Assessment of methane emissions from the U.S. oil and gas supply chain

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.

Development of Company-Specific Emission Factors with Confidence Intervals for Natural Gas Customer Meters in Southern California

Methane is both a significant and short-lived greenhouse gas compared to CO2, and reducing methane emissions from natural gas distribution systems may offer cost-effective reduction opportunities. We report substantial new direct leak rate measurements from customer meter set assemblies (MSAs) in Southern California. In a novel way, emission factors are defined in terms of aboveground Hazardous and Nonhazardous leak categories, which take direct advantage of readily available industry leak data. We also studied leaks that were not detected as part of normal leak survey procedures. As a result, this yields company-specific emission factors that can be used to track progress in reducing methane emissions. This approach also has the advantage of explicitly accounting for the skewed or fat-tail distribution of leak rates by treating high flow rate MSA leaks separately from low flow rate MSA leaks. The Southern California Gas (SoCalGas) methane emission factors, based on 485 leak rate measurements by direct enclosure, were 4.55 (95% confidence interval: 2.32 to 7.14) kg/day for Hazardous leaks, 0.149 (0.119 to 0.183) kg/day for Nonhazardous leaks, and 0.0039 (0.0003 to 0.0198) kg/day for Non-Detected leaks. The percentage of surveyed meters with nondetected leaks was 29.1% (24.3 to 34.6%). Based on a robust Monte Carlo analysis, total leak emissions from MSAs for the SoCalGas system were reduced by 35% based on data from 2015 to 2022. These reductions were attributed to surveying a larger number of MSAs and accelerated leak repair rates. In traditional population-based emission inventories, an individual emission factor for a given asset category is multiplied by the total population of MSAs within the category. This approach simply cannot capture the reduction in leak numbers and methane emissions resulting from leak mitigation and prevention programs.

Subsidizing Grid-Based Electrolytic Hydrogen Will Increase Greenhouse Gas Emissions in Coal Dominated Power Systems

Clean hydrogen has the potential to serve as an energy carrier and feedstock in decarbonizing energy systems, especially in "hard-to-abate" sectors. Although many countries have implemented policies to promote electrolytic hydrogen development, the impact of these measures on costs of production and greenhouse gas emissions remains unclear. Our study conducts an integrated analysis of provincial levelized costs and life cycle greenhouse gas emissions for all hydrogen production types in China. We find that subsidies are critical to accelerate low carbon electrolytic hydrogen development. Subsidies on renewable-based hydrogen provide cost-effective carbon dioxide equivalent (CO2e) emission reductions. However, subsidies on grid-based hydrogen increase CO2e emissions even compared with coal-based hydrogen because grid electricity in China still relies heavily on coal power and likely will beyond 2030. In fact, CO2e emissions from grid-based hydrogen may increase further if China continues to approve new coal power plants. The levelized costs of renewable energy-based electrolytic hydrogen vary among provinces. Transporting renewable-based hydrogen through pipelines from low- to high-cost production regions reduces the national average levelized cost of renewables-based hydrogen but may increase the risk of hydrogen leakage and the resulting indirect warming effects. Our findings emphasize that policy and economic support for nonfossil electrolytic hydrogen is critical to avoid an increase in CO2e emissions as hydrogen use rises during a clean energy transition.

Climate Impacts of Hydrogen and Methane Emissions Can Considerably Reduce the Climate Benefits across Key Hydrogen Use Cases and Time Scales

Recent investments in "clean" hydrogen as an alternative to fossil fuels are driven by anticipated climate benefits. However, most climate benefit calculations do not adequately account for all climate warming emissions and impacts over time. This study reanalyzes a previously published life cycle assessment as an illustrative example to show how the climate impacts of hydrogen deployment can be far greater than expected when including the warming effects of hydrogen emissions, observed methane emission intensities, and near-term time scales; this reduces the perceived climate benefits upon replacement of fossil fuel technologies. For example, for blue (natural gas with carbon capture) hydrogen pathways, the inclusion of upper-end hydrogen and methane emissions can yield an increase in warming in the near term by up to 50%, whereas lower-end emissions decrease warming impacts by at least 70%. For green (renewable-based electrolysis) hydrogen pathways, upper-end hydrogen emissions can reduce climate benefits in the near term by up to 25%. We also consider renewable electricity availability for green hydrogen and show that if it is not additional to what is needed to decarbonize the electric grid, there may be more warming than that seen with fossil fuel alternatives over all time scales. Assessments of hydrogen's climate impacts should include the aforementioned factors if hydrogen is to be an effective decarbonization tool.

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.

Vertical Distribution Mapping for Methane Fugitive Emissions Using Laser Path-Integral Sensing in Non-Cooperative Open Paths

Observing the vertical diffusion distribution of methane fugitive emissions from oil/gas facilities is significant for predicting the pollutant's spatiotemporal transport and quantifying the random emission sources. A method is proposed for methane's vertical distribution mapping by combining the laser path-integral sensing in non-non-cooperative open paths and the computer-assisted tomography (CAT) techniques. It uses a vertical-plume-mapping optical path configuration and adapts the developed dynamic relaxation and simultaneous algebraic reconstruction technique (DR-SART) into methane-emission-distribution reconstruction. A self-made miniaturized TDLAS telemetry sensor provides a reliable path to integral concentration information in non-non-cooperative open paths, with Allan variance analysis yielding a 3.59 ppm·m sensitivity. We employed a six-indexes system for the reconstruction performance analysis of four potential optical path-projection configurations and conducted the corresponding validation experiment. The results have shown that that of multiple fan-beams combined with parallel-beam modes (MFPM) is better than the other optical path-projection configurations, and its reconstruction similarity coefficient (ε) is at least 22.4% higher. For the different methane gas bag-layout schemes, the reconstruction errors of maximum concentration (γm) are consistently around 0.05, with the positional errors of maximum concentration (δ) falling within the range of 0.01 to 0.025. Moreover, considering the trade-off between scanning duration and reconstruction accuracy, it is recommended to appropriately extend the sensor measurement time on a single optical path to mitigate the impact of mechanical vibrations induced by scanning motion.

