In This Issue
Summer Issue of The Bridge on Energy, the Environment, and Climate Change
July 3, 2015 Volume 45 Issue 2

Fugitive Emissions and Air Quality Impacts of US Natural Gas Systems

Monday, July 6, 2015

Author: Adam R. Brandt and Gabrielle Pétron

Natural gas has many advantages as a fuel compared to coal and oil. It is abundant and can often be produced at low cost. It has significantly lower combustion emissions of numerous species including greenhouse gases, criteria air pollutants (e.g., carbon monoxide, ozone, sulfur dioxide), heavy metals, and acid-forming species (Moore et al. 2014). And with sufficient transmission and distribution infrastructure in the United States and other countries, it can be burned flexibly in sectors across the economy—power generation, industry, homes, and businesses.

In electricity generation the advantage of natural gas is clear. Natural gas turbines are pinnacles of engineering achievement: they consume fuel very efficiently and are capable of rapid adjustment in response to changes in power demand and supply.

Its advantages lead some to argue that natural gas could have long-term use in renewable-heavy power grids of the future. Recent experience in the United States is illustrative: the share of US electricity generated using gas rose from 18.8 percent in 2005 to 27.7 percent in 2013, mainly displacing coal (EIA 2015) and contributing to a 15 percent reduction in carbon dioxide (CO2) emissions from power generation (EPA 2015a).

However, some problems remain with the use of natural gas. First, its combustion releases large quantities of CO2 relative to zero-carbon electricity sources such as wind, solar, hydroelectric, and nuclear. Second, the production and processing of natural gas are not without air quality impacts. These impacts are associated with both the fuel consumption required along natural gas supply chain operations and the release of permitted or unintentional emissions of methane (the main constituent of natural gas) and other components of natural gas.

We briefly explain the mechanisms and risks of fugitive emissions, and then review recent assessments of such emissions at the national and local levels. Subsequent sections set out the implications of fugitive emissions for both local air quality and overall climate quality. We conclude with a summary of challenges in regulation and funding to protect air quality and maximize the potential benefits of natural gas as a reliable and abundant source of energy.

Fugitive Emissions: Causes and Risks

Natural gas can be lost from production, processing, and distribution systems through a variety of mechanisms. For a number of processes or pieces of equipment the operating conditions are designed to emit some natural gas; for example, some pneumatic controllers are powered using the pressure differential between high-pressure natural gas and the atmosphere, resulting in emissions upon each actuation of the controller (Allen et al. 2014a). In addition, numerous pieces of equipment have safety systems (e.g., pressure relief valves on tanks) that vent gas when out-of-specification pressure increases could pose danger to equipment and/or workers in the vicinity. Moreover, large quantities of natural gas can be released to the air from wells that unload liquids from the wellbore (Allen et al. 2014b) or from equipment that is “blown down” for maintenance operations. Last, natural gas can be lost from underdesigned and malfunctioning equipment (Brantley et al. 2014; IPCC 2000; Mitchell et al. 2015; Thoma et al. 2012).

Some loss of natural gas along the production and supply chain is likely unavoidable: perfection is not achievable in engineered systems, and most businesses face the reality of lost product. For example, packages are sometimes lost in complex delivery networks, and some fraction of electricity generated never makes it to consumers because of transmission line losses. In the natural gas system, product loss is a major concern because, even at relatively low loss rates, leaked natural gas poses climate and local air quality risks.

First, methane is a potent greenhouse gas. Assessed over a 100-year period, it is approximately 34 times more potent on a mass basis than carbon dioxide (IPCC 2013). With a global mean lifetime of about a decade, it has an even greater impact over shorter time periods—about 86 times more potent over 20 years (IPCC 2013). Factoring in the stoichiometry of combustion, each mole of methane not oxidized to CO2 thus results in about 12 times the climate impact over 100 years—or 31 times over two decades.

Second, natural gas contains a variety of nonmethane species that can affect local air quality (Moore et al. 2014). Venting and fugitive emissions of natural gas result in the emission of volatile organic compounds (VOCs) present in the gas (some of them added; methanol, for example, is used as an antifreeze to protect pipelines) and can contribute to local surface ozone formation or smog (Edwards et al. 2014; Field et al. 2015; Gilman et al. 2013; Schnell et al. 2009). These and other hazardous compounds emitted from such operations (Helmig et al. 2014; Pétron et al. 2014; Thompson et al. 2014) risk affecting workers and/or nearby residents (McKenzie et al. 2012). The relative importance of these impacts depends on the natural gas composition, which varies among oil- and natural–gas producing regions and along the natural gas supply chain, as discussed below.

