Mercury is a toxic bioaccumulative pollutant, with the atmosphere being the primary pathway for global distribution. Although atmospheric mercury cycling has been extensively monitored and modeled across the Northern Hemisphere, there has long been a dearth of mercury data for the Southern Hemisphere. Recent efforts in Australia are helping to fill this gap, with new observational records that span environments ranging from cool temperate to warm tropical climates and near-source to background conditions. Here, we review recent research on atmospheric mercury in Australia, highlighting new observational constraints on atmospheric concentrations, emissions, and deposition and, where possible, comparing these to model estimates. We also provide our best estimate of the current Australian atmospheric mercury budget. Ambient mercury observations collected to date show unique features not captured at other observing sites across the Southern Hemisphere, including very low concentrations at inland sites and a monsoon season drawdown in the tropical north. Previously compiled estimates of Australian anthropogenic mercury emissions differ substantially due to both methodological differences (e.g., assumptions about mercury control technology in coal-fired power plants) and recent closures of major Australian mercury sources, and none are appropriate for modern-day Australia. For mercury emissions from biomass burning, new measurements from Australian smoke plumes show emission factors for both savanna and temperate forest fires are significantly lower than measured elsewhere in the world, and prior estimates based on non-Australian data are likely too high. Although significant uncertainties remain, our analysis suggests that emissions from terrestrial sources (both newly released and legacy) significantly exceed those from anthropogenic sources. However, recent bidirectional air-surface flux observations suggest this source is likely balanced by deposition and surface uptake at local scales. Throughout, we highlight lingering uncertainties and identify critical future research needs for understanding Australian atmospheric mercury and its role in Southern Hemisphere mercury cycling.

In 2014, a satellite-based map of regional anomalies of atmospheric methane (CH 4 ) column retrievals singled out the fossil fuel rich San Juan Basin (SJB) as the biggest CH 4 regional anomaly (“hot spot”) in the United States. Over a 3-week period in April 2015, we conducted ground and airborne atmospheric measurements to investigate daily wind regimes and CH 4 emissions in this region of SW Colorado and NW New Mexico. The SJB, similar to other topographical basins with local sources, experienced elevated surface air pollution under low wind and surface temperature inversion at night and early morning. Survey drives in the basin identified multiple CH 4 and ethane (C 2 H 6 ) sources with distinct C 2 H 6 -to-CH 4 emission plume ratios for coal bed methane (CBM), natural gas, oil, and coal production operations. Air samples influenced by gas seepage from the Fruitland coal formation outcrop in La Plata County, CO, had enhanced CH 4 , with no C 2-5 light alkane enhancements. In situ fast-response data from seven basin survey flights, all with westerly winds, were used to map and attribute the detected C 2 H 6 and CH 4 emission plumes. C 2 H 6 -to-CH 4 plume enhancement correlation slopes increased from north to south, reflecting the composition of the natural gas and/or CBM extracted in different parts of the basin. Nearly 75% of the total detected CH 4 and 85% of the total detected C 2 H 6 hot spot were located in New Mexico. Emissions from CBM and natural gas operations contributed 66% to 75% of the CH 4 hot spot. Emissions from oil operations in New Mexico contributed 5% to 6% of the CH 4 hot spot and 8% to 14% of the C 2 H 6 hot spot. Seepage from the Fruitland coal outcrop in Colorado contributed at most 8% of the total detected CH 4 , while gas venting from the San Juan underground coal mine contributed <2%.

Twelve next generation emission measurement (NGEM) technologies completed single-blind testing at the Methane Emissions Technology Evaluation Center in 2018. This is the first series of tests to evaluate a wide variety of NGEM solutions including handheld, mobile, and continuous monitoring methods using comparable, repeatable protocols. Results assess performance of detection, localization and quantification, albeit with limited statistical significance due to a low number of tests. Overall, a higher detection rate is observed for handheld and mobile solutions than for continuous monitoring solutions. Compared to when a single emission source is present, a decline in detection rate is observed across all methods when multiple, steady emission sources are present. Localization by handheld and mobile solutions is more accurate than continuous monitoring solutions. These results support the common perception that detections by continuous monitoring systems will need to be confirmed and pinpointed by a follow-up inspection. Finally, this and other controlled release experiments, have been performed across a limited range of environmental conditions. To develop robust probability of detection curves needed for demonstrating emission reduction potential of leak detection and repair programs, new protocols are needed to evaluate methods across a wide range of metrological conditions and emission scenarios in a cost-effective manner.

