In This Issue
Summer Issue of The Bridge on Shale Gas: Promises and Challenges
June 15, 2014 Volume 44 Issue 2

Air Pollution Issues Associated with Shale Gas Production

Sunday, June 15, 2014

Author: Gabrielle Pétron

Any opinions, findings, conclusions, or recommendations expressed in this article are those of the author and do not necessarily reflect the views of the US National Oceanic and Atmospheric Administration or the University of Colorado Boulder.

The impacts of natural gas extraction on air quality have not been accorded the level of attention that potential water contamination has received, but they are equally consequential to deliberations on shale gas production. The benefits to US (and eventually global) society of exploiting unconventional sources of natural gas have been well explored. But although natural gas burns cleaner than coal, the full climate impact of its use depends on accurate data on the emissions of air pollutants associated with gas extraction. Environmental impact assessments that are required before extensive development rely on models based on emission inventories to predict how the activity will affect regional air quality, and regulators in turn rely on such information both for overseeing current emissions and for predicting impacts of future energy development. Emission inventories are also used to support US commitments to provide emission estimates of greenhouse gases to the United Nations Framework Convention on Climate Change.

This article provides technical background, reviews trends in atmospheric pollutants, and describes air- and ground-based measurement methods to investigate emissions from oil and gas production operations and their impacts in the western United States. Continuing research to improve the reliability of emission estimation methods is essential to support effective air quality regulation and international emission reporting commitments. 

The US Natural Gas System: Scope, Contents, and Controls

The United States has more than 1 million oil and gas wells in operation and close to 500 processing plants, 1,400 compressor stations, and 400 underground storage facilities. There are approximately 20,000 miles of gathering pipelines, 300,000 miles of transmission pipelines, and 2 million miles of distribution pipelines.1 Major efforts are required to maintain, operate, and monitor such an extensive system—engineers know that even the best-engineered systems can leak. Natural gas can leak from both underground and aboveground sources (some of the migration pathways from wells and other underground origins are discussed by Bachu and Valencia in this issue). In this paper the focus is on natural gas leakage from surface operations and equipment.

Figure 1

Figure 1 is a pictogram of natural gas systems. Gas is extracted at well heads and then moved through a network of gathering lines to compressor stations. After compression, it goes to processing plants that remove contaminants and separate out the natural gas liquids, such as propane and butane. The gas is then sent through transmission lines to power plants, homes, and commercial facilities.

Air quality assessment requires knowledge of the kind of product being moved in different parts of the system in order to characterize the potential content of leaks. Raw natural gas may contain about 70 percent methane, but by the time it is processed and distributed its methane content will be 90 percent or more. And the mix of hydrocarbons in natural gas differs not only between dry gas and wet gas (gas coproduced with oil) but also among geographical basins and even within the same basin. In addition to methane, which is a potent greenhouse gas, natural gas can contain varying amounts of other saturated hydrocarbons (e.g., ethane, propane, butane) as well as hazardous air pollutants such as benzene, toluene, and hydrogen sulfide.

Regulation of the completion of hydraulically fractured natural gas wells currently falls under the separate jurisdictions of states, and consequently results in different operator practices and potentially significantly different levels of emissions. But as of January 2015 operators of fractured or refractured gas wells will have to use reduced emission completions and a completion combustion device to reduce volatile organic compound (VOC) emissions from gas well completion (in accordance with a 2012 EPA rule discussed below).

Figure 2

Figure 2 illustrates two different circumstances of well completion. Figure 2a shows a completed well in Utah in the winter of 2012 with an open-top tank and open pit pond to capture flowback fluids. Over a 3-week span some of the highest methane (>800 ppm) and benzene (>500 ppb) mixing ratios were recorded just downwind of the site on a public road. In comparison, a “green” (reduced emissions) well completion in Colorado (Figure 2b) in the spring of 2013 has equipment that allows an operator to separate and capture the gas from the flowback fluid at the well site close to the time when hydraulic fracturing is completed, often within a couple of days; no substantial methane enhancement was detected at that location.

Global Monitoring of the Atmosphere

Accurate long-term high-quality measurements of the composition of the atmosphere at various locations around the United States can support effective tracking of potentially harmful local and regional alterations. The resulting data can enhance understanding of emissions responsible for air pollution and climate change and how they may change over time. The availability of such data for the scientific community, the public, and decision makers is essential for them to analyze specific events and trends.