Current Understanding of Fugitive Methane Emissions

The US natural gas system comprises about 1 million producing oil and gas wells,1 300,000 miles of large-diameter high-pressure transmission lines, millions of miles of medium- and low-pressure distribution lines, and many tens of millions of points of connection (e.g., homes, businesses, factories) to the natural gas grid (EIA 2007; EPA 2015a). A diagram of natural gas flows and losses in the US gas system is shown in figure 1.

Figure 1

Large portions of the US gas system are old. Some 3 million oil and gas wells have been abandoned since the start of the US oil and gas industry in the late 1850s, many of them in unknown locations and sealed with outdated or nonstandard techniques (Brandt et al. 2014). Some cities, such as Boston and Washington, DC, have a large network of century-old cast iron gas distribution infrastructure, which has more leaks than modern systems (Jackson et al. 2014; McKain et al. 2015; Phillips et al. 2013).

Estimating Fugitive Emissions at the National Level

Emissions from the natural gas system are generally estimated using two quite different scientific methods. Bottom-up methods involve intensive and usually short-term study of the emissions of a representative set of equipment and facility types, the results of which are scaled up to a regional or national estimate of emissions using activity factors that represent the prevalence of a given activity or number of pieces of a given type of equipment. To take a simplified example, dozens of compressors might be surveyed for emissions using on-site detection and quantification equipment (Mitchell et al. 2015; Subramanian et al. 2015), and the resulting information used to generate an average compressor emissions factor that is then multiplied by the number of compressors in the country (Allen et al. 2013; Kirchgessner et al. 1996).

Alternatively, emissions from a region, state, or country can be estimated using top-down methods. These use in situ atmospheric chemical measurements in conjunction with meteorological data to estimate the flux of emissions behind the observed atmospheric concentrations. The two methods are illustrated in figure 2.

Figure 2

In the United States, fugitive emissions from the natural gas system are tracked through a nationwide “inventory” of emissions produced yearly by the Environmental Protection Agency (EPA 2015a). This inventory is based largely on bottom-up and engineering emission estimation methods and tries to account for control technologies used to reduce emissions (EPA 2015a, pp. A-126–A-389). Recent EPA national GHG emission inventories suggest leakage of about 1.5 percent of the methane in natural gas before it reaches consumers, with the most important points of leakage being production, transmission, and storage (Brandt et al. 2014).

A recent comprehensive review of experimental evidence found that methane emissions are undercounted in official EPA inventories (Brandt et al. 2014). A majority of experiments that measure methane emissions show excess emissions relative to inventory estimates at all scales, from equipment surveys to atmospheric studies integrating aircraft and tower data, and across the contiguous United States. The studies at the largest spatial scale suggest that national-level inventories undercount methane emissions from all sources by a factor of 1.25–1.75, which amounts to 7 to 21 teragrams per year of excess methane.

It is unclear how much of the national-level excess methane is due to the natural gas industry, but a variety of studies at regional, facility, and device scales suggest that official methods for counting natural gas emissions are underestimating methane emissions (Brandt et al. 2014). There is some evidence of undercounting in other methane source sectors as well, such as livestock in the north-central United States (Miller et al. 2013).

One challenge is that input data used in methane inventories are out of date: a dearth of funding and attention for many years means that many data are derived from limited-scale studies done in the early 1990s (Kirchgessner et al. 1996). Thankfully, with increased interest in natural gas fugitive emission rates spurred by the recent boom in US shale gas production, a number of studies have recently been completed or are under way. The largest effort, led by the Environmental Defense Fund in cooperation with industry participants (EDF 2013), involves independent scientists studying methane emissions from a variety of industry sources. US federal agencies, including the National Oceanic and Atmospheric Administration (NOAA) (e.g., Karion et al. 2013; Peischl et al. 2015; Pétron et al. 2012, 2014) and the National Energy Technology Laboratory (Skone et al. 2014), are also conducting important studies.

Understanding Variability in Regional Measurements

Recent atmospheric measurements by NOAA scientists have shown that oil and gas emissions of VOCs contribute significantly to local ozone production (Gilman et al. 2013) and are underestimated in state inventories (Pétron et al. 2014).

