from 0.75% (95% confidence interval (CI) 0.65%, 0.84%) of covered natural gas production in a high-productivity, gas-rich region to 9.63% (95% CI 9.04%, 10.39%) in a rapidly expanding, oil-focused region. The six-region weighted average is 2.95% (95% CI 2.79%, 3.14%), or roughly three times the national government inventory estimate5. Only 0.05-1.66% of well sites contribute the majority (50-79%) of well site emissions in 11 out of 15 surveys. Ancillary midstream facilities, including pipelines, contribute 18-57% of estimated regional emissions, similarly concentrated in a small number of point sources. Together, the emissions quantified here represent an annual loss of roughly US$1 billion in commercial gas value and a US$9.3 billion annual social cost6. Repeated, comprehensive, regional remote-sensing surveys offer a path to detect these low-frequency, high-consequence emissions for rapid mitigation, incorporation into official emissions inventories and a clear-eyed assessment of the most effective emission-finding technologies for a given region.

Increasing impacts of China's oil and gas demands on global CH4 emissions

The energy sector stands out as a main contributor to increasing global methane (CH4) emissions. Given China's heavy dependence on energy imports, a closer examination of its oil and gas-related CH4 emissions becomes imperative. This study conducts an in-depth analysis of China's contribution to global CH4 emissions stemming from its consumption of crude oil and natural gas since 2000. The results indicate that CH4 emissions from crude oil and natural gas imports rose from 614 Gg in 2000 to 7692 Gg in 2019. When considering domestic production, the demand-induced CH4 emissions in 2019 increased to approximately 10754 Gg (equivalent to 320 Mt CO2-eq and 887 Mt CO2-eq based on global warming potential (GWP) values at the 100-year and 20-year time period), of which 72 % were related to crude oil and natural gas imports. The primary contributor to this increase in CH4 emissions was the expansion of the trade scale. The growth trend of crude oil imports-induced CH4 emissions was also positively influenced by emission intensity and trade structure, but these two drivers had a negative impact on the growth of natural gas imports-induced CH4 emissions. The virtual transfer of CH4 emissions via international oil and gas trade requires urgent policy attention. In collaboration with its trading partners, China should take aggressive actions to achieve meaningful mitigation in CH4 emissions associated with the oil and gas trade.

Large-Scale Controlled Experiment Demonstrates Effectiveness of Methane Leak Detection and Repair Programs at Oil and Gas Facilities

Most jurisdictions around the globe use leak detection and repair (LDAR) programs to find and fix methane leaks from oil and gas operations. In this work, we empirically evaluate the efficacy of LDAR programs using a large-scale, bottom-up, randomized controlled field experiment across ∼200 oil and gas sites in Red Deer, Canada. We find that tanks are the single largest source of emissions, contributing to nearly 60% of the total emissions. The average number of leaks at treatment sites that underwent repair reduced by ∼50% compared to the control sites. Although control sites did not see a reduction in the number of leaks, emissions reduced by approximately 36%, suggesting potential impact of routine maintenance activities to find and fix large leaks. By tracking tags on leaking equipment over time, we find a high degree of persistence; leaks that are repaired remain fixed in follow-up surveys, while non-repaired leaks remain emitting at a similar rate, suggesting that any increase in observed leak emissions following LDAR surveys are likely from new leaks. Our results show that a focus on equipment and sites that are prone to high emissions, such as tanks and oil sites, is key to cost-effective mitigation.

Informing Methane Emissions Inventories Using Facility Aerial Measurements at Midstream Natural Gas Facilities

Increased interest in greenhouse gas (GHG) emissions, including recent legislative action and voluntary programs, has increased attention on quantifying and ultimately reducing methane emissions from the natural gas supply chain. While inventories used for public or corporate GHG policies have traditionally utilized bottom-up (BU) methods to estimate emissions, the validity of such inventories has been questioned. Therefore, there is attention on utilizing full-facility measurements using airborne, satellite, or drone (top-down (TD)) techniques to inform, improve, or validate inventories. This study utilized full-facility estimates from two independent TD methods at 15 midstream natural gas facilities in the U.S.A., which were compared with a contemporaneous daily inventory assembled by the facility operator, employing comprehensive inventory methods. Estimates from the two TD methods statistically agreed in 2 of 28 paired measurements. Operator inventories, which included extensions to capture sources beyond regular inventory requirements and integration of local measurements, estimated significantly lower emissions than the TD estimates for 40 of 43 paired comparisons. Significant disagreement was observed at most facilities, both between the two TD methods and between the TD estimates and operator inventory. These findings have two implications. First, improving inventory estimates will require additional on-site or ground-based diagnostic screening and measurement of all sources. Second, the TD full-facility measurement methods need to undergo further testing, characterization, and potential improvement specifically tailored for complex midstream facilities.

