Impact of Biomass Burning Organic Aerosol Volatility on Smoke Concentrations Downwind of Fires.

Biomass burning particulate matter (BBPM) affects regional air quality and global climate, with impacts expected to continue to grow over the coming years. We show that studies of North American fires have a systematic altitude dependence in measured BBPM normalized excess mixing ratio (NEMR; ΔPM/ΔCO), with airborne and high-altitude studies showing a factor of 2 higher NEMR than ground-based measurements. We report direct airborne measurements of BBPM volatility that partially explain the difference in the BBPM NEMR observed across platforms. We find that when heated to 40-45 °C in an airborne thermal denuder, 19% of lofted smoke PM1 evaporates. Thermal denuder measurements are consistent with evaporation observed when a single smoke plume was sampled across a range of temperatures as the plume descended from 4 to 2 km altitude. We also demonstrate that chemical aging of smoke and differences in PM emission factors can not fully explain the platform-dependent differences. When the measured PM volatility is applied to output from the High Resolution Rapid Refresh Smoke regional model, we predict a lower PM NEMR at the surface compared to the lofted smoke measured by aircraft. These results emphasize the significant role that gas-particle partitioning plays in determining the air quality impacts of wildfire smoke.

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.

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.

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.

Traffic, transport, and vegetation drive VOC concentrations in a major urban area in Texas.

The population of Texas has increased rapidly in the past decade. The San Antonio Field Study (SAFS) was designed to investigate ozone (O3) production and precursors in this rapidly changing, sprawling metropolitan area. There are still many questions regarding the sources and chemistry of volatile organic compounds (VOCs) in urban areas like San Antonio which are affected by a complex mixture of industry, traffic, biogenic sources and transported pollutants. The goal of the SAFS campaign in May 2017 was to measure inorganic trace gases, VOCs, methane (CH4), and ethane (C2H6). The SAFS field design included two sites to better assess air quality across the metro area: an urban site (Traveler's World; TW) and a downwind/suburban site (University of Texas at San Antonio; UTSA). The results indicated that acetone (2.52 ± 1.17 and 2.39 ± 1.27 ppbv), acetaldehyde (1.45 ± 1.02 and 0.93 ± 0.45 ppbv) and isoprene (0.64 ± 0.49 and 1.21 ± 0.85 ppbv; TW and UTSA, respectively) were the VOCs with the highest concentrations. Additionally, positive matrix factorization showed three dominant factors of VOC emissions: biogenic, aged urban mixed source, and acetone. Methyl vinyl ketone and methacrolein (MVK + MACR) exhibited contributions from both secondary photooxidation of isoprene and direct emissions from traffic. The C2H6:CH4 demonstrated potential influence of oil and gas activities in San Antonio. Moreover, the high O3 days during the campaign were in the NOx-limited O3 formation regime and were preceded by evening peaks in select VOCs, NOx and CO. Overall, quantification of the concentration and trends of VOCs and trace gases in a major city in Texas offers vital information for general air quality management and supports strategies for reducing O3 pollution. The SAFS campaign VOC results will also add to the growing body of literature on urban sources and concentrations of VOCs in major urban areas.

Chemical Emissions from Cured and Uncured 3D-Printed Ventilator Patient Circuit Medical Parts.

Medical shortages during the COVID-19 pandemic saw numerous efforts to 3D print personal protective equipment and treatment supplies. There is, however, little research on the potential biocompatibility of 3D-printed parts using typical polymeric resins as pertaining to volatile organic compounds (VOCs), which have specific relevance for respiratory circuit equipment. Here, we measured VOCs emitted from freshly printed stereolithography (SLA) replacement medical parts using proton transfer reaction mass spectrometry and infrared differential absorption spectroscopy, and particulates using a scanning mobility particle sizer. We observed emission factors for individual VOCs ranging from ∼0.001 to ∼10 ng cm-3 min-1. Emissions were heavily dependent on postprint curing and mildly dependent on the type of SLA resin. Curing reduced the emission of all observed chemicals, and no compounds exceeded the recommended dose of 360 µg/d. VOC emissions steadily decreased for all parts over time, with an average e-folding time scale (time to decrease to 1/e of the starting value) of 2.6 ± 0.9 h.

Oxygenated Aromatic Compounds are Important Precursors of Secondary Organic Aerosol in Biomass-Burning Emissions.