Palladium Catalysts for Methane Oxidation: Old Materials, New Challenges

ConspectusMethane complete oxidation is an important reaction that is part of the general scheme used for removing pollutants contained in emissions from internal combustion engines and, more generally, combustion processes. It has also recently attracted interest as an option for the removal of atmospheric methane in the context of negative emission technologies. Methane, a powerful greenhouse gas, can be converted to carbon dioxide and water via its complete oxidation. Despite burning methane being facile because the combustion sustains its complete oxidation after ignition, methane strong C-H bonds require a catalyst to perform the oxidation at low temperatures and in the absence of a flame so as to avoid the formation of nitrogen oxides, such as those produced in flares. This process allows methane removal to be obtained under conditions that usually lead to higher emissions, such as under cold start conditions in the case of internal combustion engines. Among several options that include homo- and heterogeneous catalysts, supported palladium-based catalysts are the most active heterogeneous systems for this reaction. Finely divided palladium can activate C-H bonds at temperatures as low as 150 °C, although complete conversion is usually not reached until 400-500 °C in practical applications. Major goals are to achieve catalytic methane oxidation at as low as possible temperature and to utilize this expensive metal more efficiently.Compared to any other transition metal, palladium and its oxides are orders of magnitude more reactive for methane oxidation in the absence of water. During the last few decades, much research has been devoted to unveiling the origin of the high activity of supported palladium catalysts, their active phase, the effect of support, promoters, and defects, and the effect of reaction conditions with the goal of further improving their reactivity. There is an overall agreement in trends, yet there are noticeable differences in some details of the catalytic performance of palladium, including the active phase under reaction conditions and the reasons for catalyst deactivation and poisoning. In this Account we summarize our work in this space using well-defined catalysts, especially model palladium surfaces and those prepared using colloidal nanocrystals as precursors, and spectroscopic tools to unveil important details about the chemistry of supported palladium catalysts. We describe advanced techniques aimed at elucidating the role of several parameters in the performance of palladium catalysts for methane oxidation as well as in engineering catalysts through advancing fundamental understanding and synthesis methods. We report the state of research on active phases and sites, then move to the role of supports and promoters, and finally discuss stability in catalytic performance and the role of water in the palladium active phase. Overall, we want to emphasize the importance of a fundamental understanding in designing and realizing active and stable palladium-based catalysts for methane oxidation as an example for a variety of energy and environmental applications of nanomaterials in catalysis.

The Futility of Relative Methane Reduction Targets in the Absence of Measurement-Based Inventories

Under the Global Methane Pledge, Canada is developing oil and gas sector methane regulations targeting 75% reductions from 2012 levels by 2030. Without measured baselines and inventories, such policies are ultimately unverifiable and unenforceable. Using the major oil and gas producing province of Saskatchewan as a case study, we derive first-ever measurement-based methane inventories for the region and comprehensively model previous emissions back to the 2012 baseline. Although relative reductions of 23-69% have likely occurred, the dispersion of modeled possibilities and the high emissions from continuing production illustrate the limits of this approach as a meaningful policy metric. Moreover, nearly 90% of apparent reductions are explained by decreased production at heavy oil facilities, suggesting emissions have potential to rebound if production resumes. By contrast, derived measurement-based methane emissions intensities facilitate quantitative assessment and show that despite any past reductions, Saskatchewan's 0.41 ± 0.03 g/MJ intensity remains among the highest in North America. This highlights how relative reduction targets absent measured baselines and inventories are inherently futile and risk rewarding high emitters while obscuring ongoing mitigation potential. Ultimately, required global methane reductions will only be achieved by adopting objectively and independently verifiable emission metrics while measuring and tracking progress toward a net zero future.

Measuring methane emissions during the installation of residential and commercial natural gas meters in China

Methane is a potent greenhouse gas that accounts for one-quarter of the world's radiative forcing. Methane emissions from the natural gas sector are prevalent throughout the natural gas (NG) chain. Studies have shown that methane emissions from post-meter uses of natural gas are vastly understated. A surge in the number of natural gas users, for example, would amplify the climate impact of methane emissions during the installation of natural gas meters. Thus, quantifying methane emissions during the installation of natural gas meters is critical in light of severe global climate change and urgent reduction targets. In this study, we used a mass balance approach to calculate methane emissions during the separate installation of 1444 residential natural gas meters and 51 commercial natural gas meters. Our results revealed the methane emission had a fat tail distribution. Specifically, the estimated mean methane emissions for household users were 0.008 (0.001-0.022) kg per household and 0.192 (0.013-0.816) kg per commercial user. Extrapolating these statistics to the whole of China, total emissions from 2007 to 2021 were 3.80 million metric tons (MMt) CH4, with an annual average of 0.25 MMt. Notably, in terms of economic development and population size, the provinces with the highest methane emissions were concentrated in the southeast. Our findings close a gap in measuring CH4 emissions in China across the natural gas chain and provide data to support the reduction targets set and the development of reduction technologies.

Assessing the Relative Importance of Satellite-Detected Methane Superemitters in Quantifying Total Emissions for Oil and Gas Production Areas in Algeria

Methane emissions from oil and gas production provide an important contribution to global warming. We investigate 2020 emissions from the largest gas field in Algeria, Hassi R'Mel, and the oil-production-dominated area Hassi Messaoud. We use methane data from the high-resolution (20 m) Sentinel-2 instruments to identify and estimate emission time series for 11 superemitters (including 10 unlit flares). We integrate this information in a transport model inversion that uses methane data from the coarser (7 km × 5.5 km) but higher-precision TROPOMI instrument to estimate emissions from both the 11 superemitters (>1 t/h individually) and the remaining diffuse area source (not detected as point sources with Sentinel-2). Compared to a bottom-up inventory for 2019 that is aligned with UNFCCC-reported emissions, we find that 2020 emissions in Hassi R'Mel (0.16 [0.11-0.22] Tg/yr) are lower by 53 [24-73]%, and emissions in Hassi Messaoud (0.22 [0.13-0.28] Tg/yr) are higher by 79 [4-188]%. Our analysis indicates that a larger fraction of Algeria's methane emissions (∼75%) come from oil production than national reporting suggests (5%). Although in both regions the diffuse area source constitutes the majority of emissions, relatively few satellite-detected superemitters provide a significant contribution (24 [12-40]% in Hassi R'Mel; 49 [27-71]% in Hassi Messaoud), indicating that mitigation efforts should address both. Our synergistic use of Sentinel-2 and TROPOMI can produce a unique and detailed emission characterization of oil and gas production areas.