The recent NOAA studies have found substantial complexity in normalized natural gas emissions relative to production at the basin scale. For example, the Uintah basin in Utah and the Denver-Julesburg basin in Colorado show emission levels relative to production of 6.1–11.7 percent and 2.6–5.6 percent, respectively (Karion et al. 2013; Pétron et al. 2012, 2014). These are significantly larger than the EPA national average of 1.5 percent. In contrast, other producing regions, such as the Haynesville shale of Louisiana and Texas and the Marcellus shale in northeastern Pennsylvania, show emissions closer to the EPA estimates (Peischl et al. 2015). And atmospheric studies by other groups have found excess emissions in producing regions in California (Jeong et al. 2013, 2014) and in gas-consuming urban regions such as Los Angeles (Peischl et al. 2013; Wennberg et al. 2012) and Boston (McKain et al. 2015).

Differences in findings may also result from the method used to gather and/or analyze data. For recent top-down studies being performed by NOAA and affiliated groups, an instrumented airplane is flown on two transects perpendicular to the dominant wind direction, one upwind and the other downwind of the natural gas–producing region (figure 3). If meteorological conditions are favorable, a mass-balance approach can be used to differentiate quantities of methane exiting and entering the study region and estimate total methane emissions in the region. However, these studies typically have uncertainties of +/−30 percent, due mainly to variability and uncertainty in meteorological data such as horizontal wind speed and direction and boundary layer height, and may attribute methane emissions to different source categories.

Figure 3

Causes of confirmed different normalized emission rates among regions are generally difficult to discern. Possible drivers include the type of gas produced (dry versus wet), the type of operation (e.g., gas and liquid separation), and maintenance requirements (Zavala-Araiza et al. 2015). The Four Corners region2 of the United States, for example, has the largest emissions of methane from liquid unloading associated with coal bed methane production (Allen et al. 2014b; Pacsi and Harrison 2015), which may partly explain why a European satellite identified the region as a methane hotspot on a 7-year average (Kort et al. 2014). In addition, the age of the infrastructure, maturity of the play, and regulations for emission controls and for leak detection and repair (LDAR) programs can factor into emission magnitudes and intensity.

There are also challenges in reconciling results from top-down and bottom-up methods. First, it is not clear how comparable a limited-duration sampling effort (involving one to ten aircraft flights, one midday flight daily) is to a yearly estimate of emissions generated by an inventory method. A variety of episodic emissions may or may not occur at a representative rate during the specific, limited times of the flights. Second, it is not clear that inventory methods based on bottom-up studies of devices are of sufficient sample size to detect and record the variety of rare but consequential emission events that can drive overall emissions from a source population.

Implications for Local Air Quality

The first major development of tight and shale gas (between 2005 and 2012) happened before federal regulations were updated to limit emissions of VOCs (and indirectly methane) from thousands of new small and distributed sources. Rapid oil and gas development in several states (Colorado, Pennsylvania, Texas, Utah, Wyoming) has occurred in rural or remote locations where little or no air quality monitoring was in place to document any changes in ambient levels of air pollutants.

Local ozone pollution in adjacent populated areas or in national parks or monuments has been one of the first triggers for some states to enact stronger emission regulations for oil and gas operations. For example, the northern Colorado Front Range, including the western portion of Rocky Mountain National Park, became a nonattainment area for surface ozone in 2007. The region is home to nearly 2 million people and over 20,000 oil- and natural gas–producing wells. To mitigate VOC emissions from both vehicles and oil and gas operations, the state of Colorado has some of the most stringent regulations in the country (CDPHE 2015).

As new, stricter oil and gas regulations (passed in spring 2014) are implemented, it will be crucial to independently assess the impacts of regulation on emission mitigation/reduction. Recently, the EPA, Department of Justice, and state of Colorado agreed on a settlement with Houston-based Noble Energy, Inc., resolving alleged Clean Air Act violations stemming from the operator’s failure “to adequately design, size, operate and maintain vapor control systems on its controlled condensate storage tanks, resulting in emissions of volatile organic compound” (EPA 2015c). Regulation for emission reduction therefore needs to be done hand in hand with adequate technology design, field testing, installation, monitoring, and maintenance.

Another example comes from other Rocky Mountain regions. In the early months of both 2005 and 2006, surface ozone monitors in the Green River Basin of Wyoming showed levels above the EPA 2008 8-hour average air quality standard of 75 parts per billion by volume (ppbv).3 Later, a team of NOAA scientists further documented rapid photochemical production of ozone during cold shallow surface temperature inversions in the basin (Schnell et al. 2009). Wintertime ozone pollution events were similarly reported in 2009–2010 (and in subsequent years) in the Uintah Basin in northeastern Utah, which was also experiencing a large boom in oil and gas operations (Oltmans et al. 2014). Both basins are surrounded by mountains, so local emissions of ozone precursors, mainly driven by emissions from oil and gas operations, get trapped in a very shallow boundary layer during temperature inversions. With snow-covered ground, the sum of incoming and reflected sunlight in this shallow layer during the daytime feeds into the series of catalytic reactions that lead to rapid ground-level ozone formation.