Biomass burning is the largest combustion-related source of volatile organic compounds (VOCs) to the atmosphere. We describe the development of a state-of-the-science model to simulate the photochemical formation of secondary organic aerosol (SOA) from biomass-burning emissions observed in dry (RH <20%) environmental chamber experiments. The modeling is supported by (i) new oxidation chamber measurements, (ii) detailed concurrent measurements of SOA precursors in biomass-burning emissions, and (iii) development of SOA parameters for heterocyclic and oxygenated aromatic compounds based on historical chamber experiments. We find that oxygenated aromatic compounds, including phenols and methoxyphenols, account for slightly less than 60% of the SOA formed and help our model explain the variability in the organic aerosol mass (R2 = 0.68) and O/C (R2 = 0.69) enhancement ratios observed across 11 chamber experiments. Despite abundant emissions, heterocyclic compounds that included furans contribute to ∼20% of the total SOA. The use of pyrolysis-temperature-based or averaged emission profiles to represent SOA precursors, rather than those specific to each fire, provide similar results to within 20%. Our findings demonstrate the necessity of accounting for oxygenated aromatics from biomass-burning emissions and their SOA formation in chemical mechanisms.

Methane Emissions from Offshore Oil and Gas Platforms in the Gulf of Mexico.

Shipboard measurements of offshore oil and gas facilities were conducted in the Gulf of Mexico in February 2018. Species measured at 1 s include methane, ethane, carbon-13 (13C) and deuterium (D) isotopes of methane, and several combustion tracers. Significant variability in the emission composition is observed between individual sites, with typical ethane/methane ratios around 5.3% and 13C and D methane isotopic compositions around -40 and -240‰, respectively. Offshore plumes were spatially narrower than expectations of the plume width based on terrestrial atmospheric stability classes; a modified Gaussian dispersion methodology using empirically measured horizontal plume widths was used to estimate the emission rates. A total of 103 sites were studied, including shallow and deepwater offshore platforms and drillships. Methane emission rates range from 0 to 190 kg/h with 95% confidence limits estimated at a factor of 10. The observed distribution is skewed with the top two emitters accounting for 20% of the total methane emissions of all sampled sites. Despite the greater throughput of the deepwater facilities, they had moderate emission rates compared to shallow-water sites. Analysis of background ethane enhancements also suggests a source region in shallow waters. A complete 1 s measurement database is published for use in future studies of offshore dispersion.

Use of Light Alkane Fingerprints in Attributing Emissions from Oil and Gas Production.

Spatially resolved emission inventories were used with an atmospheric dispersion model to predict ambient concentrations of methane, ethane, and propane in the Eagle Ford oil and gas production region in south central Texas; predicted concentrations were compared to ground level observations. Using a base case inventory, predicted median propane/ethane concentration ratios were 106% higher (95% CI: 83% higher-226% higher) than observations, while median ethane/methane concentration ratios were 112% higher (95% CI: 17% higher-228% higher) than observations. Predicted median propane and ethane concentrations were factors of 6.9 (95% CI: 3-15.2) and 3.4 (95% CI: 1.4-9) larger than observations, respectively. Predicted median methane concentrations were 7% higher (95% CI: 39% lower-37% higher) than observations. These comparisons indicate that sources of emissions with high propane/ethane ratios (condensate tank flashing) were likely overestimated in the inventories. Because sources of propane and ethane emissions are also sources of methane emissions, the results also suggest that sources of emissions with low ethane/methane ratios (midstream sources) were underestimated. This analysis demonstrates the value of using multiple light alkanes in attributing sources of methane emissions and evaluating the performance of methane emission inventories for oil and natural gas production regions.

Characterization of Spatial Air Pollution Patterns Near a Large Railyard Area in Atlanta, Georgia.