Conventional Fossil Fuel Extraction, Associated Biogeochemical Processes, and Topography Influence Methane Groundwater Concentrations in Appalachia

The production of fossil fuels, including oil, gas, and coal, retains a dominant share in US energy production and serves as a major anthropogenic source of methane, a greenhouse gas with a high warming potential. In addition to directly emitting methane into the air, fossil fuel production can release methane into groundwater, and that methane may eventually reach the atmosphere. In this study, we collected 311 water samples from an unconventional oil and gas (UOG) production region in Pennsylvania and an oil and gas (O&G) and coal production region across Ohio and West Virginia. Methane concentration was negatively correlated to distance to the nearest O&G well in the second region, but such a correlation was shown to be driven by topography as a confounding variable. Furthermore, sulfate concentration was negatively correlated with methane concentration and with distance to coal mining in the second region, and these correlations were robust even when considering topography. We hypothesized that coal mining enriched sulfate in groundwater, which in turn inhibited methanogenesis and enhanced microbial methane oxidation. Thus, this study highlights the complex interplay of multiple factors in shaping groundwater methane concentrations, including biogeochemical conversion, topography, and conventional fossil extraction.

Semantic segmentation of methane plumes with hyperspectral machine learning models

Methane is the second most important greenhouse gas contributor to climate change; at the same time its reduction has been denoted as one of the fastest pathways to preventing temperature growth due to its short atmospheric lifetime. In particular, the mitigation of active point-sources associated with the fossil fuel industry has a strong and cost-effective mitigation potential. Detection of methane plumes in remote sensing data is possible, but the existing approaches exhibit high false positive rates and need manual intervention. Machine learning research in this area is limited due to the lack of large real-world annotated datasets. In this work, we are publicly releasing a machine learning ready dataset with manually refined annotation of methane plumes. We present labelled hyperspectral data from the AVIRIS-NG sensor and provide simulated multispectral WorldView-3 views of the same data to allow for model benchmarking across hyperspectral and multispectral sensors. We propose sensor agnostic machine learning architectures, using classical methane enhancement products as input features. Our HyperSTARCOP model outperforms strong matched filter baseline by over 25% in F1 score, while reducing its false positive rate per classified tile by over 41.83%. Additionally, we demonstrate zero-shot generalisation of our trained model on data from the EMIT hyperspectral instrument, despite the differences in the spectral and spatial resolution between the two sensors: in an annotated subset of EMIT images HyperSTARCOP achieves a 40% gain in F1 score over the baseline.

Natural Abiotic Iron-Oxido-Mediated Formation of C1 and C2 Compounds from Environmentally Important Methyl-Substituted Substrates

Organic and inorganic volatile compounds containing one carbon atom (C1), such as carbon dioxide, methane, methanol, formaldehyde, carbon monoxide, and chloromethane, are ubiquitous in the environment, are key components in global carbon cycling, play an important role in atmospheric physics and chemistry, e.g., as greenhouse gases, destroy stratospheric and tropospheric ozone, and control the atmospheric oxidation capacity. Up to now, most C1 compounds in the environment were associated with complex metabolic and enzymatic pathways in organisms or to combustion processes of organic matter. We now present compelling evidence that many C1 and C2 compounds have a common origin in methyl groups of methyl-substituted substrates that are cleaved by the iron oxide-mediated formation of methyl radicals. This scenario is derived from experiments with a mechanistically well-studied bispidine-iron-oxido complex as oxidant and dimethyl sulfoxide as the environmentally relevant model substrate and is supported by computational modeling based on density functional theory and ab initio quantum-chemical studies. The exhaustive experimental model studies, also involving extensive isotope labeling, are complemented with the substitution of the bispidine model system by environmentally relevant iron oxides and, finally, a collection of soils with varying iron and organic matter contents. The combination of all data suggests that the iron oxide-mediated formation of methyl radicals from methyl-substituted substrates is a common abiotic source for widespread C1 and C2 compounds in the environment.

A Gridded Inventory of Annual 2012-2018 U.S. Anthropogenic Methane Emissions

Nationally reported greenhouse gas inventories are a core component of the Paris Agreement's transparency framework. Comparisons with emission estimates derived from atmospheric observations help identify improvements to reduce uncertainties and increase the confidence in reported values. To facilitate comparisons over the contiguous United States, we present a 0.1° × 0.1° gridded inventory of annual 2012-2018 anthropogenic methane emissions, allocated to 26 individual source categories, with scale-dependent error estimates. Our inventory is consistent with the U.S. Environmental Protection Agency (EPA) Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHGI), submitted to the United Nations in 2020. Total emissions and patterns (spatial/temporal) reflect the activity and emission factor data underlying the GHGI, including many updates relative to a previous gridded version of the GHGI that has been extensively compared with observations. These underlying data are not generally available in global gridded inventories, and comparison to EDGAR version 6 shows large spatial differences, particularly for the oil and gas sectors. We also find strong regional variability across all sources in annual 2012-2018 spatial trends, highlighting the importance of understanding regional- and facility-level activities. Our inventory represents the first time series of gridded GHGI methane emissions and enables robust comparisons of emissions and their trends with atmospheric observations.

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.

The impact of methane leakage on the role of natural gas in the European energy transition

Decarbonising energy systems is a prevalent topic in the current literature on climate change mitigation, but the additional climate burden caused by methane emissions along the natural gas value chain is rarely discussed at the system level. Considering a two-basket greenhouse gas neutrality objective (both CO2 and methane), we model cost-optimal European energy transition pathways towards 2050. Our analysis shows that adoption of best available methane abatement technologies can entail an 80% reduction in methane leakage, limiting the additional environmental burden to 8% of direct CO2 emissions (vs. 35% today). We show that, while renewable energy sources are key drivers of climate neutrality, the role of natural gas strongly depends on actions to abate both associated CO2 and methane emissions. Moreover, clean hydrogen (produced mainly from renewables) can replace natural gas in a substantial proportion of its end-uses, satisfying nearly a quarter of final energy demand in a climate-neutral Europe.

Global land and water limits to electrolytic hydrogen production using wind and solar resources

Proposals for achieving net-zero emissions by 2050 include scaling-up electrolytic hydrogen production, however, this poses technical, economic, and environmental challenges. One such challenge is for policymakers to ensure a sustainable future for the environment including freshwater and land resources while facilitating low-carbon hydrogen production using renewable wind and solar energy. We establish a country-by-country reference scenario for hydrogen demand in 2050 and compare it with land and water availability. Our analysis highlights countries that will be constrained by domestic natural resources to achieve electrolytic hydrogen self-sufficiency in a net-zero target. Depending on land allocation for the installation of solar panels or wind turbines, less than 50% of hydrogen demand in 2050 could be met through a local production without land or water scarcity. Our findings identify potential importers and exporters of hydrogen or, conversely, exporters or importers of industries that would rely on electrolytic hydrogen. The abundance of land and water resources in Southern and Central-East Africa, West Africa, South America, Canada, and Australia make these countries potential leaders in hydrogen export.

