Methane Exhaust Measurements at Gathering Compressor Stations in the United States.

Unburned methane entrained in exhaust from natural gas-fired compressor engines ("combustion slip") can account for a substantial portion of station-level methane emissions. A novel in-stack, tracer gas method was coupled with Fourier transform infrared (FTIR) species measurements to quantify combustion slip from natural gas compressor engines at 67 gathering and boosting stations owned or managed by nine "study partner" operators in 11 U.S. states. The mean methane emission rate from 63 four-stroke, lean-burn (4SLB) compressor engines was 5.62 kg/h (95% CI = 5.15-6.17 kg/h) and ranged from 0.3 to 12.6 kg/h. The mean methane emission rate from 39 four-stroke, rich-burn (4SRB) compressor engines was 0.40 kg/h (95% CI = 0.37-0.42 kg/h) and ranged from 0.01 to 4.5 kg/h. Study results for 4SLB engines were lower than both the U.S. EPA compilation of air pollutant emission factors (AP-42) and Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHGI) by 8 and 9%, respectively. Study results for 4SRB engines were 43% of the AP-42 emission factor and 8% of the GHGI emission factor, the latter of which does not distinguish between engine types. Total annual combustion slip from the U.S. natural gas gathering and boosting sector was modeled using measured emission rates and compressor unit counts from the U.S. EPA Greenhouse Gas Reporting Program. Modeled results [328 Gg/y (95% CI = 235-436 Gg/y) of unburned methane] would account for 24% (95% CI = 17-31%) of the 1391 Gg of methane emissions for "Gathering and Boosting Stations", or 6% of the net emissions for "Natural Gas Systems" (5598 Gg) as reported in the 2020 U.S. EPA GHGI. Gathering and boosting combustion slip emissions reported in the 2020 GHGI (374 Gg) fall within the uncertainty of this model.

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.

Super-emitters in natural gas infrastructure are caused by abnormal process conditions.

Effectively mitigating methane emissions from the natural gas supply chain requires addressing the disproportionate influence of high-emitting sources. Here we use a Monte Carlo simulation to aggregate methane emissions from all components on natural gas production sites in the Barnett Shale production region (Texas). Our total emission estimates are two-thirds of those derived from independent site-based measurements. Although some high-emitting operations occur by design (condensate flashing and liquid unloadings), they occur more than an order of magnitude less frequently than required to explain the reported frequency at which high site-based emissions are observed. We conclude that the occurrence of abnormal process conditions (for example, malfunctions upstream of the point of emissions; equipment issues) cause additional emissions that explain the gap between component-based and site-based emissions. Such abnormal conditions can cause a substantial proportion of a site's gas production to be emitted to the atmosphere and are the defining attribute of super-emitting sites.

The Effects of Air Flow Rates, Secondary Air Inlet Geometry, Fuel Type, and Operating Mode on the Performance of Gasifier Cookstoves.

Development of biomass cookstoves that reduce emissions of CO and PM2.5 by more than 50% and 95%, respectively, compared to a three-stone fire has been promoted as part of efforts to reduce exposure to household air pollution (HAP) among people that cook with solid fuels. Gasifier cookstoves have attracted interest because some have been shown to emit less CO and PM2.5 than other designs. A laboratory test bed and new test procedure were used to investigate the influence of air flow rates, stove geometry, fuel type, and operating mode on gasifier cookstove performance. Power output, CO emissions, PM2.5 emissions, fuel consumption rates, producer gas composition, and fuel bed temperatures were measured. The test bed emitted <41 mg·MJd­1 PM2.5 and <8 g·MJd­1 CO when operating normally with certain prepared fuels, but order of magnitude increases in emission factors were observed for other fuels and during refueling. Changes in operating mode and fuel type also affected the composition of the producer gas entering the secondary combustion zone. Overall, the results suggest that the effects of fuel type and operator behavior on emissions need to be considered, in addition to cookstove design, as part of efforts to reduce exposure to HAP.

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%.

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.

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.

Methane Emissions from the Natural Gas Transmission and Storage System in the United States.

The recent growth in production and utilization of natural gas offers potential climate benefits, but those benefits depend on lifecycle emissions of methane, the primary component of natural gas and a potent greenhouse gas. This study estimates methane emissions from the transmission and storage (T&S) sector of the United States natural gas industry using new data collected during 2012, including 2,292 onsite measurements, additional emissions data from 677 facilities and activity data from 922 facilities. The largest emission sources were fugitive emissions from certain compressor-related equipment and "super-emitter" facilities. We estimate total methane emissions from the T&S sector at 1,503 [1,220 to 1,950] Gg/yr (95% confidence interval) compared to the 2012 Environmental Protection Agency's Greenhouse Gas Inventory (GHGI) estimate of 2,071 [1,680 to 2,690] Gg/yr. While the overlap in confidence intervals indicates that the difference is not statistically significant, this is the result of several significant, but offsetting, factors. Factors which reduce the study estimate include a lower estimated facility count, a shift away from engines toward lower-emitting turbine and electric compressor drivers, and reductions in the usage of gas-driven pneumatic devices. Factors that increase the study estimate relative to the GHGI include updated emission rates in certain emission categories and explicit treatment of skewed emissions at both component and facility levels. For T&S stations that are required to report to the EPA's Greenhouse Gas Reporting Program (GHGRP), this study estimates total emissions to be 260% [215% to 330%] of the reportable emissions for these stations, primarily due to the inclusion of emission sources that are not reported under the GHGRP rules, updated emission factors, and super-emitter emissions.