The Global Monitoring Division (GMD) of the US National Oceanic and Atmospheric Administration (NOAA) operates a global air sampling and measurement network that is the largest source of well-calibrated observations of the global remote atmosphere composition and how it has changed over the past four decades. GMD is the World Meteorological Organization (WMO) Central Calibration Laboratory, which maintains and distributes the WMO mole fraction calibration scale for several long-lived greenhouse gases, including carbon dioxide and methane. The central calibration scale ensures confidence that, from one sampling location and time to another and from one measurement laboratory to another, consistent well-calibrated datasets are described and compared—apples to apples, methane to methane.

Carbon dioxide is an important trace gas and the main driver behind anthropogenic climate forcing. Observations recorded since 1960 at the Mauna Loa Observatory in Hawaii demonstrate a steady climb of atmospheric CO2 from about 315 parts per million (ppm) to over 400 ppm in May 2013, a record-breaking figure that caught the attention of the media (Kunzig 2013). In April 2014, the observations at Mauna Loa showed a mean CO2 level of 401.3 ppm.

GMD has also measured stratospheric ozone at the South Pole for several decades to track the size of the stratospheric ozone hole. In the spring of 2012 the hole was the smallest in the past 20 years, a positive result that shows the global ban on ozone-depleting substances is starting to pay off. More recently, ozone pollution near the surface in oil- and gas-producing regions has been the focus of GMD collaborations with several western states.

Emission Inventories

To assess emissions from the large and complex natural gas industry, regulators break down these systems into emission source categories. Large point sources, such as processing plants and compressors, are usually regulated by the EPA. The large engines used in drilling rigs are regulated at the state level, but regulatory details vary from state to state. Smaller sources include equipment such as heaters, pneumatic devices, dehydrators, separators, and storage tanks for oil, liquid condensate, and produced water. So far, violation of national standards for surface ozone levels in states such as Colorado, Wyoming, and Texas has been the main driver to regulate some of these minor (but numerous) VOC point sources in several counties.

In 2012 EPA signed a rule providing New Source Performance Standards for VOC emissions from new pieces of equipment (e.g., pneumatic controllers, oil and condensate storage tanks) at oil and gas facilities and completion of hydraulically fractured (or refractured) gas wells.2 Expected to come into effect by early 2015, these national standards for new “small” distributed oil and gas sources address emissions from many potential emission sources and establish minimum requirements for air emission reductions.

Box 1

To track potential air impacts, an inventory of emission sources and activities from natural gas and/or oil production in a region is usually the first tool developed and used by regulators. Box 1 shows an example of the source categories covered by emission inventories for different producing basins in the Rocky Mountain region.3 Each item in the inventory is assigned an emission factor, the amount of emissions expected from that item over a designated time period, usually a year. Estimates of emissions at the county, state, or national level are derived by combining the inventory of source/activity counts with the appropriate emission factors. These estimates are usually on an annualized basis and include different species of greenhouse gases, VOCs (which can act as precursors of surface ozone), and hazardous air pollutants.

 How Accurate Are Emission Estimates?

Emission factor values are a weakness in the system. They are usually derived from a small set of direct measurements by consulting firms or collaborators with the EPA and may be based on data collected as long as 20 years ago. At this time, more than 80 different emission factors are used in the EPA’s national inventory for natural gas systems and more than 60 in its oil inventory.

The fact that there are two different EPA inventories—one for natural gas wells and one for oil wells—is a problem in itself. The inventories are each maintained by separate departments and personnel and operate independently with different source categories, emission factors, and schedules for updates and revisions. This arrangement fails to reflect the reality that natural gas and oil can flow from both types of wells.

Furthermore, although the EPA has published a national annual emission inventory since the mid-1990s, the original methods appear to have underestimated actual methane emissions from natural gas production. The agency has been updating some of its methods and information sources since 2011, resulting in higher emission estimates than in the inventory released in 2010, which relied mostly on emission factors from the early 1990s.

But reliance on the current system for estimating emissions is problematic: If the models used are inaccurate, regulatory policies and actions may not be effective. In fact, a very recent study, involving participants from a number of institutions, indicated that actual methane emissions from natural gas systems in the United States and Canada appear to be larger than the official estimates (Brandt et al. 2014). Even on a smaller scale, there can be serious discrepancies, as discussed below.

Atmospheric Studies

My NOAA/GMD colleagues and I have been conducting extensive research on surface ozone pollution and hydrocarbon emissions in several oil and natural gas basins in Colorado (since 2008), Wyoming (2008), Utah (2012, 2013), and Texas (2013). We use instrumented vans, tethered sondes, balloons, airplanes, and towers to make accurate downwind measurements of emission plumes.