Greenhouse gas emissions from U.S. crude oil pipeline accidents: 1968 to 2020

Crude oil pipelines are considered as the lifelines of energy industry. However, accidents of the pipelines can lead to severe public health and environmental concerns, in which greenhouse gas (GHG) emissions, primarily methane, are frequently overlooked. While previous studies examined fugitive emissions in normal operation of crude oil pipelines, emissions resulting from accidents were typically managed separately and were therefore not included in the emission account of oil systems. To bridge this knowledge gap, we employed a bottom-up approach to conducted the first-ever inventory of GHG emissions resulting from crude oil pipeline accidents in the United States at the state level from 1968 to 2020, and leveraged Monte Carlo simulation to estimate the associated uncertainties. Our results reveal that GHG emissions from accidents in gathering pipelines (~720,000 tCO2e) exceed those from transmission pipelines (~290,000 tCO2e), although significantly more accidents have occurred in transmission pipelines (6883 cases) than gathering pipelines (773 cases). Texas accounted for over 40% of total accident-related GHG emissions nationwide. Our study contributes to enhanced accuracy of the GHG account associated with crude oil transport and implementing the data-driven climate mitigation strategies.

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.

The prospects of flexible natural gas-fired CCGT within a green taxonomy

Despite increased commitments toward net zero, there will likely be a continued need for natural gas to provide low carbon dispatchable power and blue hydrogen to balance the increased penetration of renewables. We evaluate the CO2 emissions intensity of electricity produced by (i) natural gas-fired combined cycle gas turbine (CCGT) power plants with carbon capture and storage (CCS), and (ii) blue hydrogen CCGT plants which uses steam methane reforming with CCS to supply H2. This study aims to determine whether these assets are able to meet a possible green taxonomy emissions threshold of 100 kg CO2 eq/MWh. Key considerations include methane leakage, CO2 capture rate, and the impacts of start-up and shut down cycles performed by the CCGT-CCS plant. This study suggests that, in order for natural gas to play an enduring role in the transition toward net zero, managing GHG emissions from both the upstream natural gas supply chain and the conversion facility is key.

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.

An inventory of greenhouse gas emissions due to natural gas pipeline incidents in the United States and Canada from 1980s to 2021

Natural gas is believed to be a critical transitional energy source. However, natural gas pipelines, once failed, will contribute to a large amount of greenhouse gas (GHG) emissions, including methane from uncontrolled natural gas venting and carbon dioxide from flared natural gas. However, the GHG emissions caused by pipeline incidents are not included in the regular inventories, making the counted GHG amount deviate from the reality. This study, for the first time, establishes an inventory framework for GHG emissions including all natural gas pipeline incidents in the two of the largest gas producers and consumers in North America (United States and Canada) from 1980s to 2021. The inventory comprises GHG emissions resulting from gathering and transmission pipeline incidents in a total of 24 states or regions in the United States between 1970 and 2021, local distribution pipeline incidents in 22 states or regions between 1970 and 2021, as well as natural gas pipeline incidents in a total of 7 provinces or regions in Canada between 1979 and 2021. These datasets can improve the accuracy of regular emission inventories by covering more emission sources in the United States and Canada and provide essential information for climate-oriented pipeline integrity management.

Tiered Leak Detection and Repair Programs at Simulated Oil and Gas Production Facilities: Increasing Emission Reduction by Targeting High-Emitting Sources

Distributions of methane emission rates originating from oil and gas production facilities are highly skewed and span 6-8 orders of magnitude. Traditional leak detection and repair programs have relied on surveys with handheld detectors at intervals of 2 to 4 times a year to find and fix emissions; however, this approach may lead unintended emissions to be active for the same interval independently of their magnitude. In addition, manual surveys are labor intensive. Novel methane detection technologies offer opportunities to further reduce emissions by quickly detecting the high-emitters, which account for a disproportionate fraction of total emissions. In this work, combinations of methane detection technologies with a focus of targeting high-emitting sources were simulated in a tiered approach for facilities representative of the Permian Basin, a region with skewed emission rates where emissions above 100 kg/h account for 40-80% of production site-wide total emissions, which include sensors on satellites, aircraft, continuous monitors, and optical gas imaging (OGI) cameras, with variations on survey frequency, detection thresholds, and repair times. Results show that strategies that quickly detect and fix high-emitting sources while decreasing the frequency of OGI inspections, which find the smaller emissions, achieve higher reductions than quarterly OGI and, in some cases, reduce emissions further than monthly OGI.

Performance of Continuous Emission Monitoring Solutions under a Single-Blind Controlled Testing Protocol

Continuous emission monitoring (CM) solutions promise to detect large fugitive methane emissions in natural gas infrastructure sooner than traditional leak surveys, and quantification by CM solutions has been proposed as the foundation of measurement-based inventories. This study performed single-blind testing at a controlled release facility (release from 0.4 to 6400 g CH₄/h) replicating conditions that were challenging, but less complex than typical field conditions. Eleven solutions were tested, including point sensor networks and scanning/imaging solutions. Results indicated a 90% probability of detection (POD) of 3-30 kg CH₄/h; 6 of 11 solutions achieved a POD < 6 kg CH₄/h, although uncertainty was high. Four had true positive rates > 50%. False positive rates ranged from 0 to 79%. Six solutions estimated emission rates. For a release rate of 0.1-1 kg/h, the solutions' mean relative errors ranged from -44% to +586% with single estimates between -97% and +2077%, and 4 solutions' upper uncertainty exceeding +900%. Above 1 kg/h, mean relative error was -40% to +93%, with two solutions within ±20%, and single-estimate relative errors were from -82% to +448%. The large variability in performance between CM solutions, coupled with highly uncertain detection, detection limit, and quantification results, indicates that the performance of individual CM solutions should be well understood before relying on results for internal emissions mitigation programs or regulatory reporting.