If ozone pollution mitigation remains a major driver for federal and state-level regulation of oil and gas sources, more work is needed to better understand sources, emissions, and short- and long-term ambient levels of hazardous air pollutants, which can affect the health of both workers and nearby residential communities. Esswein and colleagues (2012) documented workers’ exposure to respirable crystalline silica during hydraulic fracturing operations. Field and colleagues (2015) showed that a treatment and recycling facility for produced and flowback water from fracking operations was responsible for enhanced levels of air toxics (toluene and xylenes) in the Pinedale Anticline gas field of Wyoming. And analysis of aircraft data showed that benzene emissions from oil and gas operations in the Denver-Julesburg Basin appear to be much larger than anticipated by the state inventory calculation (Pétron et al. 2014) and warrant a thorough investigation of important hazardous air pollutant source vectors and exposures.

Implications for Climate Benefits of Natural Gas

A comparison of the impacts of substituting natural gas for coal or transportation fuels such as gasoline and diesel indicates the possible climate benefits of using natural gas. Updated results from this comparison, using the most recent IPCC global warming potentials and taking into account a recent upward revision in methane’s heat-trapping capacity (Myhre et al. 2013), suggest that methane leakage must be at or below 2.7 percent if natural gas substitution for coal-fired power is to have climate benefits over all timescales (Alvarez et al. 2012). For benefits over a century-long timescale, leakage could be as high as 6 percent.

Given these targets and the current understanding of excess leakage, the substitution of natural gas for coal may not be beneficial immediately but should have robust benefits over a 100-year assessment period (Brandt et al. 2014). But as a substitute for gasoline or diesel the breakeven leakage rates are much narrower, making climate benefits from such a switch unlikely over even century-long timescales.

Solving the Problem

Can the problem of fugitive methane emissions from the natural gas system be solved? Numerous studies point to cost-effective means to reduce methane emissions (e.g., Harvey et al. 2012; ICF International 2014). Some solutions involve replacing a device or component with an improved version (e.g., replacing high-bleed pneumatic devices with low-bleed models, or capturing gas from centrifugal compressor seal leaks). Other cost-effective options are management shifts; for example, the implementation of formal LDAR processes at compressor stations was found to be very cost effective (ICF International 2014).

Because reducing leakage increases the quantity of salable product, there are economic benefits to emission and leakage reduction in addition to the goals of safety, environmental compliance, and social license to operate. One key challenge is that losses tend to be dispersed across a great variety of equipment types, and often a small number of leaks (called superemitters) are responsible for a large fraction of the total emissions.

Federal and private funding is being brought to bear on the problem of the expense of methane leak detection. Efforts in this area would greatly lower the cost and increase the effectiveness of the currently labor-intensive, and for some sources limited, leak detection process (ARPA-E 2014; EDF 2015).

Federal regulations (adopted in 2012 and later amended) address emissions from thousands of new gas wells (including sources such as gas well completion flowback and tank emissions) and call for upgrades to low- or no-bleed pneumatic devices (EPA 2015b). Existing wells and small gathering compressors are under the purview of states and emission reduction regulations vary greatly from one state to the next. In the Rocky Mountain region, Colorado, Wyoming, and Utah have implemented the most stringent emission control and LDAR programs for counties that violate federal ozone standards. More uniform standards and generally adopted tracking methods would both help to ensure consistent data and inform effective measures across jurisdictions.

To track progress, it is critical that states with existing and/or growing oil and gas operations maintain adequate ambient air quality monitoring and field operation inspections to preserve air quality for local populations and/or protected areas. Adequate funding and staffing are essential to ensure local capacity to investigate and monitor air impacts of current and future oil and gas operations.


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 1 In 2013, 18 percent of US natural gas production originated from oil wells, according to data from the US Energy Information Administration, available at

2 The Four Corners are the southwestern corner of Colorado, northwestern corner of New Mexico, northeastern corner of Arizona, and southeastern corner of Utah.

3 The final rule for the 2008 ozone standard was published in the Federal Register 73(60):16436–16514, available at

About the Author:Adam R. Brandt is an assistant professor in the Department of Energy Resources Engineering at Stanford University. Gabrielle Pétron is an atmospheric scientist at both the Cooperative Institute for Research in Environmental Sciences, University of Colorado Boulder, and the Earth System Research Laboratory, National Oceanic and Atmospheric Administration (NOAA), in Boulder.