Estimation of natural methane emissions from the largest oil sand deposits on earth

Worldwide methane emission by various industrial sources is one of the important human concerns due to its serious climate and air-quality implications. This study investigates less-considered diffusive natural methane emissions from the world's largest oil sand deposits. An analytical model, considering the first-order methane degradation, in combination with Monte Carlo simulations, is used to quantitatively characterize diffusive methane emissions from Alberta's oil sands formations. The results show that the average diffusive methane emissions from Alberta's oil sands formations is 1.56 × 10-4 kg/m2/year at the 90th percentile of cumulative probability. The results also indicate an annual diffusive methane emissions rate of 0.857 ± 0.013 Million tons of CO2e/year (MtCO2e/year) from Alberta's oil sands formations. This finding suggests that natural diffusive leakages from the oil sands contribute an additional 1.659 ± 0.025 and 5.194 ± 0.079% to recent Canada's 2019 and Alberta's 2020 methane emission estimates from the upstream oil and gas sector, respectively. The developed model combined with Monte Carlo simulations can be used as a tool for assessing methane emissions and current inventories.

Extension of Methane Emission Rate Distribution for Permian Basin Oil and Gas Production Infrastructure by Aerial LiDAR

Aerial LiDAR measurements at 7474 oil and gas production facilities in the Permian Basin yield a measured methane emission rate distribution extending to the detection sensitivity of the method, 2 kg/h at 90% probability of detection (POD). Emissions are found at 38.3% of facilities scanned, a significantly higher proportion than reported in lower-sensitivity campaigns. LiDAR measurements are analyzed in combination with measurements of the heavy tail portion of the distribution (>600 kg/h) obtained from an airborne solar infrared imaging spectrometry campaign by Carbon Mapper (CM). A joint distribution is found by fitting the aligned LiDAR and CM data. By comparing the aerial samples to the joint distribution, the practical detection sensitivity of the CM 2019 campaign is found to be 280 kg/h [256, 309] (95% confidence) at 50% POD for facility-sized emission sources. With respect to the joint model distribution and its confidence interval, the LiDAR campaign is found to have measured 103.6% [93.5, 114.2%] of the total emission rate predicted by the model for equipment-sized emission sources (∼2 m diameter) with emission rates above 3 kg/h, whereas the CM 2019 campaign is found to have measured 39.7% [34.6, 45.1%] of the same quantity for facility-sized sources (150 m diameter) above 10 kg/h. The analysis is repeated with data from CM 2020-21 campaigns with similar results. The combined distributions represent a more comprehensive view of the emission rate distribution in the survey area, revealing the significance of previously underreported emission sources at rates below the detection sensitivity of some emissions monitoring campaigns.

Toward Multiscale Measurement-Informed Methane Inventories: Reconciling Bottom-Up Site-Level Inventories with Top-Down Measurements Using Continuous Monitoring Systems

Government policies and corporate strategies aimed at reducing methane emissions from the oil and gas sector increasingly rely on measurement-informed, site-level emission inventories, as conventional bottom-up inventories poorly capture temporal variability and the heavy-tailed nature of methane emissions. This work is based on an 11-month methane measurement campaign at oil and gas production sites. We find that operator-level top-down methane measurements are lower during the end-of-project phase than during the baseline phase. However, gaps persist between end-of-project top-down measurements and bottom-up site-level inventories, which we reconcile with high-frequency data from continuous monitoring systems (CMS). Specifically, we use CMS to (i) validate specific snapshot measurements and determine how they relate to the temporal emission profile of a given site and (ii) create a measurement-informed, site-level inventory that can be validated with top-down measurements to update conventional bottom-up inventories. This work presents a real-world demonstration of how to reconcile CMS rate estimates and top-down snapshot measurements jointly with bottom-up inventories at the site level. More broadly, it demonstrates the importance of multiscale measurements when creating measurement-informed, site-level emission inventories, which is a critical aspect of recent regulatory requirements in the Inflation Reduction Act, voluntary methane initiatives such as the Oil and Gas Methane Partnership 2.0, and corporate strategies.

Quantification of natural gas and other hydrocarbons from production sites in northern West Virginia using tracer flux ratio methodology

Tracer flux ratio (TFR) methodology performed downwind of 15 active oil and natural gas production sites in Ohio County, West Virginia sought to quantify air pollutant emissions over two weeks in April 2018. In coordination with a production company, sites were randomly selected depending on wind forecasts and nearby road access. Methane (CH4), ethane (C2H6), and tracer gas compounds (acetylene and nitrous oxide) were measured via tunable infrared direct absorption spectroscopy. Ion signals attributed to benzene (C6H6) and other volatile gases (e.g., C7 - C9 aromatics) were measured via proton-transfer reaction time-of-flight mass spectrometry. Short-term whole facility emission rates for 12 sites are reported. Results from TFR were systematically higher than the sum of concurrent on-site full flow sampler measurements, though not all sources were assessed on-site in most cases. In downwind plumes, the mode of the C2H6:CH4 molar ratio distribution for all sites was 0.2, which agreed with spot sample analysis from the site operator. Distribution of C6H6:CH4 ratios was skew but values between 1 and 5 pptv ppbv-1 were common. Additionally, the aromatic profile has been attributed to condensate storage tank emissions. Average ratios of C7 - C9 to C6H6 were similar to other literature values reported for natural gas wells.