Combustion, Chemistry, and Carbon Neutrality

Combustion is a reactive oxidation process that releases energy bound in chemical compounds used as fuels─energy that is needed for power generation, transportation, heating, and industrial purposes. Because of greenhouse gas and local pollutant emissions associated with fossil fuels, combustion science and applications are challenged to abandon conventional pathways and to adapt toward the demand of future carbon neutrality. For the design of efficient, low-emission processes, understanding the details of the relevant chemical transformations is essential. Comprehensive knowledge gained from decades of fossil-fuel combustion research includes general principles for establishing and validating reaction mechanisms and process models, relying on both theory and experiments with a suite of analytic monitoring and sensing techniques. Such knowledge can be advantageously applied and extended to configure, analyze, and control new systems using different, nonfossil, potentially zero-carbon fuels. Understanding the impact of combustion and its links with chemistry needs some background. The introduction therefore combines information on exemplary cultural and technological achievements using combustion and on nature and effects of combustion emissions. Subsequently, the methodology of combustion chemistry research is described. A major part is devoted to fuels, followed by a discussion of selected combustion applications, illustrating the chemical information needed for the future.

Reconciling Methane Emission Measurements for Offshore Oil and Gas Platforms with Detailed Emission Inventories: Accounting for Emission Intermittency

Comparisons of observation-based emission estimates with emission inventories for oil and gas production operations have demonstrated that intermittency in emissions is an important factor to be accounted for in reconciling inventories with observations. Most emission inventories do not directly report data on durations of active emissions, and the variability in emissions over time must be inferred from other measurements or engineering calculations. This work examines a unique emission inventory, assembled for offshore oil and gas production platforms in federal waters of the Outer Continental Shelf (OCS) of the United States, which reports production-related sources on individual platforms, along with estimates of emission duration for individual sources. Platform specific emission rates, derived from the inventory, were compared to shipboard measurements made at 72 platforms. The reconciliation demonstrates that emission duration reporting, by source, can lead to predicted ranges in emissions that are much broader than those based on annual average emission rates. For platforms in federal waters, total emissions reported in the inventory for the matched platforms were within ∼10% of emissions estimated based on observations, depending on emission rates assumed for nondetects in the observational data set. The distributions of emissions were similar, with 75% of platform total emission rates falling between 0 and 49 kg/h for the observations and between 0.59 and 54 kg/h for the inventory.

Planet-compatible pathways for transitioning the chemical industry

Chemical products, such as plastics, solvents, and fertilizers, are essential for supporting modern lifestyles. Yet, producing, using, and disposing of chemicals creates adverse environmental impacts which threaten the industry's license to operate. This study presents seven planet-compatible pathways toward 2050 employing demand-side and supply-side interventions with cumulative total investment costs of US$1.2-3.7 trillion. Resource efficiency and circularity interventions reduce global chemicals demand by 23 to 33% and are critical for mitigating risks associated with using fossil feedstocks and carbon capture and sequestration, and constraints on available biogenic and recyclate feedstocks. Replacing fossil feedstocks with biogenic/air-capture sources, shifting carbon destinations from the atmosphere to ground, and electrifying/decarbonizing energy supply for production technologies could enable net negative emissions of 0.5 GtCO_2eq y^-1 across non-ammonia chemicals, while still delivering essential chemical-based services to society.

Widespread Frequent Methane Emissions From the Oil and Gas Industry in the Permian Basin

Emissions of methane (CH₄) in the Permian basin (USA) have been derived for 2019 and 2020 from satellite observations of the Tropospheric Monitoring Instrument (TROPOMI) using the divergence method, in combination with a data driven method to estimate the background column densities. The resulting CH₄ emission data, which have been verified using model data with known emissions, have a spatial resolution of approximately 10 km. The CH₄ emissions show moderate spatial correlation with the locations of oil and gas production and drilling activities in the Permian basin, as well as with emissions of nitrogen oxides (NO_x). Analysis of the emission maps and time series indicates that a significant fraction of methane emissions in the Permian basin is from frequent widespread emissions sources, rather than from a few infrequent very large unplanned releases, which is important considering possible CH₄ emission mitigation strategies. In addition to providing spatially resolved emissions, the divergence method also provides the total emissions of the Permian basin and its main sub-basins. The total CH₄ emission of the Permian is estimated as 3.0 ± 0.7 Tg yr^-1 for 2019, which agrees with other independent estimates based on TROPOMI data. For the Delaware sub-basin, it is estimated as 1.4 ± 0.3 Tg yr^-1 for 2019, and for the Midland sub-basin 1.2 ± 0.3 Tg yr^-1. In 2020 the emissions are 9% lower compared to 2019 in the entire Permian basin, and respectively 19% and 27% for the Delaware and Midland sub-basins.

Photoacoustic methane detection inside a MEMS microphone

An innovative laser based photoacoustic (PA) gas sensing concept with intrinsic miniaturization potential was developed and investigated for methane trace gas detection. An interband cascade laser (ICL) with an optical power of 8.5 mW targets a methane (CH₄) absorption line feature around 3057.7 cm^-1 (or 3270 nm). The ICL was focused into the sound port of a MEMS microphone, where the PA signal was generated and detected using a wavelength modulation concept (2f-WMS-PAS). The MEMS microphone was successfully implemented as an intrinsically miniaturized PA cell being gas sensing volume, acoustic resonator and sound transducer at once. Frequencies between 2 kHz and 100 kHz were investigated and used for methane detection. A sensitive and resonant methane detection at 41.8 kHz was investigated by concentration variations between 0 and 10 ppm CH₄ in N₂. A limit of detection ( 3 σ -LOD) of 329 ppb was estimated. The long term stability of this sensor was investigated by the measurement of methane in ambient air. A noise equivalent concentration (NEC) of 14 ppb (parts per billion) at an average time of 10 s was estimated. This value corresponds to a normalized noise equivalent absorption (NNEA) of 2 ⋅ 1 0 - 8 W cm^-1 Hz^-1/2. Using the MEMS microphone directly as PA cell offers the possibility for an extremely miniaturized, highly sensitive and very cost-efficient photoacoustic trace gas sensor.

Assessing Detection Efficiencies for Continuous Methane Emission Monitoring Systems at Oil and Gas Production Sites

Continuous monitoring systems, consisting of multiple fixed sensors, are increasingly being deployed at oil and gas production sites to detect methane emissions. While these monitoring systems operate continuously, their efficiency in detecting emissions will depend on meteorological conditions, sensor detection limits, the number of sensors deployed, and sensor placement strategies. This work demonstrates an approach to assess the effectiveness of continuous sensor networks in detecting infinite-duration and fixed-duration emission events. The case studies examine a single idealized source and a group of nine different sources at varying heights and locations on a single pad. Using site-specific meteorological data and dispersion modeling, the emission detection performance is characterized. For these case studies, infinite-duration emission events are detected within 1 h to multiple days, depending on the number of sensors deployed. The percentage of fixed-duration emission events that are detected ranged from less than 10% to more than 90%, depending on the number of sources, emission release height, emission event duration, and the number of sensors deployed. While these results are specific to these case studies, the analysis framework described in this work can be broadly applied in the evaluation of continuous emission monitoring network designs.