Railyards are important transportation hubs, and they are often situated near populated areas with high co-located density of manufacturing, freight movement and commercial enterprises. Emissions occurring within railyards can affect nearby air quality. To better understand the air pollution levels in proximity to a major railyard, an intensive mobile air monitoring study was conducted in May 2012 around a major railyard area in Atlanta, GA, constituted of two separate facilities situated side-by-side. A total of 19 multi-hour mobile monitoring sessions took place over different times of day, days of the week, and under a variety of wind conditions. High time resolution measurements included black carbon (BC), particle number concentration (PN), particle optical extinction (EXT), oxides of nitrogen (NO, NO2, NOy), carbon monoxide (CO), and speciated air toxics. Urban background was estimated to contribute substantially (>70%) to EXT and CO, whereas BC, oxides of nitrogen (NOx) and toluene had comparably low background contributions (<30%). Mobile monitoring data were aggregated into 50 meter spatial medians by wind categories, with categories including low speed wind conditions (<0.5 m s-1) and, for wind speeds above that threshold, by wind direction relative to the railyard. Spatial medians of different pollutants measured had a wide range of correlation-gas-phase air toxics (benzene, toluene, acetaldehyde) had moderate correlation with each other (r = 0.46⁻0.59) and between toluene and CO (r = 0.53), but lower correlation for other pairings. PN had highest correlation with oxides of nitrogen (r = 0.55⁻0.66), followed by BC (r = 0.4), and lower correlation with other pollutants. Multivariate regression analysis on the full set of 50 m medians found BC and NO as having the strongest relationship to railyard emissions, in comparison to their respective background levels. This was indicated by an increase associated with transiting through the yard and inverse relationship with distance from the railyard; NO and BC decreased by a factor of approximately 0.5 and 0.7 over 1 km distance of the railyard boundary, respectively. Low speed, variable wind conditions were related to higher concentrations of all measured parameters.

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

Methane emissions from the U.S. oil and natural gas supply chain were estimated by using ground-based, facility-scale measurements and validated with aircraft observations in areas accounting for ~30% of U.S. gas production. When scaled up nationally, our facility-based estimate of 2015 supply chain emissions is 13 ± 2 teragrams per year, equivalent to 2.3% of gross U.S. gas production. This value is ~60% higher than the U.S. Environmental Protection Agency inventory estimate, likely because existing inventory methods miss emissions released during abnormal operating conditions. Methane emissions of this magnitude, per unit of natural gas consumed, produce radiative forcing over a 20-year time horizon comparable to the CO2 from natural gas combustion. Substantial emission reductions are feasible through rapid detection of the root causes of high emissions and deployment of less failure-prone systems.

Characterization of methane emissions from five cold heavy oil production with sands (CHOPS) facilities.

Cold heavy oil production with sands (CHOPS) is a common oil extraction method in the Canadian provinces of Alberta and Saskatchewan that can result in significant methane emissions due to annular venting. Little is known about the magnitude of these emissions, nor their contributions to the regional methane budget. Here the authors present the results of field measurements of methane emissions from CHOPS wells and compare them with self-reported venting rates. The tracer ratio method was used not only to analyze total site emissions but at one site it was also used to locate primary emission sources and quantify their contributions to the facility-wide emission rate, revealing the annular vent to be a dominant source. Emissions measured from five different CHOPS sites in Alberta showed large discrepancies between the measured and reported rates, with emissions being mainly underreported. These methane emission rates are placed in the context of current reporting procedures and the role that gas-oil ratio (GOR) measurements play in vented volume estimates. In addition to methane, emissions of higher hydrocarbons were also measured; a chemical "fingerprint" associated with CHOPS wells in this region reveals very low emission ratios of ethane, propane, and aromatics versus methane. The results of this study may inform future studies of CHOPS sites and aid in developing policy to mitigate regional methane emissions. IMPLICATIONS: Methane measurements from cold heavy oil production with sand (CHOPS) sites identify annular venting to be a potentially major source of emissions at these facilities. The measured emission rates are generally larger than reported by operators, with uncertainty in the gas-oil ratio (GOR) possibly playing a large role in this discrepancy. These results have potential policy implications for reducing methane emissions in Alberta in order to achieve the Canadian government's goal of reducing methane emissions by 40-45% below 2012 levels within 8 yr.

Reconciling divergent estimates of oil and gas methane emissions.