Aircraft and satellite observations reveal historical gap between top-down and bottom-up CO2 emissions from Canadian oil sands

Measurement-based estimates of greenhouse gas (GHG) emissions from complex industrial operations are challenging to obtain, but serve as an important, independent check on inventory-reported emissions. Such top-down estimates, while important for oil and gas (O&G) emissions globally, are particularly relevant for Canadian oil sands (OS) operations, which represent the largest O&G contributor to national GHG emissions. We present a multifaceted top-down approach for estimating CO₂ emissions that combines aircraft-measured CO₂/NO_x emission ratios (ERs) with inventory and satellite-derived NO_x emissions from Ozone Monitoring Instrument (OMI) and TROPOspheric Ozone Monitoring Instrument (TROPOMI) and apply it to the Athabasca Oil Sands Region (AOSR) in Alberta, Canada. Historical CO₂ emissions were reconstructed for the surface mining region, and average top-down estimates were found to be >65% higher than facility-reported, bottom-up estimates from 2005 to 2020. Higher top-down vs. bottom-up emissions estimates were also consistently obtained for individual surface mining and in situ extraction facilities, which represent a growing category of energy-intensive OS operations. Although the magnitudes of the measured discrepancies vary between facilities, they combine such that the observed reporting gap for total AOSR emissions is ≥(31 ± 8) Mt for each of the last 3 years (2018-2020). This potential underestimation is large and broadly highlights the importance of continued review and refinement of bottom-up estimation methodologies and inventories. The ER method herein offers a powerful approach for upscaling measured facility-level or regional fossil fuel CO₂ emissions by taking advantage of satellite remote sensing observations.

Excess methane emissions from shallow water platforms elevate the carbon intensity of US Gulf of Mexico oil and gas production

The Gulf of Mexico is the largest offshore fossil fuel production basin in the United States. Decisions on expanding production in the region legally depend on assessments of the climate impact of new growth. Here, we collect airborne observations and combine them with previous surveys and inventories to estimate the climate impact of current field operations. We evaluate all major on-site greenhouse gas emissions, carbon dioxide (CO2) from combustion, and methane from losses and venting. Using these findings, we estimate the climate impact per unit of energy of produced oil and gas (the carbon intensity). We find high methane emissions (0.60 Tg/y [0.41 to 0.81, 95% confidence interval]) exceeding inventories. This elevates the average CI of the basin to 5.3 g CO2e/MJ [4.1 to 6.7] (100-y horizon) over twice the inventories. The CI across the Gulf varies, with deep water production exhibiting a low CI dominated by combustion emissions (1.1 g CO2e/MJ), while shallow federal and state waters exhibit an extraordinarily high CI (16 and 43 g CO2e/MJ) primarily driven by methane emissions from central hub facilities (intermediaries for gathering and processing). This shows that production in shallow waters, as currently operated, has outsized climate impact. To mitigate these climate impacts, methane emissions in shallow waters must be addressed through efficient flaring instead of venting and repair, refurbishment, or abandonment of poorly maintained infrastructure. We demonstrate an approach to evaluate the CI of fossil fuel production using observations, considering all direct production emissions while allocating to all fossil products.

Role of non-CO2 greenhouse gas emissions in limiting global warming

Current climate pledges are insufficient to achieve the aspirational goal of limiting global warming to 1.5°C. Here we discuss the critical role that non-CO2 greenhouse gas emissions might play in global climate change stabilization, and challenges and opportunities to pivot research and policy focus towards accelerated reductions of non-CO2 gases.

Differentiating and Mitigating Methane Emissions from Fugitive Leaks from Natural Gas Distribution, Historic Landfills, and Manholes in Montréal, Canada

Rapidly reducing urban methane (CH₄) emissions is a critical component of strategies aimed at limiting climate change. Individual source measurements provide the details necessary to develop actionable mitigation strategies and are highly complementary to mobile surveys and other top-down methods. Here, we perform 615 individual source measurements in Montréal, Canada, to quantify CH₄ emissions from historic landfills, manholes, and fugitive emissions from natural gas (NG) distribution systems. We find that in 2020, historic landfills produced 901 (452 to 1541, 95% c.i.) tons of CH₄, manholes emitted 786 (32 to 2602, 95% c.i.) tons of CH₄, and NG distribution systems emitted 451 (176-843, 95% c.i.) tons of CH₄, placing them all within the top four CH₄ sources in Montréal. Methane emissions from both historic landfills and manholes are not accounted for in any greenhouse gas inventory. We find that geochemistry alone cannot positively identify source subcategories (e.g., type of manhole or NG infrastructure) in almost all cases, although C₂/C₁ ratios can distinguish NG distribution sources from biogenic sources (historic landfills and manholes). Using our individual source measurement data, we show that historic landfills have the greatest potential for CH₄ reductions but the highest mitigation costs, unless we target the highest emitting landfills. In contrast, CH₄ emissions from manholes can be reduced at low costs, but reduction methods are commercially unavailable. For NG distribution, methods such as increasing repair rates for high-emitting industrial meters can greatly reduce mitigation costs and emissions. Overall, our results highlight the role of individual source measurements in developing actionable CH₄ mitigation strategies to meet municipal, regional, and national climate action plans.