The Eagle Ford Shale in southern Texas remains one of the most productive oil and gas regions in the US. Like the Permian Basin and Bakken Shale, ubiquitous natural gas flaring serves as an uncertain source of trace gas emissions within the Eagle Ford. A lack of ambient air quality data, especially in the western shale, impedes a thorough understanding of trace gas emissions within the shale and the subsequent local/regional air quality impacts. Meteorological and trace gas instrumentation was deployed to Shape Ranch in southwestern Dimmit County, near the US/Mexico border, from April to November of 2015. Mixing ratios of CO, NO x , O 3 , and VOCs did not exceed ambient air quality standards and were generally lower than mixing ratios measured in US cities, with the exception of alkanes. A non-negative matrix factorization demonstrated the dominance of oil and gas-sector emission sources in local trace gas variability, with combustion processes and transport of continental air also present. An analysis of NO x /CO and NO x /CO 2 ratios during periods of O 3 titration, identified by the ambient NO x /O 3 ratio, suggested that combustion and biospheric sources contributed to emissions of NO x , CO, and CO 2 . In-plume NO x /CO 2 ratios indicated relatively low-temperature combustion sources, with median NO x /CO 2 ratios close to that expected for natural gas flaring (0.54 ppb/ppm), and much lower than emission ratios for internal combustion engines (>10 ppb/ppm). However, the NO x /CO 2 ratio within these plumes exhibited a large variability, spanning more than an order of magnitude. Future research should focus on improving flaring emission factors and flaring volume estimates such that their air quality impacts can be better understood.

We deployed a helicopter with an infrared optical gas imaging camera to detect hydrocarbon emissions from 3,428 oil and gas facilities (including 3,225 producing oil and gas well pads) in Utah’s Uinta Basin during winter and spring 2018. We also surveyed 419 of the same well pads from the ground. Winter conditions led to poor contrast between emission plumes and the ground, leading to a detection limit for the aerial survey that was between two and six times worse than a previous summertime survey. Because the ground survey was able to use the camera’s high-sensitivity mode, the rate of detected emission plumes was much higher in the ground survey (31% of all surveyed well pads) relative to the aerial survey (0.5%), but colder air temperatures appeared to impair plume detection in the ground survey as well. The aerial survey cost less per facility visited, but the ground survey cost less per emission plume detected. Well pads with detected emissions during the ground and aerial surveys had higher oil and gas production, were younger, were more likely to be oil well pads, and had more liquid storage tanks per pad relative to the entire surveyed population. The majority of observed emission plumes were from liquid storage tanks (75.9% of all observed plumes), including emissions from pressure relief valves and thief hatches on the tank or from piping that connects to the tank. Well pads with control devices to reduce emissions from tanks (combustors or vapor recovery units) were more likely to have detected emissions. This finding does not imply that the control devices themselves were not functioning properly. Instead, gas was escaping into the atmosphere before it reached control devices. Pads with control devices tended to be newer and have higher oil and gas production, which probably explains their higher rate of detected emissions.

This study presents a meteorologically-based methodology for quantifying basin-scale methane (CH 4 ) emissions in Utah’s Uintah Basin, which is home to over 9,000 active and producing oil and natural gas wells. Previous studies in oil and gas producing regions have often relied on intensive aircraft campaigns to estimate methane emissions. However, the high cost of airborne campaigns prevents their frequent undertaking, thus providing only daytime snapshots of emissions rather than more temporally-representative estimates over multiple days. Providing estimates of CH 4 emissions from oil and natural gas production regions across the United States is important to inform leakage rates and emission mitigation efforts in order to curb the potential impacts of these emissions on global climate change and local air quality assessments. Here we introduce the Basin-constrained Emissions Estimate (BEE) method, which utilizes the confining topography of a basin and known depth of a pollution layer during multi-day wintertime cold-air pool episodes to relate point observations of CH 4 to basin-scale CH 4 emission rates. This study utilizes ground-based CH 4 observations from three fixed sites to calculate daily increases in CH 4 , a laser ceilometer to estimate pollution layer depth, and a Lagrangian transport model to assess the spatial representativity of surface observations. BEE was applied to two cold-air pool episodes during the winter of 2015–2016 and yielded CH 4 emission estimates between 44.60 +/– 9.66 × 10 3 and 61.82 +/– 19.76 × 10 3 kg CH 4 hr –1 , which are similar to the estimates proposed by previous studies performed in the Uintah Basin. The techniques used in this study could potentially be utilized in other deep basins worldwide.

