Publications

Coordinated dual-tracer, aircraft-based, and direct component-level measurements were made at midstream natural gas gathering and boosting stations in the Fayetteville shale (Arkansas, USA). On-site component-level measurements were combined with engineering estimates to generate comprehensive facility-level methane emission rate estimates (“study on-site estimates (SOE)”) comparable to tracer and aircraft measurements. Combustion slip (unburned fuel entrained in compressor engine exhaust), which was calculated based on 111 recent measurements of representative compressor engines, accounts for an estimated 75% of cumulative SOEs at gathering stations included in comparisons. Measured methane emissions from regenerator vents on glycol dehydrator units were substantially larger than predicted by modelling software; the contribution of dehydrator regenerator vents to the cumulative SOE would increase from 1% to 10% if based on direct measurements. Concurrent measurements at 14 normally-operating facilities show relative agreement between tracer and SOE, but indicate that tracer measurements estimate lower emissions (regression of tracer to SOE = 0.91 (95% CI = 0.83–0.99), R2 = 0.89). Tracer and SOE 95% confidence intervals overlap at 11/14 facilities. Contemporaneous measurements at six facilities suggest that aircraft measurements estimate higher emissions than SOE. Aircraft and study on-site estimate 95% confidence intervals overlap at 3/6 facilities. The average facility level emission rate (FLER) estimated by tracer measurements in this study is 17–73% higher than a prior national study by Marchese et al.

Abstract. Increased natural gas production in recent years has spurred intense interest in methane (CH4) emissions associated with its production, gathering, processing, transmission and distribution. Gathering and processing facilities (G&P facilities) are unique in that the wide range of gas sources (shale, coal-bed, tight gas, conventional, etc.) results in a wide range of gas compositions, which in turn requires an array of technologies to prepare the gas for pipeline transmission and distribution. We present an overview and detailed description of the measurement method and analysis approach used during a 20-week field campaign studying CH4 emissions from the natural gas G&P facilities between October 2013 and April 2014. Dual tracer flux measurements and onsite observations were used to address the magnitude and origins of CH4 emissions from these facilities. The use of a second tracer as an internal standard revealed plume-specific uncertainties in the measured emission rates of 20–47%, depending upon plume classification. Combining downwind methane, ethane (C2H6), carbon monoxide (CO), carbon dioxide (CO2), and tracer gas measurements with onsite tracer gas release allows for quantification of facility emissions, and in some cases a more detailed picture of source locations.

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 38-86% of the time. When non-zero site-level emission rate estimates were provided, no linear correlation between release rate and reported emission rate estimate was observed. The average, aggregated across all PSN solutions during releases, shows 5% of mixing ratio readings at downwind sensors were greater than the site's baseline plus two standard deviations. Four of six 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.

Quantitative optical gas imaging (QOGI) system can rapidly quantify leaks detected by optical gas imaging (OGI) cameras across the oil and gas supply chain. A comprehensive evaluation of the QOGI system's quantification capability is needed for the successful adoption of the technology. This study conducted single-blind experiments to examine the quantification performance of the FLIR QL320 QOGI system under near-field conditions at a pseudo-realistic, outdoor, controlled testing facility that mimics upstream and midstream natural gas operations. The study completed 357 individual measurements across 26 controlled releases and 71 camera positions for release rates between 0.1 kg Ch4/h and 2.9 kg Ch4/h of compressed natural gas (which accounts for more than 90% of typical component-level leaks in several production facilities). The majority (75%) of measurements were within a quantification factor of 3 (quantification error of -67% to 200%) with individual errors between -90% and 831%, which reduced to -79% to +297% when the mean of estimates of the same controlled release from multiple camera positions was considered. Performance improved with increasing release rate, using clear sky as plume background, and at wind speeds ≤1 mph relative to other measurement conditions.

Recent regulatory spotlight on continuous emissions monitoring (CEM) and the rapid development of CEM solutions has demanded the characterization of solutions performance through regular, rigorous testing using consensus test protocols. This study is the second known implementation of such protocol involving single-blind controlled testing of 10 CEM solutions. Controlled releases of rates (6 to 7100) g CH4/h over durations (0.4 to 10.2) hours under wind speed range of (0.7 to 9.9) m/s were conducted for 11 weeks. Results showed that 4 solutions achieved minimum detection limits (MDLs) within tested emission rate range with all 4 solutions having both the lowest MDLs (3.7 [3.0, 5.2] kg CH4/h to 6.1 [3.7, 17.1] kg 11 CH4/h) and FP rates (9.2% to 15.4%) indicating efforts at balancing low sensitivity with low FP rate. Quantification results showed wide individual estimate uncertainties with emissions underestimation and overestimation by factors up to > 15 and 97 respectively. Three solutions had > 80% of their estimates within a factor of 3 of actual rates for controlled release in the ranges of (0.1 – 1] kg CH4/h and >1 kg CH4/h respectively. Relative to the study by Bell et al., current solutions performance, as a group, generally improved majorly due to solutions from the study by Bell et al. that retested. This result highlights the importance of regular, quality testing to the advancement of CEM solutions for effective emissions mitigation.