Recent Advances Toward Transparent Methane Emissions Monitoring: A Review

Given that anthropogenic greenhouse gas (GHG) emissions must be immediately reduced to avoid drastic increases in global temperature, methane emissions have been placed center stage in the fight against climate change. Methane has a significantly larger warming potential than carbon dioxide. A large percentage of methane emissions are in the form of industry emissions, some of which can now be readily identified and mitigated. This review considers recent advances in methane detection that allow accurate and transparent monitoring, which are needed for reducing uncertainty in source attribution and evaluating progress in emissions reductions. A particular focus is on complementary methods operating at different scales with applications for the oil and gas industry, allowing rapid detection of large point sources and addressing inconsistencies of emissions inventories. Emerging airborne and satellite imaging spectrometers are advancing our understanding and offer new top-down assessment methods to complement bottom-up methods. Successfully merging estimates across scales is vital for increased certainty regarding greenhouse gas emissions and can inform regulatory decisions. The development of comprehensive, transparent, and spatially resolved top-down and bottom-up inventories will be crucial for holding nations accountable for their climate commitments.

Methane emissions from oil and gas production sites and their storage tanks in West Virginia

A measurement campaign characterized methane and other emissions from 15 natural gas production sites. Sites were surveyed using optical gas imaging (OGI) cameras to identify fugitive and vented emissions, with the methane mass emission rate quantified using a full flow sampler. We present storage tank emissions in context of all site emissions, followed by a detailed account of the former. In total, 224 well pad emission sources at 15 sites were quantified yielding a total emission rate of 57.5 ± 2.89 kg/hr for all sites. Site specific emissions ranged from 0.4 to 10.5 kg/hr with arithmetic and geometric means of 3.8 and 2.2 kg/hr, respectively. The two largest categories of emissions by mass were pneumatic devices (35 kg/hr or ~61% of total) and tanks (14.3 kg/hr or ~25% of total). Produced water and condensate tanks at all sites employed emissions control devices. Nevertheless, tanks may still lose gas via component leaks as observed in this study. The total number of tanks at all sites was 153. One site experienced a major malfunction and direct tank measurements were not conducted due to safety concerns and may have represented a super-emitter as found in other studies. The remaining sites had 143 tanks, which accounted for 42 emissions sources. Leaks on controlled tanks were associated with ERVs, PRVs, and thief hatches. Since measurements represented snapshots-in-time and could only be compared with modeled tank emission data, it was difficult to assess real capture efficiencies accurately. Our estimates suggest that capture efficiency ranged from 63 to 92% for controlled tanks.

Atmospheric observations suggest methane emissions in north-eastern China growing with natural gas use

The dramatic increase of natural gas use in China, as a substitute for coal, helps to reduce CO₂ emissions and air pollution, but the climate mitigation benefit can be offset by methane leakage into the atmosphere. We estimate methane emissions from 2010 to 2018 in four regions of China using the GOSAT satellite data and in-situ observations with a high-resolution (0.1° × 0.1°) inverse model and analyze interannual changes of emissions by source sectors. We find that estimated methane emission over the north-eastern China region contributes the largest part (0.77 Tg CH₄ yr^-1) of the methane emission growth rate of China (0.87 Tg CH₄ yr^-1) and is largely attributable to the growth in natural gas use. The results provide evidence of a detectable impact on atmospheric methane observations by the increasing natural gas use in China and call for methane emission reductions throughout the gas supply chain and promotion of low emission end-use facilities.

Life Cycle GHG Perspective on U.S. Natural Gas Delivery Pathways

Recent emission measurement campaigns have improved our understanding of the total greenhouse gas (GHG) emissions across the natural gas supply chain, the individual components that contribute to these emissions, and how these emissions vary geographically. However, our current understanding of natural gas supply chain emissions does not account for the linkages between specific production basins and consumers. This work provides a detailed life cycle perspective on how GHG emissions vary according to where natural gas is produced and where it is delivered. This is accomplished by disaggregating transmission and distribution infrastructure into six regions, balancing natural gas supply and demand locations to infer the likely pathways between production and delivery, and incorporating new data on distribution meters. The average transmission distance for U.S. natural gas is 815 km but ranges from 45 to 3000 km across estimated production-to-delivery pairings. In terms of 100-year global warming potentials, the delivery of one megajoule (MJ) of natural gas to the Pacific region has the highest mean life cycle GHG emissions (13.0 g CO2e/MJ) and the delivery of natural gas to the Northeast U.S. has the lowest mean life cycle GHG emissions (8.1 g CO2e/MJ). The cradle-to-delivery scenarios developed in this work show that a national average does not adequately represent the upstream GHG emission intensity for natural gas from a specific basin or delivered to a specific consumer.

Carbon footprint calculation in one of the largest Gas Refinery Companies in the Middle East

Rapid technological advances in the natural gas industry raised access to natural gas reserves, related to increased greenhouse gas emissions, including CO2 and CH4. This study calculates greenhouse gas emissions (CO2 and CH4) according to sources (direct and indirect) in one of the largest gas Refinery Companies in the Middle East to analyze the carbon footprint for the first time. All computational frameworks for estimating carbon footprint and greenhouse gas emissions (CO2 and CH4) in different sectors were carried out after determining direct sources (combustion, processes, and fugitive) and indirect ones (import from National Grid's electricity) according to the requirement guide and organizations' report involved in the operational activities of the oil industry. The carbon footprint for this refinery, leading to the emission of CO2 and CH4, is in the range of 1507.1 Gg CO2/yr and 0.003 Gg CH4/yr. The highest CO2 emissions are related to the gas-sweetening unit from GHG direct emission sources, and the lowest CO2 emissions are related to fugitive ones. For methane gas, the highest CH4 emissions are related to fugitive emissions. In addition, the emission of CH4 from the gas sweetening unit and waste combustion equipment is estimated to be very small and close to zero. This study showed that it is necessary to carry out more studies in different regions to give a more comprehensive insight into gas emissions and their adverse health effects on human populations.