Published estimates of methane emissions from atmospheric data (top-down approaches) exceed those from source-based inventories (bottom-up approaches), leading to conflicting claims about the climate implications of fuel switching from coal or petroleum to natural gas. Based on data from a coordinated campaign in the Barnett Shale oil and gas-producing region of Texas, we find that top-down and bottom-up estimates of both total and fossil methane emissions agree within statistical confidence intervals (relative differences are 10% for fossil methane and 0.1% for total methane). We reduced uncertainty in top-down estimates by using repeated mass balance measurements, as well as ethane as a fingerprint for source attribution. Similarly, our bottom-up estimate incorporates a more complete count of facilities than past inventories, which omitted a significant number of major sources, and more effectively accounts for the influence of large emission sources using a statistical estimator that integrates observations from multiple ground-based measurement datasets. Two percent of oil and gas facilities in the Barnett accounts for half of methane emissions at any given time, and high-emitting facilities appear to be spatiotemporally variable. Measured oil and gas methane emissions are 90% larger than estimates based on the US Environmental Protection Agency's Greenhouse Gas Inventory and correspond to 1.5% of natural gas production. This rate of methane loss increases the 20-y climate impacts of natural gas consumed in the region by roughly 50%.

Enhanced light absorption by mixed source black and brown carbon particles in UK winter.

Black carbon (BC) and light-absorbing organic carbon (brown carbon, BrC) play key roles in warming the atmosphere, but the magnitude of their effects remains highly uncertain. Theoretical modelling and laboratory experiments demonstrate that coatings on BC can enhance BC's light absorption, therefore many climate models simply assume enhanced BC absorption by a factor of ∼1.5. However, recent field observations show negligible absorption enhancement, implying models may overestimate BC's warming. Here we report direct evidence of substantial field-measured BC absorption enhancement, with the magnitude strongly depending on BC coating amount. Increases in BC coating result from a combination of changing sources and photochemical aging processes. When the influence of BrC is accounted for, observationally constrained model calculations of the BC absorption enhancement can be reconciled with the observations. We conclude that the influence of coatings on BC absorption should be treated as a source and regionally specific parameter in climate models.

Methane Emissions from United States Natural Gas Gathering and Processing.

New facility-level methane (CH4) emissions measurements obtained from 114 natural gas gathering facilities and 16 processing plants in 13 U.S. states were combined with facility counts obtained from state and national databases in a Monte Carlo simulation to estimate CH4 emissions from U.S. natural gas gathering and processing operations. Total annual CH4 emissions of 2421 (+245/-237) Gg were estimated for all U.S. gathering and processing operations, which represents a CH4 loss rate of 0.47% (±0.05%) when normalized by 2012 CH4 production. Over 90% of those emissions were attributed to normal operation of gathering facilities (1697 +189/-185 Gg) and processing plants (506 +55/-52 Gg), with the balance attributed to gathering pipelines and processing plant routine maintenance and upsets. The median CH4 emissions estimate for processing plants is a factor of 1.7 lower than the 2012 EPA Greenhouse Gas Inventory (GHGI) estimate, with the difference due largely to fewer reciprocating compressors, and a factor of 3.0 higher than that reported under the EPA Greenhouse Gas Reporting Program. Since gathering operations are currently embedded within the production segment of the EPA GHGI, direct comparison to our results is complicated. However, the study results suggest that CH4 emissions from gathering are substantially higher than the current EPA GHGI estimate and are equivalent to 30% of the total net CH4 emissions in the natural gas systems GHGI. Because CH4 emissions from most gathering facilities are not reported under the current rule and not all source categories are reported for processing plants, the total CH4 emissions from gathering and processing reported under the EPA GHGRP (180 Gg) represents only 14% of that tabulated in the EPA GHGI and 7% of that predicted from this study.

Aircraft-Based Measurements of Point Source Methane Emissions in the Barnett Shale Basin.

We report measurements of methane (CH4) emission rates observed at eight different high-emitting point sources in the Barnett Shale, Texas, using aircraft-based methods performed as part of the Barnett Coordinated Campaign. We quantified CH4 emission rates from four gas processing plants, one compressor station, and three landfills during five flights conducted in October 2013. Results are compared to other aircraft- and surface-based measurements of the same facilities, and to estimates based on a national study of gathering and processing facilities emissions and 2013 annual average emissions reported to the U.S. EPA Greenhouse Gas Reporting Program (GHGRP). For the eight sources, CH4 emission measurements from the aircraft-based mass balance approach were a factor of 3.2-5.8 greater than the GHGRP-based estimates. Summed emissions totaled 7022 ± 2000 kg hr(-1), roughly 9% of the entire basin-wide CH4 emissions estimated from regional mass balance flights during the campaign. Emission measurements from five natural gas management facilities were 1.2-4.6 times larger than emissions based on the national study. Results from this study were used to represent "super-emitters" in a newly formulated Barnett Shale Inventory, demonstrating the importance of targeted sampling of "super-emitters" that may be missed by random sampling of a subset of the total.