An intensive coordinated airborne and ground-based measurement study was conducted in the Fayetteville Shale in northwestern Arkansas during September and October 2015 to compare and explain potential discrepancies between top-down and bottom-up estimates of regional natural gas (NG) methane (CH 4 ) emissions. In situ mobile downwind measurements are used to document the ethane to methane enhancement ratios (ERs) in emission plumes from NG operations in the region. Enhancement ratios are low (<2% for 87% of NG sources sampled) in this dry gas-producing region and normally distributed around 1.3% in the western half of the study area. A few sampled landfills emitted CH 4 but no ethane (C 2 H 6 ). Sampling drives around large chicken farms, prevalent in the region, did not detect significant downwind CH 4 enhancements. In situ airborne measurements of C 2 H 6 and CH 4 from area-scale surveys over and downwind of the region documented the resulting ERs from a mix of CH 4 sources. Based on these measurements, we show that on average during the measurement windows 85–95% of total CH 4 emissions in the western half of the Fayetteville Shale originated from NG sources, which agrees well with bottom-up estimates from the same field study. Lower mixing ratios measured over the eastern half of the region did not support the ER analysis due to the low signal-to-noise on C 2 H 6 measurements.

The Groningen natural gas field in the Netherlands – one of Europe’s major gas fields – deploys a “production cluster” infrastructure with extraction, some processing and storage in a single facility. This region is also the site of intensive agriculture and cattle operations. We present results from a multi-scale measurement campaign of methane emissions, including ground and airborne-based estimates. Results are compared with inventory at both the facility and regional level. Investigation of production cluster emissions in the Groningen gas field shows that production volume alone is not a good indicator of whether, and how much, a site is emitting methane. Sites that are nominally shut down may still be emitting, and vice-versa. As a result, the inventory emission factors applied to these sites (i.e. weighted by production) do a poor job of reproducing individual site emissions. Additional facility-level case studies are presented, including a plume at 150 ± 50 kg CH 4 hr –1 with an unidentified off-shore emission source, a natural gas storage facility and landfills. Methane emissions in a study region covering 6000 km 2 and including the majority of the Groningen field are dominated by biogenic sources (e.g. agriculture, wetlands, cattle). Total methane emissions (8 ± 2 Mg hr –1 ) are lower than inventory predictions (14 Mg hr –1 ) but the proportion of fossil fuel sources is higher than indicated by the inventory. Apportionment of methane emissions between thermogenic and biogenic source types used ethane/methane ratios in aircraft flasks and ground-based source characterization. We find that emissions from the oil and gas sector account for 20% of regional methane, with 95% confidence limits of (0%, 51%). The experimental uncertainties bound the inventory apportionment of 1.9%, though the central estimate of 20% exceeds this result by nearly 10 times. This study’s uncertainties demonstrate the need for additional research focusing on emissions apportionment, inventory refinement and offshore platforms.

Unconventional oil and gas exploration in the US has become a significant new source of atmospheric hydrocarbons. Field measurements and monitoring have been initiated to determine integral effects from this geographically dispersed source in and downwind of shale areas, driven mostly by concerns related to photochemical ozone production. The Texas Commission on Environmental Quality (TCEQ) deployed its first air quality monitor near the Eagle Ford shale in south Texas in summer 2013, followed by a more centrally located monitor in winter 2014/15. Here, we report on the latter monitor’s 2015 data, showing at times extraordinarily high levels of saturated hydrocarbons, similar to earlier findings in this area. Using hydrocarbon ratios, we establish that the dominant sources at this site appear to be oil and gas exploration. A non-negative matrix factorization (NMF) analysis revealed six consistent source factors, of which two were associated with pre-existing local sources from car traffic and industry, three with regional oil and gas exploration, and one with diesel emissions. The dominant source factors were associated with evaporative and fugitive emissions, and with flaring and (diesel-powered) compressor engine emissions. The former is a major source of saturated hydrocarbons while the latter is a major source of NO x and unsaturated hydrocarbons, confirming earlier findings. Due to the rural nature of the site, road traffic is a minor NO x source in this area, and the NMF results support inventory estimates showing oil and gas exploration to be the dominant regional source of NO x emissions. The NMF based source apportionment results also suggests that benzene levels in this rural area in 2015, while comparable to levels in Houston now, were probably three to five times lower before the shale boom.

Fossil fuel use associated with scientific activities in the Taylor Valley, Antarctic has been examined to determine the fluxes of particulate organic and elemental carbon and nitrogen as well as NO x for the 2015–2016 austral summer field season. These carbon and nitrogen fluxes are compared to our previously published calculations for the 1997–1998 austral summer. In addition, we compile fossil fuel usage and resulting C and N fluxes from the major field camp in Taylor Valley, Lake Hoare Camp (LHC) from the late 1990’s through 2017. In general, the annual fluxes do vary from year to year, but there is no significant trend, at least during the primary summer field season. There is indication that increasing the length of scientific operations does increase the C and N inputs via fossil fuel burning. This works supports our original results demonstrating that over long periods of time the anthropogenic flux of N from local fossil fuel burning could become quantitatively important in the region. Although the particulate C fluxes remain very low, the recent finding of black carbon in the Taylor Valley landscape indicates more on-going monitoring of the source of this material is merited.