Investigating the Potential of Thin Silicon Nitride Membranes in Fiber-Based Photoacoustic Sensing

The detection of methane, a strong greenhouse gas, has increased in importance due to rising emissions, which partly originate from unreported and undetected leaks in oil and gas fields. The gas emitted by these leaks could be detected using an optical fiber-based photoacoustic sensor called PAS-WRAP. Here, we investigate the potential of silicon-based membranes as more sensitive microphones in the PAS-WRAP concept. Toward this goal, we built a setup with which the frequency response of the membranes was interrogated by an optical fiber. Multiple mounting mechanisms were tested by adapting commercial interferometry systems (OP1550, ZonaSens, Optics11 B.V.) to our case. Finally, methane detection was attempted using a silicon nitride membrane as a sensor. Our findings show a quality factor of 2.4 at 46 kHz and 33.6 at 168 kHz for a thin silicon nitride membrane. This membrane had a frequency response with a signal-to-background ratio of 1 ± 0.7 at 44 kHz when tested in a vacuum chamber with 4% methane at 0.94 bar. The signal-to-background ratio was not significant for methane detection; however, we believe that the methods and experimental procedures that we used in this work can provide a useful reference for future research into gas trace detection with optical fiber-based photoacoustic spectroscopy.

An Analysis of the Potential and Cost of the U.S. Refinery Sector Decarbonization

In 2019, U.S. petroleum refineries emitted 196 million metric tons (MT) of CO2, while the well-to-gate and the full life cycle CO2 emissions were significantly higher, reaching 419 and 2843 million MT of CO2, respectively. This analysis examines decarbonization opportunities for U.S. refineries and the cost to achieve both refinery-level and complete life-cycle CO2 emission reductions. We used 2019 life-cycle CO2 emissions from U.S. refineries as a baseline and identified three categories of decarbonization opportunity: (1) switching refinery energy inputs from fossil to renewable sources (e.g., switch hydrogen source); (2) carbon capture and storage of CO2 from various refining units; and (3) changing the feedstock from petroleum crude to biocrude using various blending levels. While all three options can reduce CO2 emissions from refineries, only the third can reduce emissions throughout the life cycle of refinery products, including the combustion of fuels (e.g., gasoline and diesel) during end use applications. A decarbonization approach that combines strategies 1, 2, and 3 can achieve negative life-cycle CO2 emissions, with an average CO2 avoidance cost of $113-$477/MT CO2, or $54-$227/bbl of processed crude; these costs are driven primarily by the high cost of biocrude feedstock.

Evaluating Natural Gas Emissions from Pneumatic Controllers from Upstream Oil and Gas Facilities in West Virginia

In April of 2018, an optical gas imaging (OGI) and full flow sampler (FFS) emissions measurement study of pneumatic controllers (PCs) was conducted at 15 oil and natural gas production sites in West Virginia. The objective of the study was to identify and characterize PC systems with excessive emissions caused by maintenance issues or nonoptimized process conditions. A total of 391 PC systems were found on the sites and all were classified by the operator as snap-acting (on/off) intermittent venting PCs (IPCs) that should exhibit little gas release while the PC is closed between actuation events. The population was comprised of two groups, 259 infrequently actuating, lower emitting (LE) IPCs and 132 gas processing unit (GPU) liquid level IPCs and associated dump valve actuators that vent more frequently and have larger emission volumes. Using a PC-specific OGI inspection protocol with an assumed whole gas OGI detection threshold of 2.0 scfh, only 2 out of 259 LE-IPCs exhibited OGI detectable emissions indicating good inspection and maintenance practices for this category. Due to combined (ganged) GPU exhaust vents, the OGI inspection of the GPU liquid level IPCs was comparatively less informative and determination of single component IPC emissions by the FFS was more difficult. The time resolved FFS measurements of GPU IPCs defined three categories of operation: one that indicated proper function and two associated with higher emissions that may result from an IPC maintenance or process issues. The overall GPU IPC emission distribution was heavy tailed, with a median value of 12.8 scfh, similar to the 13.5 scfh whole gas IPC emission factor (EF). Total emissions were dominated by non-optimal temporal profile high-emitter IPC cases with the top 20% of IPC systems accounting for between 51.3% and 70.7% of GPU liquid level IPC emissions by volume. The uncertainty in the estimate was due to the ganged nature of the GPU exhaust vents. The highest GPU IPC emission came from a single malfunctioning unit with a measured whole gas value of 157 scfh. Up to six IPCs exceeded 100 scfh. An analysis of FFS emission measurements compared to liquids production per IPC unit employed indicated that production sites operating at a high level of liquids production test the limits of the site engineering, likely resulting in higher IPC emissions. Overall, this study found that the LE-IPCs with OGI-verified low closed bleed rates may emit well below the IPC EF while GPU liquid level IPC systems are likely well represented by the current IPC EF. IPCs that are experiencing a maintenance or process issue or that are operating at sites with a very high product throughput per IPC employed can emit at rates exceeding ten times IPC EF.

Manmade earthquakes and healthcare visits for anxiety disorders in Oklahoma, 2010-2019

Since 2010, seismicity in Oklahoma has increased from wastewater injection. It remains unknown if these earthquakes have resulted in increased treatment seeking for mental healthcare services.

Methods

Using data from a nationwide United States patient-level commercial and Medicare Advantage claims database from 2010 to 2019, we identified healthcare encounters for anxiety disorders using diagnostic codes and subclassified them as adjustment reaction; anxiety-related disorders; physical symptoms of anxiety; and stress disorders. With U.S. Geological Survey Advanced National Seismic System data, we generated county-level 6-month rolling counts of felt earthquakes (≥M 4) and linked them to patient residential county at the time of the healthcare visit. In this repeated measures, individual-level analysis we used generalized estimating equations to estimate the odds of monthly anxiety-related healthcare visits as a function of the frequency of ≥M 4 earthquakes in the previous 6 months.

Results

We identified 4,594 individuals in Oklahoma observed from 2010 to 2019. For every additional five ≥M 4 earthquakes in the preceding 6 months, the odds of healthcare visits for stress disorders increased (odds ratio [OR] = 1.27; 95% confidence interval [CI] = 1.03, 1.57). We found no evidence of an association with adjustment reaction (OR = 1.05; 95% CI = 0.89, 1.23), anxiety-related disorders (OR = 0.96; 95% CI = 0.90, 1.03), or physical symptoms of anxiety (OR = 1.03; 95% CI = 0.98, 1.09).