Impact of Shale Gas Exploration and Exploitation Activities on the Quality of Ambient Air—The Case Study of Wysin, Poland

The continuous two-year monitoring of a set of air pollutants, as well as gases directly related to shale gas exploration processes (methane, non-methane hydrocarbons, carbon dioxide), was carried out at Stary Wiec village in the vicinity (1100 m) of the shale gas wells area in Wysin (Pomeranian voivodeship, north of Poland), covering the stages of preparation, drilling, hydrofracturing and closing of wells. The results of analysis of air pollution data from Stary Wiec and nearby urban and rural stations, over the period 2012–2017 (starting three years before preparations for hydraulic fracturing) indicated that Stary Wiec represents a clean rural environment with an average concentration of nitrogen oxides, carbon monoxide and particulate matter that is one of the lowest in the Pomeranian region. The aim of this study was to explore the range of potential impact of shale gas exploration on local ambient air quality. Analysis of dependence of the concentration level of pollutants on the wind direction indicated that during the drilling period, when the air was coming directly from the area of the wells, nitrogen oxide concentration increased by 13%. Increases of concentration during the hydro-fracturing period, recorded at the Stary Wiec station, were equal to 108%, 21%, 18%, 12%, 7%, 4%, 1% for nitrogen oxide, non-methane hydrocarbons, carbon monoxide, nitrogen dioxide, particulate matter, carbon dioxide and methane. The results of one-minute concentration values for the period 1–4 September 2016 showed a series of short peaks up to 7.45 ppm for methane and up to 3.03 ppm for non-methane hydrocarbons, being probably the result of operations carried out at the area of the wells.

Understanding the complexity of existing fossil fuel power plant decarbonization

Growing national decarbonization commitments require rapid and deep reductions of carbon dioxide emissions from existing fossil-fuel power plants. Although retrofitting existing plants with carbon capture and storage or biomass has been discussed extensively, yet such options have failed to provide evident emission reductions at a global scale so far. Assessments of decarbonization technologies tend to focus on one specific option but omit its interactions with competing technologies and related sectors (e.g., water, food, and land use). Energy system models could mimic such inter-technological and inter-sectoral competition but often aggregate plant-level parameters without validation, as well as fleet-level inputs with large variability and uncertainty. To enhance the accuracy and reliability of top-down optimization models, bottom-up plant-level experience accumulation is of vital importance. Identifying sweet spots for plant-level pilot projects, overcoming the technical, financial, and social obstacles of early large-scale demonstration projects, incorporating equity into the transition, propagating the plant-level potential to generate fleet-level impacts represent some key complexity of existing fossil-fuel power plant decarbonization challenges that imposes the need for a serious re-evaluation of existing fossil fuel power plant abatement in energy transition.

The BosWash Infrastructure Biome and Energy System Succession

The BosWash corridor is a megalopolis, or large urbanized region composed of interconnected transportation, infrastructure, physiography, and sociopolitical systems. Previous work has not considered the BosWash corridor as an integrated, holistic ecosystem. Building on the emerging field of infrastructure ecology, the region is conceptualized here as an infrastructure biome, and this concept is applied to the region’s energy transition to a post-fossil fueled heating sector, in analogy to ecosystem succession. In this conception, infrastructure systems are analogous to focal species. A case study for an energy succession from an aging natural gas infrastructure to a carbon-free heating sector is presented, in order to demonstrate the utility of the infrastructure biome framework to address climate and energy challenges facing BosWash communities. Natural gas is a dominant energy source that emits carbon dioxide when burned and methane when leaked along the process chain; therefore, a transition to electricity is widely seen as necessary toward reducing greenhouse gas emissions. Utilizing an infrastructure biome framework for energy policy, a regional gas transition plan akin to the Regional Greenhouse Gas Initiative is generated to harmonize natural gas transition within the BosWash infrastructure biome and resolve conflict arising from a siloed approach to infrastructure management at individual city and state levels. This work generates and utilizes the novel infrastructure biome concept to prescribe a regional energy policy for an element of infrastructure that has not previously been explored at the regional scale—natural gas.

Global Tracking and Quantification of Oil and Gas Methane Emissions from Recurrent Sentinel-2 Imagery

Methane (CH₄) emission estimates from top-down studies over oil and gas basins have revealed systematic underestimation of CH₄ emissions in current national inventories. Sparse but extremely large amounts of CH₄ from oil and gas production activities have been detected across the globe, resulting in a significant increase of the overall oil and gas contribution. However, attribution to specific facilities remains a major challenge unless high-spatial-resolution images provide sufficient granularity within the oil and gas basin. In this paper, we monitor known oil and gas infrastructures across the globe using recurrent Sentinel-2 imagery to detect and quantify more than 1200 CH₄ emissions. In combination with emission estimates from airborne and Sentinel-5P measurements, we demonstrate the robustness of the fit to a power law from 0.1 tCH4/h to 600 tCH4/h. We conclude here that the prevalence of ultraemitters (>25tCH4/h) detected globally by Sentinel-5P directly relates to emission occurrences below its detection threshold in the range >2tCH4/h, which correspond to large emitters covered by Sentinel-2. We also verified that this relation is also valid at a more local scale for two specific countries, namely, Algeria and Turkmenistan, and the Permian basin in the United States.

