Significance: Dry deposition is a key sink of atmospheric particles, which impact human and ecosystem health, and the radiative balance of the planet. However, the deposition parameterizations used in climate and air-quality models are poorly constrained by observations. Dry deposition of submicron particles is the largest uncertainty in aerosol indirect radiative forcing. Our particle flux observations indicate that dry deposition velocities are an order of magnitude lower than models suggest. Our updated, observation-driven parameterizations should reduce uncertainty in modeled dry deposition. The scheme increases modeled accumulation mode aerosol number concentrations, and enhances the combined natural and anthropogenic aerosol indirect effect by −0.63 W m ⁻² , similar in magnitude to the total aerosol indirect forcing in the Intergovernmental Panel on Climate Change report.

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

The atmospheric lifetime of black carbon (BC) is controlled by wet and dry deposition, which are poorly constrained by observations. We show that the single‐particle soot photometer can measure surface‐atmosphere exchange fluxes of refractory BC (rBC) particle mass (m_rBC) and number (N_rBC) by eddy covariance. We report field measurements of rBC dry and wet deposition rates during summer 2017 at the Southern Great Plains site in Oklahoma. On average, dry deposition of rBC is 0.3 ± 0.2 mm/s. We estimate a wet deposition flux of 2,600 ng·m⁻²·hr⁻¹ over the 148.5 mm of rainfall observed. These data indicate a composite lifetime of 7–11 days.

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

Standardized controlled testing of emerging methane detection solutions is a critical step in demonstrating emissions mitigation equivalence between emerging solutions and existing regulatory-approved leak detection and repair methods, such as ground-based optical gas imaging (OGI) camera surveys, in the United States and Canada. In this study, 12 solutions─including four hand-held OGI cameras, hand-held NextGen solutions, and mobile solutions (automobile- and drone-based)─were evaluated using a single-blind controlled testing protocol at an outdoor facility designed to simulate emissions from a simplified onshore North American oil and gas production facility. Three solutions were retested 3 to 12 months after the initial assessment using the same protocol and facility to evaluate how performance changed over time. Results indicated that hand-held OGI cameras generally achieved better emission source localization accuracy as well as lower 90% probability of detection and false positive fraction compared to other solution categories. The false negative fractions of OGI cameras were comparable to those of hand-held NextGen solutions but generally lower than those of mobile solutions, which exhibited shorter survey durations relative to other categories of hand-held solutions. The performance of two of three solutions improved with repeat testing, highlighting the potential benefit of regular, comprehensive testing for the development of solutions. Overall, the study findings suggest that while several emerging survey solutions showed promising detection and localization capabilities, hand-held OGI cameras demonstrated higher efficacy in identifying and accurately localizing small emission sources.

Quantifying and controlling fugitive methane emissions from oil and gas facilities remains essential for addressing climate goals, but the costs associated with monitoring millions of production sites remain prohibitively expensive. Current thinking, supported by measurement and simple dispersion modelling, assumes single-digit parts-per-million instrumentation is required. To investigate instrument response, the inlets of three trace-methane (sub-ppm) analyzers were collocated on a facility designed to release gas of known composition at known flow rates between 0.4 and 5.2 kg CH₄ h⁻¹ from simulated oil and gas infrastructure. Methane mixing ratios were measured by each instrument at 1 Hertz resolution over nine hours. While mixing ratios reported by a cavity ring-down spectrometer (CRDS)-based instrument were on average 10.0 ppm (range 1.8 to 83 ppm), a mid-infrared laser absorption spectroscopy (MIRA)-based instrument reported short-lived mixing ratios far larger than expected (range 1.8 to 779 ppm) with a similar nine-hour average to the CRDS (10.1 ppm). We suggest the peaks detected by the MIRA are likely caused by a micrometeorological phenomenon, where vortex shedding has resulted in heterogeneous methane plumes which only the MIRA can observe. Further analysis suggests an instrument like the MIRA (an optical-cavity-based instrument with cavity size ≤10 cm³ measuring at ≥2 Hz with air flow rates in the order of ≤0.3 slpm at distances of ≤20 m from the source) but with a higher detection limit (25 ppm) could detect enough of the high-concentration events to generate representative 20 min-average methane mixing ratios. Even though development of a lower-cost, high-precision, high-accuracy instrument with a 25 ppm detection threshold remains a significant problem, this has implications for the use of instrumentation with higher detection thresholds, resulting in the reduction in cost to measure methane emissions and providing a mechanism for the widespread deployment of effective leak detection and repair programs for all oil and gas infrastructure.