Measurements of methane emissions from natural gas gathering facilities and processing plants: measurement results.

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

An ultrasonically enhanced inclined settler for microalgae harvesting.

Microalgae have vast potential as a sustainable and scalable source of biofuels and bioproducts. However, algae dewatering is a critical challenge that must be addressed. Ultrasonic settling has already been exploited for concentrating various biological cells at relatively small batch volumes and/or low throughput. Typically, these designs are operated in batch or semicontinuous mode, wherein the flow is interrupted and the cells are subsequently harvested. These batch techniques are not well suited for scaleup to the throughput levels required for harvesting microalgae from the large-scale cultivation operations necessary for a viable algal biofuel industry. This article introduces a novel device for the acoustic harvesting of microalgae. The design is based on the coupling of the acoustophoretic force, acoustic transparent materials, and inclined settling. A filtration efficiency of 70 ± 5% and a concentration factor of 11.6 ± 2.2 were achieved at a flow rate of 25 mL·min(-1) and an energy consumption of 3.6 ± 0.9 kWh·m(-3) . The effects of the applied power, flow rate, inlet cell concentration, and inclination were explored. It was found that the filtration efficiency of the device is proportional to the power applied. However, the filtration efficiency experienced a plateau at 100 W L(-1) of power density applied. The filtration efficiency also increased with increasing inlet cell concentration and was inversely proportional to the flow rate. It was also found that the optimum settling angle for maximum concentration factor occurred at an angle of 50 ± 5°. At these optimum conditions, the device had higher filtration efficiency in comparison to other similar devices reported in the previous literature.

Oxidative stress and aromatic hydrocarbon response of human bronchial epithelial cells exposed to petro- or biodiesel exhaust treated with a diesel particulate filter.

The composition of diesel exhaust has changed over the past decade due to the increased use of alternative fuels, like biodiesel, and to new regulations on diesel engine emissions. Given the changing nature of diesel fuels and diesel exhaust emissions, a need exists to understand the human health implications of switching to "cleaner" diesel engines run with particulate filters and engines run on alternative fuels like biodiesel. We exposed well-differentiated normal human bronchial epithelial cells to fresh, complete exhaust from a diesel engine run (1) with and without a diesel particulate filter and (2) using either traditional petro- or alternative biodiesel. Despite the lowered emissions in filter-treated exhaust (a 91-96% reduction in mass), significant increases in transcripts associated with oxidative stress and polycyclic aromatic hydrocarbon response were observed in all exposure groups and were not significantly different between exposure groups. Our results suggest that biodiesel and filter-treated diesel exhaust elicits as great, or greater a cellular response as unfiltered, traditional petrodiesel exhaust in a representative model of the bronchial epithelium.

Quantitative measurement of direct nitrous oxide emissions from microalgae cultivation.

Although numerous lifecycle assessments (LCA) of microalgae-based biofuels have suggested net reductions of greenhouse gas emissions, limited experimental data exist on direct emissions from microalgae cultivation systems. For example, nitrous oxide (N(2)O) is a potent greenhouse gas that has been detected from microalgae cultivation. However, little quantitative experimental data exist on direct N(2)O emissions from microalgae cultivation, which has inhibited LCA performed to date. In this study, microalgae species Nannochloropsis salina was cultivated with diurnal light-dark cycling using a nitrate nitrogen source. Gaseous N(2)O emissions were quantitatively measured using Fourier transform infrared spectrometry. Under a nitrogen headspace (photobioreactor simulation), the reactors exhibited elevated N(2)O emissions during dark periods, and reduced N(2)O emissions during light periods. Under air headspace conditions (open pond simulation), N(2)O emissions were negligible during both light and dark periods. Results show that N(2)O production was induced by anoxic conditions when nitrate was present, suggesting that N(2)O was produced by denitrifying bacteria within the culture. The presence of denitrifying bacteria was verified through PCR-based detection of norB genes and antibiotic treatments, the latter of which substantially reduced N(2)O emissions. Application of these results to LCA and strategies for growth management to reduce N(2)O emissions are discussed.