Monitoring methane emissions from oil and gas operations‡

The atmospheric concentration of methane has more than doubled since the start of the Industrial Revolution. Methane is the second-most-abundant greenhouse gas created by human activities and a major driver of climate change. This APS-Optica report provides a technical assessment of the current state of monitoring U.S. methane emissions from oil and gas operations, which accounts for roughly 30% of U.S. anthropogenic methane emissions. The report identifies current technological and policy gaps and makes recommendations for the federal government in three key areas: methane emissions detection, reliable and systematized data and models to support mitigation measures, and effective regulation.

Elimination of Scintillation Noise Caused by External Environment Disturbances in Open Space

External environment disturbances in open space cause scintillation noise in tunable diode laser absorption spectroscopy (TDLAS), which is used to detect the concentration of gases in air. However, most gases analyzed by TDLAS are present in trace amounts in air. Thus, useful information is typically submerged in strong noise, thereby reducing the detection accuracy. Herein, a method is proposed to eliminate the scintillation noise caused by external environment disturbances in open space. First, the submerged signal is detected via fast coarse-tuning filtering. Then, scintillation noise is eliminated through the extraction and reconstruction of the main feature information. Thereafter, the background signal is obtained by unequal precision. Furthermore, adaptive iterative fitting is performed. Finally, an experimental setup is established for atmospheric detection in an open optical path. The experimental results show that the COD and RSS fitted using the traditional method are 0.87859 and 1.5772 × 10−5, respectively, and those fitted using the proposed method are 0.91448 and 8.81639 × 10−6, respectively. The field results imply that the proposed method has improved accuracy for detecting trace gases in open space and can be employed for practical engineering applications.

Methane and hydrogen sulfide emissions from abandoned, active, and marginally producing oil and gas wells in Ontario, Canada

Abandoned, active, and marginally producing (producing <1700 m³/day of natural gas or <1.6 m³/day of oil) oil and gas (O&G) wells emit methane (CH₄), a potent greenhouse gas, and hydrogen sulfide (H₂S), a highly toxic gas, but measurements to quantify these emission rates are limited or lacking. Here, we conduct 85 measurements of CH₄ and H₂S emission rates from 63 abandoned, active and marginally producing gas wells and a wetland area overlying a possible undocumented well in Ontario, the Canadian province with the longest history of O&G development. Our measurements show that abandoned wells emitting H₂S are some of the highest CH₄ emitters (average = 16600 mg CH₄/h/well), followed by abandoned unplugged and marginally producing wells. Abandoned plugged (average = 2100 mg CH₄/h/well) and producing (average = 6800 mg CH₄/h/well) wells are the lowest CH₄ emitters. Compared to inventory estimates, CH₄ emissions from marginally producing and active wells in Ontario are underestimated by a factor of 2.1, and emissions from abandoned plugged wells are underestimated by a factor of 920. H₂S emissions, currently not included in the Canadian Air Pollutant Emissions Inventory, average at 160 mg H₂S/h/well. Our findings highlight the importance of conducting measurements from all types of oil and gas wells including H₂S emitting wells to understand H₂S and CH₄ emissions and develop policies to reduce greenhouse gas emissions, improve air quality, and protect human and ecosystem health.

Measurements of Atmospheric Methane Emissions from Stray Gas Migration: A Case Study from the Marcellus Shale

Understanding emissions of methane from legacy and ongoing shale gas development requires both regional studies that assess the frequency of emissions and case studies that assess causation. We present the first direct measurements of emissions in a case study of a putatively leaking gas well in the largest shale gas play in the United States. We quantify atmospheric methane emissions in farmland >2 km from the nearest shale gas well cited for casing and cementing issues. We find that emissions are highly heterogeneous as they travel long distances in the subsurface. Emissions were measured near observed patches of dead vegetation and methane bubbling from a stream. An eddy covariance flux tower, chamber flux measurements, and a survey of enhancements of the near-surface methane mole fraction were used to quantify emissions and evaluate the spatial and temporal variability. We combined eddy covariance measurements with the survey of the methane mole fraction to estimate total emissions over the study area (2,800 m²). Estimated at ∼6 kg CH₄ day^-1, emissions were spatially heterogeneous but showed no temporal trends over 6 months. The isotopic signature of the atmospheric CH₄ source (δ¹³CH₄) was equal to -29‰, consistent with methane of thermogenic origin and similar to the isotopic signature of the gas reported from the nearest shale gas well. While the magnitude of emissions from the potential leak is modest compared to large emitters identified among shale gas production sites, it is large compared to estimates of emissions from single abandoned wells. Since other areas of emissions have been identified close to this putatively leaking well, our estimate of emissions likely represents only a portion of total emissions from this event. More comprehensive quantification will require more extensive spatial and temporal sampling of the locations of gas migration to the surface as well as an investigation into the mechanisms of subsurface gas migration. This work highlights an example of atmospheric methane emissions from potential stray gas migration at a location far from a well pad, and further research should explore the frequency and mechanisms behind these types of events to inform careful and strategic natural gas development.