Current bottom up estimates of CO 2 emission fluxes are based on a mixture of direct and indirect flux estimates relying to varying degrees on regulatory or self-reported data. Hence, it is important to use additional, independent information to assess biases and lower the flux uncertainty. We explore the use of a self-organizing map (SOM) as a tool to use multi-species observations to partition fossil fuel CO 2 ( CO 2 ff ) emissions by economic source sector. We use the Indianapolis Flux experiment (INFLUX) multi-species observations to provide constraints on the types of relationships we can expect to see, and show from the observations and existing knowledge of likely sources for these species that relationships do exist but can be complex. An Observing System Simulation Experiment (OSSE) is then created to test, in a pseudodata framework, the abilities and limitations of using an SOM to accurately attribute atmospheric tracers to their source sector. These tests are conducted for a variety of emission scenarios, and make use of the corresponding high-resolution footprints for the pseudo-measurements. We show here that the attribution of sector-specific emissions to measured trace gases cannot be addressed by investigating the atmospheric trace gas measurements alone. We conclude that additional a priori information such as inventories of sector-specific trace gases are required to evaluate sector-level emissions using atmospheric methods, to overcome the challenge of the spatial overlap of nearly every predefined source sector. Our OSSE additionally allows us to demonstrate that increasing the (already high) data density cannot solve the co-localization problem.

This study presents the results of a campaign that estimated methane emissions at 268 gas production facilities in the Fayetteville shale gas play using onsite measurements (261 facilities) and two downwind methods – the dual tracer flux ratio method (Tracer Facility Estimate – TFE, 17 facilities) and the EPA Other Test Method 33a (OTM33A Facility Estimate – OFE, 50 facilities). A study onsite estimate (SOE) for each facility was developed by combining direct measurements and simulation of unmeasured emission sources, using operator activity data and emission data from literature. The SOE spans 0–403 kg/h and simulated methane emissions from liquid unloadings account for 88% of total emissions estimated by the SOE, with 76% (95% CI [51%–92%]) contributed by liquid unloading at two facilities. TFE and SOE show overlapping 95% CI between individual estimates at 15 of 16 (94%) facilities where the measurements were paired, while OFE and SOE show overlapping 95% CI between individual estimates at 28 of 43 (65%) facilities. However, variance-weighted least-squares (VWLS) regressions performed on sets of paired estimates indicate statistically significant differences between methods. The SOE represents a lower bound of emissions at facilities where onsite direct measurements of continuously emitting sources are the primary contributor to the SOE, a sub-selection of facilities which minimizes expected inter-method differences for intermittent pneumatic controllers and the impact of episodically-emitting unloadings. At 9 such facilities, VWLS indicates that TFE estimates systematically higher emissions than SOE (TFE-to-SOE ratio = 1.6, 95% CI [1.2 to 2.1]). At 20 such facilities, VWLS indicates that OFE estimates systematically lower emissions than SOE (OFE-to-SOE ratio of 0.41 [0.26 to 0.90]). Given that SOE at these facilities is a lower limit on emissions, these results indicate that OFE is likely a less accurate method than SOE or TFE for this type of facility.

Gathering pipelines, which transport gas from well pads to downstream processing, are a sector of the natural gas supply chain for which little measured methane emissions data are available. This study performed leak detection and measurement on 96 km of gathering pipeline and the associated 56 pigging facilities and 39 block valves. The study found one underground leak accounting for 83% (4.0 kg CH 4 /hr) of total measured emissions. Methane emissions for the 4684 km of gathering pipeline in the study area were estimated at 402 kg CH 4 /hr [95 to 1065 kg CH 4 /hr, 95% CI], or 1% [0.2% to 2.6%] of all methane emissions measured during a prior aircraft study of the same area. Emissions estimated by this study fall within the uncertainty range of emissions estimated using emission factors from EPA’s 2015 Greenhouse Inventory and study activity estimates. While EPA’s current inventory is based upon emission factors from distribution mains measured in the 1990s, this study indicates that using emission factors from more recent distribution studies could significantly underestimate emissions from gathering pipelines. To guide broader studies of pipeline emissions, we also estimate the fraction of the pipeline length within a basin that must be measured to constrain uncertainty of pipeline emissions estimates to within 1% of total basin emissions. The study provides both substantial insight into the mix of emission sources and guidance for future gathering pipeline studies, but since measurements were made in a single basin, the results are not sufficiently representative to provide methane emission factors at the regional or national level.