Conclusions

We report an association between increased frequency of felt earthquakes and treatment seeking for stress disorders. This finding should motivate ongoing study of the potential consequences of the oil and gas industry for mental health outcomes including anxiety disorders.

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.

Reconciling Multiple Methane Detection and Quantification Systems at Oil and Gas Tank Battery Sites

Emission rates were estimated for >100 oil and gas production sites with significant liquid-handling equipment (tank battery sites) in the Permian Basin of west Texas. Emission estimates based on equipment counts and emission factors, but not accounting for large uninventoried emission events, led to ensemble average emission rates of 1.8-3.6 kg/h per site. None of the site-specific emission estimates for individual sites, based on equipment counts, exceeded 10 kg/h. On-site drone-based emission measurements led to similar emission estimates for inventoried sources. Multiple aircraft measurement platforms were deployed and reported emissions exceeding 10 kg/h at 14-27% of the sites, and these high-emission rate sites accounted for 80-90% of total emissions for the ensemble of sites. The aircraft measurement systems were deployed asynchronously but within a 5 day period. At least half of the sites with emission rates above 10 kg/h detected by aircraft had emissions that did not persist at a level above 10 kg/h for repeat measurements, suggesting typical high-emission rate durations of a few days or less for many events. The two aircraft systems differed in their estimates of total emissions from the ensembles of sites sampled by more than a factor of 2; however, the normalized distributions of emissions for sites with emission rates of >10 kg/h were comparable for the two aircraft-based methods. The differences between the two aircraft-based platforms are attributed to a combination of factors; however, both aircraft-based emission measurement systems attribute a large fraction of emissions to sites with an emission rate of >10 kg/h.

Methane Emissions from Natural Gas Gathering Pipelines in the Permian Basin

The rapid reduction of methane emissions, especially from oil and gas (O&G) operations, is a critical part of slowing global warming. However, few studies have attempted to specifically characterize emissions from natural gas gathering pipelines, which tend to be more difficult to monitor on the ground than other forms of O&G infrastructure. In this study, we use methane emission measurements collected from four recent aerial campaigns in the Permian Basin, the most prolific O&G basin in the United States, to estimate a methane emission factor for gathering lines. From each campaign, we calculate an emission factor between 2.7 (+1.9/-1.8, 95% confidence interval) and 10.0 (+6.4/-6.2) Mg of CH₄ year^-1 km^-1, 14-52 times higher than the U.S. Environmental Protection Agency's national estimate for gathering lines and 4-13 times higher than the highest estimate derived from a published ground-based survey of gathering lines. Using Monte Carlo techniques, we demonstrate that aerial data collection allows for a greater sample size than ground-based data collection and therefore more comprehensive identification of emission sources that comprise the heavy tail of methane emissions distributions. Our results suggest that pipeline emissions are underestimated in current inventories and highlight the importance of a large sample size when calculating basinwide pipeline emission factors.

Evaluating the detectability of methane point sources from satellite observing systems using microscale modeling

This study evaluates the efficacy of current satellite observing systems to detect methane point sources from typical oil and gas production (O&G) facilities using a novel very high-resolution methane concentration dataset generated using a microscale model. Transport and dispersion of typical methane emissions from seven well pads were simulated and the column enhancements for pseudo satellite pixel sizes of 3, 1, and 0.05 km were examined every second of the 2-h simulations (7200 realizations). The detectability of plumes increased with a pixel resolution, but two orders of magnitude change in emission rates at the surface results only in about 0.4%, 1.6%, and 47.8% enhancement in the pseudo-satellite retrieved methane column at 3, 1, and 0.05 km, respectively. Average methane emission rates estimated by employing the integrated mass enhancement (IME) method to column enhancements at 0.05 km showed an underestimation of the mean emissions by 0.2-6.4%. We show that IME derived satellite-based inversions of methane emissions work well for large persistent emission sources (e.g., super emitters), however, the method is ill-suited to resolve short-term emission fluctuations (< 20 min) in typical well site emissions due to the limitations in satellite detection limits, precision, overpass timing, and pixel resolution.

Multiscale Methane Measurements at Oil and Gas Facilities Reveal Necessary Frameworks for Improved Emissions Accounting

Methane mitigation from the oil and gas (O&G) sector represents a key near-term global climate action opportunity. Recent legislation in the United States requires updating current methane reporting programs for oil and gas facilities with empirical data. While technological advances have led to improvements in methane emissions measurements and monitoring, the overall effectiveness of mitigation strategies rests on quantifying spatially and temporally varying methane emissions more accurately than the current approaches. In this work, we demonstrate a quantification, monitoring, reporting, and verification framework that pairs snapshot measurements with continuous emissions monitoring systems (CEMS) to reconcile measurements with inventory estimates and account for intermittent emission events. We find that site-level emissions exhibit significant intraday and daily emission variations. Snapshot measurements of methane can span over 3 orders of magnitude and may have limited application in developing annualized inventory estimates at the site level. Consequently, while official inventories underestimate methane emissions on average, emissions at individual facilities can be higher or lower than inventory estimates. Using CEMS, we characterize distributions of frequency and duration of intermittent emission events. Technologies that allow high sampling frequency such as CEMS, paired with a mechanistic understanding of facility-level events, are key to an accurate accounting of short-duration, episodic, and high-volume events that are often missed in snapshot surveys and to scale snapshot measurements to annualized emissions estimates.

Inefficient and unlit natural gas flares both emit large quantities of methane

Flaring is widely used by the fossil fuel industry to dispose of natural gas. Industry and governments generally assume that flares remain lit and destroy methane, the predominant component of natural gas, with 98% efficiency. Neither assumption, however, is based on real-world observations. We calculate flare efficiency using airborne sampling across three basins responsible for >80% of US flaring and combine these observations with unlit flare prevalence surveys. We find that both unlit flares and inefficient combustion contribute comparably to ineffective methane destruction, with flares effectively destroying only 91.1% (90.2, 91.8; 95% confidence interval) of methane. This represents a fivefold increase in methane emissions above present assumptions and constitutes 4 to 10% of total US oil and gas methane emissions, highlighting a previously underappreciated methane source and mitigation opportunity.