Recent regulatory spotlight on continuous monitoring (CM) solutions and the rapid development of CM solutions has demanded the characterization of solutions performance through regular, rigorous testing using consensus test protocols. This study is the second known implementation of such protocol involving single-blind controlled testing of 9 CM solutions. Controlled releases of rates (6 to 7100) g CH4/h over durations (0.4 to 10.2) hours under wind speed range of (0.7 to 9.9) m/s were conducted for 11 weeks. Results showed that 4 solutions achieved method detection limits (DL90s) within 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% to 13.2%) indicating efforts at balancing low sensitivity with low false positive rate. 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 retested. This result highlights the importance of regular, quality testing to the advancement of CM solutions for effective emissions mitigation.

Abstract. Other Test Method 33A (OTM 33A) is a near-source flux measurement method developed by the Environmental Protection Agency (EPA) primarily used to locate and estimate emission fluxes of methane from oil and gas (O&G) production facilities without requiring site access. A recent nation-wide estimate of methane emissions from O&G production included a large number of flux measurements of upstream O&G facilities made using OTM 33A and concluded the EPA National Emission Inventory underestimates this sector by a factor of ~ 2.1 (Alvarez et al., 2018). The study presented here investigates the accuracy of OTM 33A through a series of test releases performed at the Methane Emissions Technology Evaluation Center (METEC), a facility designed to allow quantified amounts of natural gas to be released from decommissioned O&G equipment to simulate emissions from real facilities (Fig. 1). This study includes test releases from single and multiple points, from equipment locations at different heights, and spanned methane release rates ranging from 0.16 to 2.15 kg h-1. Approximately 95 % of individual measurements (N = 45) fell within ±70 % of the known release rate. A simple linear regression of OTM 33A versus known release rates at the METEC site gives an average slope of 0.96 with 95 % CI (0.66,1.28), suggesting that an ensemble of OTM 33A measurements may have a small but statistically insignificant low bias.

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., and 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 to integrate local measurements, estimated significantly lower emissions than the TD estimates for 40 of 43 paired comparisons. Significant disagreement is observed at most facilities, both between the two TD methods and between the TD estimates and operator inventory. These findings have two implications. Firstly, improving inventory estimates will require additional on-site or ground-based diagnostic screening and measurement of all sources. Secondly, the TD full-facility measurement methods need to undergo further testing, characterization, and potential improvement specifically tailored for complex midstream facilities.

Significance Past studies reporting divergent estimates of methane emissions from the natural gas supply chain have generated conflicting claims about the full greenhouse gas footprint of natural gas. Top-down estimates based on large-scale atmospheric sampling often exceed bottom-up estimates based on source-based emission inventories. In this work, we reconcile top-down and bottom-up methane emissions estimates in one of the country’s major natural gas production basins using easily replicable measurement and data integration techniques. These convergent emissions estimates provide greater confidence that we can accurately characterize the sources of emissions, including the large impact that a small proportion of high-emitters have on total emissions and determine the implications for mitigation.

In comparing observation based methane emission estimates for oil and gas well sites to routine emissions reported in inventories, the time scale of the measurement should match the time scale over which the inventoried emissions are estimated. Since many measurements are of relatively short duration (seconds to hours), a tool is needed to estimate emissions over these time scales rather than the annual totals reported in most emission inventories. This work presents a tool for estimating routine emissions from oil and gas well sites at multiple time scales; emissions at well sites vary over time due to changes in oil and gas production rates, operating practices and operational modes at the sites. Distributions of routine emissions (expected and inventoried) from well sites are generally skewed, and the nature and degree to which the distributions are skewed depends on the time scales over which emissions are aggregated. Abnormal emissions can create additional skew in these distributions. At very short time scales (emissions aggregated over 1 min) case study distributions presented in this work are both skewed and bimodal, with the modes depending on whether liquid storage tanks are flashing at the time of the measurement and whether abnormal emissions are occurring. At longer time scales (emissions aggregated over 1 day) distributions of routine emissions simulated in this work can have multiple modes if short duration, high emission rate events, such as liquid unloadings or large abnormal emissions, occur at the site. Multiple applications of the methane emission estimation tool (MEET), developed in this work, are presented. These results emphasize the importance of developing detailed emission inventories, which incorporate operational data, when comparing measurements to routine emissions. The model described in this work supports such comparisons and is freely available.