Measurement-based Methane Emission Estimates

Figure 3a is a map showing the Denver-Julesburg Basin (about half an hour from Denver and Boulder), where there are more than 20,000 active oil and gas wells. Figure 3b contrasts levels of methane measured at the upstream edge of the oil and gas basin at the NOAA Boulder Atmospheric Observatory (BAO) (in blue) with those detected at the Platteville site (in red) near the middle of the oil and gas basin. Methane concentrations are clearly much higher in the middle of the field than in the upstream (BAO) location.

Figure 3a

The highest (peak) levels are always experienced on nights when there is very little dispersion in the atmosphere. Some peak levels of methane registered at 10 ppm, five times the background value, a level rarely seen that suggests the existence of persistent leaks of natural gas from operations nearby (the peaks have a d13CH4 isotopic signature typical of natural gas methane in this region, which is different from the isotopic signatures of methane emitted by landfills and cows).

Figure 3b and 3c

Figure 3c illustrates the strong correlation between the fugitive (or rogue) gases associated with methane in this same basin. Note the stronger correlation in the northeast direction from BAO (red circles), the sector with the large majority of the wells.

Data show that high methane levels are neither isolated nor few in a number of oil and gas fields. A GMD flight over the Uinta Basin in northeastern Utah in February 2012 revealed a “lake” of enhanced methane over the largely uncommingled but adjacent gas and oil fields, with the gas field showing higher levels (Karion et al. 2013). Here also levels of short-lived hydrocarbons, contributors to the chemical processes that lead to surface ozone production, were significantly correlated with methane levels. There are very few human settlements or cattle in the region; 97 percent of the methane emissions were attributed to oil and gas activities in Uintah County, Utah.

To derive independent emission estimates from measurements obtained from aircraft flights, the aircraft mass balance technique (Karion et al. 2013) is used. The method draws on variables such as air composition, wind speed and direction, and dispersion rates to estimate the fraction of produced gas that is lost to the atmosphere. The mass balance technique does not use assigned standard emission inventory values but is based entirely on measurements. As a result, it is possible to obtain numbers for the amount of methane leaked in the atmosphere compared to the amount of natural gas (and methane) produced in a particular basin.

Some regional inventories, such as those developed for oil and gas basins in several western states,3 have already reported emissions with actual leakage rates higher than the 0.8–0.9 percent estimated by the EPA for natural gas production and processing. Figures for hourly leakage rates in the Uinta and Denver-Julesburg basins based on one or two flights are higher still, nearly double those derived from basin-level inventories for VOC emissions (Karion et al. 2013; Pétron et al. 2012).

While the aircraft surveys are a good way to obtain estimates of the total emission rate from an entire basin, measurements on the ground provide a more detailed identification of specific emission sources. GMD used a specially equipped van to measure concentrations of various air pollutants in the Uinta Basin oil and gas fields in Utah; an example of the data obtained is shown in Figure 4a, and the van’s path is shown in Figure 4b. Concentrations near compressor sites were three to five times higher than the background methane level of 2 ppm.

Figure 4

More broadly, anomalously high methane levels were detected downwind of some surface operations in all the oil- and gas-producing regions investigated. In one location in the Barnett field in Texas, GMD gauges revealed methane well above background levels at 5 out of 22 wells, smaller deviations at 8 wells, and no deviation from background at 9 wells. The EPA inventory method assumes that each of these wells will have the same emission magnitudes, and will thus get the total emissions wrong and fail to identify specific problematic sources (high emitters).

Surface Ozone Pollution

Mixtures of volatile organic compounds and nitrogen oxides can react to produce surface ozone. Usually ozone surface pollution is an urban, summertime problem, but it can also occur in remote or peri-urban oil- and gas-producing regions in the winter or summer.

Because natural gas contains other hydrocarbon species in addition to methane, their presence in the atmosphere as rogue gases is highly correlated with methane emissions. When these rogue gases are released in an area of snow-covered ground, low wind, and strong temperature inversions, the result is a “perfect storm” in which the pollutants can react to form ozone. The phenomenon of wintertime surface ozone in remote regions was not anticipated, monitored, or modeled by regulators and scientists.

In Wyoming, Utah, and Colorado, VOC emissions from oil and gas operations contribute significantly to regional ozone pollution in the summer (Colorado) (Gilman et al. 2013) or winter (Wyoming, Utah). We studied (and first reported in 2008) wintertime ozone surface pollution in the Wyoming Green River basin (Schnell et al. 2009) and have investigated similar conditions in Utah’s Uinta Basin (Oltmans et al. 2014). For nearly 40 days in January–March 2013, surface ozone levels in this basin exceeded the national ambient air quality standards of 75 ppb (8-hour average). On 11 days the levels rose to 120–140 ppb—levels that are unhealthy for humans. An EPA webpage reports surface ozone pollution in counties in the Rocky Mountain region4; all of the ones in nonattainment are in gas- and oil-producing regions. 

