Ramón A. Alvarez

Reconciling divergent estimates of oil and gas methane emissions

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. 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%.

Toward a Functional Definition of Methane Super-Emitters: Application to Natural Gas Production Sites

Emissions from natural gas production sites are characterized by skewed distributions, where a small percentage of sites-commonly labeled super-emitters-account for a majority of emissions. A better characterization of super-emitters is needed to operationalize ways to identify them and reduce emissions. We designed a conceptual framework that functionally defines superemitting sites as those with the highest proportional loss rates (methane emitted relative to methane produced). Using this concept, we estimated total methane emissions from natural gas production sites in the Barnett Shale; functionally superemitting sites accounted for roughly three-fourths of total emissions. We discuss the potential to reduce emissions from these sites, under the assumption that sites with high proportional loss rates have excess emissions resulting from abnormal or otherwise avoidable operating conditions, such as malfunctioning equipment. Because the population of functionally superemitting sites is not expected to be static over time, continuous monitoring will likely be necessary to identify them and improve their operation. This work suggests that achieving and maintaining uniformly low emissions across the entire population of production sites will require mitigation steps at a large fraction of sites.

Aerial Surveys of Elevated Hydrocarbon Emissions from Oil and Gas Production Sites

Oil and gas (O&G) well pads with high hydrocarbon emission rates may disproportionally contribute to total methane and volatile organic compound (VOC) emissions from the production sector. In turn, these emissions may be missing from most bottom-up emission inventories. We performed helicopter-based infrared camera surveys of more than 8000 O&G well pads in seven U.S. basins to assess the prevalence and distribution of high-emitting hydrocarbon sources (detection threshold ∼ 1-3 g s(-1)). The proportion of sites with such high-emitting sources was 4% nationally but ranged from 1% in the Powder River (Wyoming) to 14% in the Bakken (North Dakota). Emissions were observed three times more frequently at sites in the oil-producing Bakken and oil-producing regions of mixed basins (p < 0.0001, χ(2) test). However, statistical models using basin and well pad characteristics explained 14% or less of the variance in observed emission patterns, indicating that stochastic processes dominate the occurrence of high emissions at individual sites. Over 90% of almost 500 detected sources were from tank vents and hatches. Although tank emissions may be partially attributable to flash gas, observed frequencies in most basins exceed those expected if emissions were effectively captured and controlled, demonstrating that tank emission control systems commonly underperform. Tanks represent a key mitigation opportunity for reducing methane and VOC emissions.

Using Multi-Scale Measurements to Improve Methane Emission Estimates from Oil and Gas Operations in the Barnett Shale Region, Texas.

A growing body of work using varying analytical approaches is yielding estimates of methane emissions from the natural gas supply chain. For shorthand, the resulting emission estimates can be broadly described as top-down or bottom-up. Top-down estimates are determined from measured atmospheric methane enhancements at regional or larger scales. Bottom-up estimates rely on emissions measurements made directly from components or at the site level. (We note that bottom-up emission estimates (e.g., refs 4 and 13) may rely on data obtained with emission quantification methods sometimes labeled as top-down (e.g., refs 6, 7, and 9−12).) Both approaches have strengths and weaknesses. Top-down estimates cannot easily distinguish emissions from specific source types, limiting the development of informed mitigation strategies. Bottom-up estimates are resource intensive, and may not provide sufficient statistical characterization of each source type to accurately estimate total emissions. Previously published large-scale top-down studies report higher methane emissions than estimated by bottom-up emission inventories. Recent reviews of this work suggest that differences may result from (i) incorrect attribution of emissions among methane sources (e.g., fossil vs biogenic sources); (ii) obsolete or incomplete emission inventories, possibly based on emission factors developed using small or unrepresentative samples (including potential bias introduced by sampling only at cooperating facilities) and poor infrastructure activity data (e.g., site or event counts); (iii) failure to account for emissions from uncommon but anomalously high emitting sources (sometimes called superemitters); and (iv) the impact of intermittent, short-duration events. This issue contains 10 articles reporting results from a coordinated, twoweek field campaign that examined methane emissions using a diversity of analytical approaches in an effort to address these issues. The Barnett Shale Coordinated Campaign focused on a region of north Texas that includes the Barnett Shale oil and gas fields and the metropolitan area around Dallas and Fort Worth (population ∼7 million). With about 30 000 active wells, the region produced ∼2 trillion cubic feet of natural gas in 2013, or 7% of total U.S. production. As summarized below and in Figure 1, measurements from the campaign, supplemented with two recent national data sets, were used to develop topdown and bottom-up estimates of oil and gas methane emissions in the Barnett Shale region.

Influence of methane emissions and vehicle efficiency on the climate implications of heavy-duty natural gas trucks.

While natural gas produces lower carbon dioxide emissions than diesel during combustion, if enough methane is emitted across the fuel cycle, then switching a heavy-duty truck fleet from diesel to natural gas can produce net climate damages (more radiative forcing) for decades. Using the Technology Warming Potential methodology, we assess the climate implications of a diesel to natural gas switch in heavy-duty trucks. We consider spark ignition (SI) and high-pressure direct injection (HPDI) natural gas engines and compressed and liquefied natural gas. Given uncertainty surrounding several key assumptions and the potential for technology to evolve, results are evaluated for a range of inputs for well-to-pump natural gas loss rates, vehicle efficiency, and pump-to-wheels (in-use) methane emissions. Using reference case assumptions reflecting currently available data, we find that converting heavy-duty truck fleets leads to damages to the climate for several decades: around 70-90 years for the SI cases, and 50 years for the more efficient HPDI. Our range of results indicates that these fuel switches have the potential to produce climate benefits on all time frames, but combinations of significant well-to-wheels methane emissions reductions and natural gas vehicle efficiency improvements would be required.

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 sites gas production to be emitted to the atmosphere and are the defining attribute of super-emitting sites.

Emissions from oil and gas operations in the United States and their air quality implications.

Department of Medicine, Division of Environmental and Occupational Medicine, University of California, Irvine, CA, USA; Shell Projects and Technology (US), Shell Global Solutions Inc., Houston, TX, USA; Bay Area Air Quality Management District, San Francisco, CA, USA; Environmental Defense Fund, Austin, TX, USA; Department of Mechanical Engineering, Colorado State University, Fort Collins, CO, USA; Department of Chemical Engineering, and Center for Energy and Environmental Resources, University of Texas at Austin, Austin, TX, USA

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

A leaky endeavor Considerable amounts of the greenhouse gas methane leak from the U.S. oil and natural gas supply chain. Alvarez et al. reassessed the magnitude of this leakage and found that in 2015, supply chain emissions were ∼60% higher than the U.S. Environmental Protection Agency inventory estimate. They suggest that this discrepancy exists because current inventory methods miss emissions that occur during abnormal operating conditions. These data, and the methodology used to obtain them, could improve and verify international inventories of greenhouse gases and provide a better understanding of mitigation efforts outlined by the Paris Agreement. Science, this issue p. 186 Methane leakage from the U.S. oil and natural gas supply chain is much greater than previously estimated. 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.

Reply to Caldeira and Myhrvold: Radiative forcing is a useful, accepted metric to compare climate influence of alternative energy choices

Caldeira and Myhrvold (1) argue that the temperature change metric proposed in their recent paper (2) would be more useful to policymakers than the cumulative radiative forcing metric used by Alvarez et al. (3). We believe both metrics are useful, although the simplicity, transparency, and relatively low uncertainty of the cumulative radiative forcing metric makes it particularly useful in policy formulation.