Quantifying Regional Methane Emissions in the New Mexico Permian Basin with a Comprehensive Aerial Survey

Limiting emissions of climate-warming methane from oil and gas (O&G) is a major opportunity for short-term climate benefits. We deploy a basin-wide airborne survey of O&G extraction and transportation activities in the New Mexico Permian Basin, spanning 35 923 km², 26 292 active wells, and over 15 000 km of natural gas pipelines using an independently validated hyperspectral methane point source detection and quantification system. The airborne survey repeatedly visited over 90% of the active wells in the survey region throughout October 2018 to January 2020, totaling approximately 98 000 well site visits. We estimate total O&G methane emissions in this area at 194 (+72/-68, 95% CI) metric tonnes per hour (t/h), or 9.4% (+3.5%/-3.3%) of gross gas production. 50% of observed emissions come from large emission sources with persistence-averaged emission rates over 308 kg/h. The fact that a large sample size is required to characterize the heavy tail of the distribution emphasizes the importance of capturing low-probability, high-consequence events through basin-wide surveys when estimating regional O&G methane emissions.

Implications of Generation Efficiencies and Supply Chain Leaks for the Life Cycle Greenhouse Gas Emissions of Natural Gas-Fired Electricity in the United States

Uncertainties in supply chain emissions raise questions about the benefits of natural gas as a bridge fuel, but recent efficiency improvements in gas-fired electricity generation remain overlooked. Our comprehensive analysis of supply chain infrastructure and electricity generation across the United States informs spatially and temporally resolved estimates of life cycle greenhouse gas emissions. Results show decreasing life cycle emissions over each year examined: 629, 574, and 525 kg CO₂ eq MWh^-1 in 2005, 2010, and 2015, respectively. Electricity generation contributed 86% of emissions or greater for each year. Despite concerns over uncertain methane leaks, efficiency improvements make it much more likely that natural gas electricity has an unambiguous greenhouse gas benefit relative to coal. Methane leaks would have to be 4.4 times the Environmental Protection Agency (EPA) value in 2015 to reverse these benefits over 20-year time horizons. With retiring coal plants and scrutinized supply chain emissions, our results show that natural gas can provide a lower emissions option to coal in an increasingly decarbonized power sector.

Why are methane emissions from China's oil & natural gas systems still unclear? A review of current bottom-up inventories

There is growing awareness and concern on methane (CH₄) emissions from China's oil and natural gas (ONG) systems owing to the carbon neutral target. This paper aims to present a comprehensive review on the bottom-up inventories of the CH₄ emissions from the perspective of the ONG systems in China. The trend and magnitude of total emissions in the last four decades were revealed and limitations of current estimations were explored. Previous studies showed that the average CH₄ emissions from China's ONG systems have almost tripled from 1980 (760 Gg) to 2015 (2180 Gg) with a trend of steady increase. However, the estimated values varied by an order-of-magnitude with the largest discrepancy of 2700 Gg. This discrepancy was unlikely caused mainly by the incompleteness of estimation, since dominant emission sources were all covered by representative studies. Moreover, the differences of activity-level data were within ±10%, which ruled out the possibility that it was the main contributor to the large discrepancies. The emissions estimate has huge variation in large part because of differences in assumed emission factors (EFs) that vary by an order of magnitude. The difficulty was to determine which of the EFs were accurate due to measurement-based data availability. Thus, the large discrepancies stem from the scarcity of publicly available data, which enlarged the impact from various methods adopted by previous studies. For better understanding of CH₄ emissions from the ONG systems in China, the measurements of facility-level emissions and statistics on the ONG infrastructure are required urgently. Due to the high cost and experience-oriented measurement work, international cooperation and communications are critical prerequisites for future CH₄ emission estimates and effective mitigation strategies.

Elevated levels of radiocarbon in methane dissolved in seawater reveal likely local contamination from nuclear powered vessels

Measurements of the natural radiocarbon content of methane (¹⁴C-CH₄) dissolved in seawater and freshwater have been used to investigate sources and dynamics of methane. However, during investigations along the Atlantic, Pacific, and Arctic Ocean Margins of the United States, as well as in the North American Great Lakes, some samples revealed highly elevated ¹⁴C-CH₄ values, as much as 4-5 times above contemporary atmospheric ¹⁴C-CH₄ levels. Natural production of the ¹⁴CH₄ isotopologue is too low to cause these observations nor can it explain the variations in location and depth. Numerous lab and field validation tests and blanks, as well as the relatively small number of samples that display these elevated values, all suggest that these signals are not derived from an unknown procedural issue. Here we suggest that the byproducts of nuclear power generation include localized discharges of the ¹⁴CH₄ isotopologue into marine and aquatic environments, severely altering the measured ¹⁴C-CH₄ isotopic signals. Since several of our sample sites are distant from on-land nuclear powerplants, we conduct further calculations concluding that the most elevated anomalies in ¹⁴C-CH₄ likely originate with discharge from nuclear-powered vessels.