It is clear that better quantification of actual emissions of methane and VOCs is needed, as well as improved understanding of how such emissions contribute to the formation of seasonal ozone in and near oil and gas fields (Oltmans et al. 2014).

Summary and Conclusions

Atmospheric measurements from vehicle and aircraft platforms are a reliable and quantitative method to detect leaks and estimate emissions from natural gas- and oil-producing regions. Yet the data available also point to the need for additional reliable gauges of methane, VOCs, and hazardous air pollutant emissions from various source types in these regions, both to evaluate and improve (if necessary) the accuracy of emission inventories and to quickly identify problematic high-emitting sources.

As various sectors of the economy strive to reduce their environmental and climate impacts, it is imperative to develop more accurate emission estimation methods. Such methods would increase the reliability of EPA and other inventories used by regulators to guide air quality management decisions, including new emission reduction requirements for specific sources.

Some research is still needed to explore the full potential of different atmospheric measurement techniques, to assess how they might effectively supplement existing leak detection and repair programs for different scales, and to provide an independent assessment of the effectiveness of new emission reduction regulations.

If natural gas is to provide a bridge to a greener future, emissions must be curbed. That can be achieved only with industry leaders, regulators, researchers, and engineers working together using reliable data.


Bachu S, Valencia RL. 2014. Well integrity and risk assessment. The Bridge 44(2):28–33.

Brandt AR, Heath GA, Kort EA, O’Sullivan F, Pétron G, Jordaan SM, Tans P, Wilcox J, Gopstein AM, Arent D, Wofsy S, Brown NJ, Bradley R, Stucky GD, Eardley D, Harriss R. 2014. Methane leaks from North American natural gas systems. Science 343:733–735.

Gilman JB, Lerner BM, Kuster WC, de Gouw JA. 2013. Source signature of volatile organic compounds from oil and natural gas operations in northeastern Colorado. Environmental Science and Technology 47(3):1297–1305.

Karion A, Sweeney C, Pétron G, Frost G, Hardesty RM, Kofler J, Miller BR, Newberger T, Wolter S, Banta R, Brewer A, Dlugokencky E, Lang P, Montzka SA, Schnell R, Tans P, Trainer M, Zamora R, Conley S. 2013. Methane emissions estimates from airborne measurements over a western United States natural gas field. Geophysical Research Letters 40:4393–4397.

Kunzig R. 2013. Climate milestone: Earth’s CO2 level passes 400 ppm. National Geographic News, May 9. Available at 130510-earth-co2-milestone-400-ppm/.

Oltmans S, Schnell R, Johnson B, Pétron G, Mefford T, Neely R III. 2014. Anatomy of wintertime ozone associated with oil and natural gas extraction activity in Wyoming and Utah. Elementa Science of the Anthropene 2, doi:10.12952/ journal.elementa.000024.

Pétron G, Frost G, Miller BR, Hirsch SA, Montzka A, Karion M, Trainer C, Sweeney AE, Andrews L, Miller J, Kofler A, Bar-Ilan EJ, Dlugokencky L, Patrick CT, Moore TB Jr, Ryerson C, Siso W, Kolodzey PM, Lang T, Conway P, Novelli K, Masarie B, Hall D, Guenther D, Kitzis J, Miller D, Welsh D, Wolfe W, Neff P. 2012. Hydrocarbon emissions characterization in the Colorado Front Range: A pilot study. Journal of Geophysical Research D, Atmospheres 117: D04304.

Schnell RC, Oltmans SJ, Neely RR, Endres MS, Molenar JV, White AB. 2009. Rapid photochemical production of ozone at high concentrations in a rural site during winter. Nature Geoscience 2:120–122.


1 These data are from the US Department of Energy’s Energy Information Agency ( ngpipeline/index.html and and the US Department of Transportation (

 2 The rule, signed on April 17, 2012, is available at pdf. The standards are available at

 3 Data from the Western Regional Air Partnership’s Regional Emissions Data and Analyses, available at http://wrapair2
.org/emissions.aspx. The categories are used by Air Quality Program Manager Tom Moore’s team at the Western Governors Association.

4Area Designations for 2008 Ground-level Ozone Standards: Region 8 Final Designations, April 2012. The six states in Region 8 are Colorado, Montana, North and South Dakota, Utah, and Wyoming. Available at htm.

About the Author:Gabrielle Pétron is an atmospheric scientist at the Global Monitoring Division, National Ocean-ic and Atmospheric Ad--ministration, and the Cooperative Institute for Research in Environmental Sciences, University of Colorado Boulder.