Reduction of Signal Drift in a Wavelength Modulation Spectroscopy-Based Methane Flux Sensor

Accurately quantifying unsteady methane venting from key oil and gas sector sources such as storage tanks and well casing vents is a critical challenge. Recently, we presented an optical sensor to meet this need that combines volume fraction and Doppler shift measurements using wavelength modulation spectroscopy with 2f harmonic detection to quantify mass flux of methane through a vent line. This paper extends the previous effort through a methodical component-by-component investigation of potential sources of thermally-induced measurement drift to guide the design of an updated sensor. Test data were analyzed using an innovative signal processing technique that permitted quantification of background wavelength modulation spectroscopy signal drift linked to specific components, and the results were successfully used to design a drift-resistant sensor. In the updated sensor, background signal strength was reduced, and stability improved, such that the empirical methane-fraction dependent velocity correction necessary in the original sensor was no longer required. The revised sensor improves previously reported measurement uncertainties on flow velocity from 0.15 to 0.10 m/s, while markedly reducing thermally-induced velocity drift from 0.44 m/s/K to 0.015 m/s/K. In the most general and challenging application, where both flow velocity and methane fraction are independently varying, the updated design reduces the methane mass flow rate uncertainty by more than a factor of six, from ±2.55 kg/h to ±0.40 kg/h. This new design also maintains the intrinsic safety of the original sensor and is ideally suited for unsteady methane vent measurements within hazardous locations typical of oil and gas facilities.

Using satellites to uncover large methane emissions from landfills

As atmospheric methane concentrations increase at record pace, it is critical to identify individual emission sources with high potential for mitigation. Here, we leverage the synergy between satellite instruments with different spatiotemporal coverage and resolution to detect and quantify emissions from individual landfills. We use the global surveying Tropospheric Monitoring Instrument (TROPOMI) to identify large emission hot spots and then zoom in with high-resolution target-mode observations from the GHGSat instrument suite to identify the responsible facilities and characterize their emissions. Using this approach, we detect and analyze strongly emitting landfills (3 to 29 t hour^-1) in Buenos Aires, Delhi, Lahore, and Mumbai. Using TROPOMI data in an inversion, we find that city-level emissions are 1.4 to 2.6 times larger than reported in commonly used emission inventories and that the landfills contribute 6 to 50% of those emissions. Our work demonstrates how complementary satellites enable global detection, identification, and monitoring of methane superemitters at the facility level.

Is the Production of Agricultural Biogas Environmentally Friendly? Does the Structure of Consumption of First- and Second-Generation Raw Materials in Latvia and Poland Matter?

The importance of biogas in the energy mix in Poland and Latvia is very low. In Poland, 306 million m3 of biogas is produced annually, and in Latvia, 56 million m3. The share of energy from agricultural biogas in Latvia is 1.6%, and in Poland, only 0.12%. This study analyzed the impact of the structure on CO2 emissions from agricultural biogas production in Latvia and Poland. The emission was determined in accordance with the EU directive. The structure of substrates was dominated by those from the second generation, i.e., manure and food waste. In Latvia, it was 70%, and in Poland, 78%. The manure share was 45% and 24%, respectively. The anaerobic digestion of manure guarantees high GHG savings thanks to the avoided emissions from the traditional storage and management of raw manure as organic fertilizer. The level of emissions from the production of agricultural biogas was calculated for the variant with the use of closed digestate tanks, and it was about 10–11 g CO2/MJ, which is comparable to the emissions from solar photovoltaic sources. When using open tanks, the emission level was twice as high, but it was still many times less than from the Polish or Latvian energy mix. Such a low level of emissions resulted from the high share of manure. The level of emission reduction reached 90% compared to fossil fuels. The use of second-generation feedstock in biogas production provides environmental benefits. Therefore, if wastes are used in biogas generation, and the influence on the local environment and overall GHG emissions is positive, authorities should support such activity.

Total Methane and CO2 Emissions from Liquefied Natural Gas Carrier Ships: The First Primary Measurements

Mitigating methane emissions is vital in meeting global climate targets, but there is a lack of understanding of emissions and abatement opportunities to enable this. The natural gas supply chain is a key emission source, where methane emissions from liquefied natural gas (LNG) shipping have until now not been directly measured. This study provides the first measurement and modeling of total methane and CO₂ emissions from an LNG carrier on a round trip voyage from the USA to Belgium and back, including loading, laden voyage, unloading, and ballast voyage, measuring emissions from exhaust stacks, vents, and fugitives. Venting and fugitive emissions were extremely low, contributing less than 0.1% of total greenhouse gas emissions. CO₂ emissions from fuel usage were also lower than previous estimates due to improved efficiencies in modern engines and ship design. However, methane slip through the engines were higher than those in prior studies, averaging 3.8% across all engines: equating to 0.1% of delivered LNG. Generator engines are not typically included in emissions analyses but were the key cause of methane emissions. Engines exhibited higher methane slip rates at low loads, and optimized operation could reduce slip rates by half. More measurement studies are now needed to better understand fleet emissions and enable cost-effective mitigation strategies.

Shale Gas Decarbonization in the Permian Basin: Is It Possible?

The United States is unique in the energy reserves held in shale gas fields, which coproduce natural gas and natural gas liquids. Use of this resource, however, contributes to greenhouse gas emissions and, correspondingly, climate change. We explore how natural gas and natural gas liquids might build bridges toward low-carbon transportation fuels. For example, as petroleum refineries produce less gasoline in response to widespread electrification, natural gas liquids can be converted to fuel. We consider whether the greenhouse gas emissions from production and use of these fuels might be offset through three potential outcomes of converting coproduced natural gas to CO₂ through steam methane reforming. First, the CO₂ could be injected into conventional oil formations for enhanced oil recovery. Second, it could be sequestered into saline aquifers to avoid CO₂ emissions from the produced oil combustion. Third, it could be injected into unconventional gas formations in the form of CO₂-based fracturing fluids. Simultaneously, the coproduced hydrogen from steam methane reforming could be used to support the expansion of the hydrogen economy. The region of study is the Permian Basin. The results show sizeable emission benefits by decreasing net emissions of natural gas production and use to 28 from 88 g-CO₂e/MJ. For revenue generating pathways, a partial decarbonization of 3.4 TCF/year is possible. All of the natural gas can be partially decarbonized if the CO₂ is sequestered in saline aquifers. Overall, the results show that while greenhouse gas emissions can be reduced through decarbonization approaches relying on subsurface sequestration, full natural gas decarbonization is not achieved but must be pursued through other approaches.