Assessing Unconventional Oil and Gas Exposure in the Appalachian Basin: Comparison of Exposure Surrogates and Residential Drinking Water Measurements

Health studies report associations between metrics of residential proximity to unconventional oil and gas (UOG) development and adverse health endpoints. We investigated whether exposure through household groundwater is captured by existing metrics and a newly developed metric incorporating groundwater flow paths. We compared metrics with detection frequencies/concentrations of 64 organic and inorganic UOG-related chemicals/groups in residential groundwater from 255 homes (Pennsylvania n = 94 and Ohio n = 161). Twenty-seven chemicals were detected in ≥20% of water samples at concentrations generally below U.S. Environmental Protection Agency standards. In Pennsylvania, two organic chemicals/groups had reduced odds of detection with increasing distance to the nearest well: 1,2-dichloroethene and benzene (Odds Ratio [OR]: 0.46, 95% confidence interval [CI]: 0.23-0.93) and m- and p-xylene (OR: 0.28, 95% CI: 0.10-0.80); results were consistent across metrics. In Ohio, the odds of detecting toluene increased with increasing distance to the nearest well (OR: 1.48, 95% CI: 1.12-1.95), also consistent across metrics. Correlations between inorganic chemicals and metrics were limited (all |ρ| ≤ 0.28). Limited associations between metrics and chemicals may indicate that UOG-related water contamination occurs rarely/episodically, more complex metrics may be needed to capture drinking water exposure, and/or spatial metrics in health studies may better reflect exposure to other stressors.

Cost of long-distance energy transmission by different carriers

This paper compares the relative cost of long-distance, large-scale energy transmission by electricity, gaseous, and liquid carriers (e-fuels). The results indicate that the cost of electrical transmission per delivered MWh can be up to eight times higher than for hydrogen pipelines, about eleven times higher than for natural gas pipelines, and twenty to fifty times higher than for liquid fuels pipelines. These differences generally hold for shorter distances as well. The higher cost of electrical transmission is primarily because of lower carrying capacity (MW per line) of electrical transmission lines compared to the energy carrying capacity of the pipelines for gaseous and liquid fuels. The differences in the cost of transmission are important but often unrecognized and should be considered as a significant cost component in the analysis of various renewable energy production, distribution, and utilization scenarios.

Hot money: Illuminating the financing of high-carbon infrastructure in the developing world

Major infrastructure financiers will have to significantly decarbonize their investments to meet mounting promises to cut carbon emissions to “net-zero” by mid-century. We provide new details about those needed shifts. Using two World Bank databases of infrastructure projects throughout the developing world, and applying a methodology for imputing the projects' likely future carbon output, we assess the emissions profile of power-plant projects executed from 2018 through 2020 — the three years immediately preceding the spate of net-zero pledges. We find that approximately half the generation executed in those years is too carbon-intensive to align with keeping Earth's average temperature from exceeding 1.5°C above pre-industrial levels, largely because of the prevalence of new natural-gas–fired power plants. We also find new evidence of host countries' agency in shaping carbon trajectories: Much of the climate-misaligned financing is not foreign but domestic. And we find different institutions are financing infrastructure portfolios with significantly differing carbon intensities.

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New data yields insights on climate impact of developing-world infrastructure finance

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52% of power generation added in developing world from 2018 through 2020 is climate-misaligned

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Climate benefits of falling coal financing eclipsed by surging natural-gas financing

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Much high-carbon developing-world finance comes from domestic, not foreign, investors

Declining methane emissions and steady, high leakage rates observed over multiple years in a western US oil/gas production basin

Methane, a potent greenhouse gas, is the main component of natural gas. Previous research has identified considerable methane emissions associated with oil and gas production, but estimates of emission trends have been inconsistent, in part due to limited in-situ methane observations spanning multiple years in oil/gas production regions. Here we present a unique analysis of one of the longest-running datasets of in-situ methane observations from an oil/gas production region in Utah’s Uinta Basin. The observations indicate Uinta methane emissions approximately halved between 2015 and 2020, along with declining gas production. As a percentage of gas production, however, emissions remained steady over the same years, at ~ 6–8%, among the highest in the U.S. Addressing methane leaks and recovering more of the economically valuable natural gas is critical, as the U.S. seeks to address climate change through aggressive greenhouse emission reductions.

Atmospheric methane removal: a research agenda

Atmospheric methane removal (e.g. in situ methane oxidation to carbon dioxide) may be needed to offset continued methane release and limit the global warming contribution of this potent greenhouse gas. Because mitigating most anthropogenic emissions of methane is uncertain this century, and sudden methane releases from the Arctic or elsewhere cannot be excluded, technologies for methane removal or oxidation may be required. Carbon dioxide removal has an increasingly well-established research agenda and technological foundation. No similar framework exists for methane removal. We believe that a research agenda for negative methane emissions-'removal' or atmospheric methane oxidation-is needed. We outline some considerations for such an agenda here, including a proposed Methane Removal Model Intercomparison Project (MR-MIP). This article is part of a discussion meeting issue 'Rising methane: is warming feeding warming? (part 1)'.