Aircraft-Based Estimate of Total Methane Emissions from the Barnett Shale Region.

We present estimates of regional methane (CH4) emissions from oil and natural gas operations in the Barnett Shale, Texas, using airborne atmospheric measurements. Using a mass balance approach on eight different flight days in March and October 2013, the total CH4 emissions for the region are estimated to be 76 ± 13 × 10(3) kg hr(-1) (equivalent to 0.66 ± 0.11 Tg CH4 yr(-1); 95% confidence interval (CI)). We estimate that 60 ± 11 × 10(3) kg CH4 hr(-1) (95% CI) are emitted by natural gas and oil operations, including production, processing, and distribution in the urban areas of Dallas and Fort Worth. This estimate agrees with the U.S. Environmental Protection Agency (EPA) estimate for nationwide CH4 emissions from the natural gas sector when scaled by natural gas production, but it is higher than emissions reported by the EDGAR inventory or by industry to EPA's Greenhouse Gas Reporting Program. This study is the first to show consistency between mass balance results on so many different days and in two different seasons, enabling better quantification of the related uncertainty. The Barnett is one of the largest production basins in the United States, with 8% of total U.S. natural gas production, and thus, our results represent a crucial step toward determining the greenhouse gas footprint of U.S. onshore natural gas production.

Constructing a Spatially Resolved Methane Emission Inventory for the Barnett Shale Region.

Methane emissions from the oil and gas industry (O&G) and other sources in the Barnett Shale region were estimated by constructing a spatially resolved emission inventory. Eighteen source categories were estimated using multiple data sets, including new empirical measurements at regional O&G sites and a national study of gathering and processing facilities. Spatially referenced activity data were compiled from federal and state databases and combined with O&G facility emission factors calculated using Monte Carlo simulations that account for high emission sites representing the very upper portion, or fat-tail, in the observed emissions distributions. Total methane emissions in the 25-county Barnett Shale region in October 2013 were estimated to be 72,300 (63,400-82,400) kg CH4 h(-1). O&G emissions were estimated to be 46,200 (40,000-54,100) kg CH4 h(-1) with 19% of emissions from fat-tail sites representing less than 2% of sites. Our estimate of O&G emissions in the Barnett Shale region was higher than alternative inventories based on the United States Environmental Protection Agency (EPA) Greenhouse Gas Inventory, EPA Greenhouse Gas Reporting Program, and Emissions Database for Global Atmospheric Research by factors of 1.5, 2.7, and 4.3, respectively. Gathering compressor stations, which accounted for 40% of O&G emissions in our inventory, had the largest difference from emission estimates based on EPA data sources. Our inventory's higher O&G emission estimate was due primarily to its more comprehensive activity factors and inclusion of emissions from fat-tail sites.

Airborne Ethane Observations in the Barnett Shale: Quantification of Ethane Flux and Attribution of Methane Emissions.

We present high time resolution airborne ethane (C2H6) and methane (CH4) measurements made in March and October 2013 as part of the Barnett Coordinated Campaign over the Barnett Shale formation in Texas. Ethane fluxes are quantified using a downwind flight strategy, a first demonstration of this approach for C2H6. Additionally, ethane-to-methane emissions ratios (C2H6:CH4) of point sources were observationally determined from simultaneous airborne C2H6 and CH4 measurements during a survey flight over the source region. Distinct C2H6:CH4 × 100% molar ratios of 0.0%, 1.8%, and 9.6%, indicative of microbial, low-C2H6 fossil, and high-C2H6 fossil sources, respectively, emerged in observations over the emissions source region of the Barnett Shale. Ethane-to-methane correlations were used in conjunction with C2H6 and CH4 fluxes to quantify the fraction of CH4 emissions derived from fossil and microbial sources. On the basis of two analyses, we find 71-85% of the observed methane emissions quantified in the Barnett Shale are derived from fossil sources. The average ethane flux observed from the studied region of the Barnett Shale was 6.6 ± 0.2 × 10(3) kg hr(-1) and consistent across six days in spring and fall of 2013.