Types of Air Pollutants Associated with Hydraulic Fracturing

Natural gas development and production emits criteria pollutants as defined by the Clean Air Act (EPA, 2012). Nitrogen oxides (NO_x) and volatile organic compounds (VOCs) are associated with oil and gas development; in the presence of sunlight, these may react to form ozone and contribute to regional air problems. Regional chemical transport modeling has predicted that ozone may be of particular concern. Nitrogen dioxide and particulate matter (PM_2.5) emissions are also worrisome, but may be more of a local than a regional issue.

Hazardous air pollutants or air toxics are another category of pollutant that is emitted with shale gas development and production. Many operations necessary for oil and gas development use diesel-powered engines, which emit diesel particulate matter. Furthermore, natural gasfired engines can be significant sources of formaldehyde, which is also a secondary pollutant. Aromatics (e.g., benzene and toluene) and other VOCs can be released during shale gas production.

Fugitive emissions released during shale gas extraction are also composed of greenhouse gases such as methane. Black carbon from diesel fuel combustion impacts climate. How the benefits of natural gas shift when emissions that directly impact climate change are factored in is an issue to be examined.

Dr. Robinson discussed Figure 5-1, which lists the sources of emissions described above, categorizes them as major or minor sources of pollution, describes the pollutants they emit, and assesses the quality of data. (The values should be considered the “potential to emit” because particulate filters and other technologies, if implemented effectively, can reduce the contributions of these sources.) He noted that there is reasonable understanding of the emissions from diesel-powered engines (e.g., drill rigs, fracturing pumps, and truck traffic). There is less knowledge about emissions from other sources, for example, completion venting, blowdown venting, and fracturing ponds. There may be an increase in knowledge as the field moves to more controlled “green completions” that significantly reduce fugitive emissions of methane and other gases. During the gas production phase, sources such as compressor stations, heaters and dehydrators, condensate tanks, fugitive emissions, and pneumatics emit air pollutants. Some sources have well-defined emission points, and others do not; for most, more data are needed to accurately assess their impacts. Dr. Robinson noted that the main concern is what the net effect is when these pollutants mix in the atmosphere.

FIGURE 5-1

Sources of emissions. NOTE: NO_x = nitrogen oxide, PM = particulate matter, VOC = volatile organic compound. SOURCE: Robinson, 2012.

Spatial Scale of Air Pollution

Dr. Robinson commented on the need to consider the spatial scale of air pollution. The air acts as an integrating medium—the emissions from many sources mix to impact air quality and produce exposures. There is much interest in local exposure because there are usually homes near gas wells, and emissions from drilling activities that have the potential to affect local residents. But, from an air quality perspective, he stressed, it is imperative to also think at the level of field exposure. As well pads become concentrated in a small area, the emissions from the individual activities of each are integrated and can alter air quality. Finally, the regional scale needs to be considered. Individual wells may cover a large spatial distribution, and as their numbers increase, they can have a regional impact. This means that NO_x and ozone may not only affect local homes, but may also impact cities that are farther away. For example, Marcellus Shale activities have the potential to affect ozone concentrations in Philadelphia. One way of thinking about regional impacts, Dr. Robinson suggested, is as a massive refinery distributed hundreds or thousands of square miles. From a regional perspective, it is very challenging to fully comprehend the impacts on air quality due to shale gas development.

Another point to consider is where air quality monitoring currently occurs. There is a large network of state and local air monitoring stations that are deployed by state and local agencies to monitor air quality. Selection of sites for stations is population-based, with many stations being located in the Northeast corridor; there is reasonable justification for sitting stations in this fashion. However, there are not many sites in more rural, less populated areas, where much of the gas development is occurring. A monitoring strategy to understand the air quality impacts of shale gas developments in less populated areas, such as in the Marcellus Shale region, is needed. It is possible to make measurements for shortterm studies by setting up temporary monitoring stations downwind of well sites. This will indicate very coarsely what the air quality impacts might be. But these types of assessments are sensitive to meteorological and other factors, making it difficult to quantify the true air quality impacts. Furthermore, because of the dearth of permanent monitoring stations in rural areas, there is limited background baseline data, so it is impossible to track the changes in air quality over time. In addition, there is pressure to reduce monitoring stations—not to establish new ones—and this will not aid in ameliorating the spotty nature of the data concerning the impacts of rural shale gas production on air quality.

Predicting Future Trends in Emissions

Dr. Robinson underscored the need to better predict the impact of emissions associated with shale gas production. Carnegie Mellon is developing an emission inventory for chemical transport modeling to predict the regional impacts of Marcellus Shale activities on air quality. The emission inventory covers the states of New York, Pennsylvania, and West Virginia, but the modeling of impacts considers the entire Eastern United States.

In the Marcellus region, new natural gas development has rapidly expanded. There were no Marcellus wells in the mid-2000s. Currently, approximately 1,000 wells are being drilled per year. The future projections are imprecise, but substantial development will certainly continue into the future—perhaps 3,000 wells drilled per year by 2020 (Considine et al., 2010). The associated activities (e.g., drill rigs, hydraulic fracturing pumps) are going to be contributing significant emissions to the area for the foreseeable future. The exact amount depends strongly on the price of natural gas.

Emissions from compressor stations and processing facilities are tied to the amount of gas produced (not necessarily the number of wells drilled). There is a range of estimates of future gas production, which is also expected to increase. By 2020, there could be 15 billion cubic feet per day (bcfd) produced, where currently there is less than 5 bcfd (Considine et al., 2010; U.S. Energy Information Administration, 2013). These activity predictions are important because they factor into the analysis of future emissions.

Dr. Robinson stated that there is also uncertainty in the underlying emissions data. For the diesel-powered sources, there is literature on emissions data and on duty cycles. These data can be used to build reasonably robust estimates. For process-level data or activities such as pneumatics, there is more uncertainty. To estimate these emissions, there are a number of parameters to use. There is the emission factor (which is the rate of production of the pollutant), operations characteristics (such as power), the size of the source, and the amount of time the source is functioning. These values can vary from basin to basin and operator to operator, so they carry some degree of uncertainty, but, despite that challenge, it is possible to account explicitly for that uncertainty in the estimation of emissions.

In a Monte Carlo simulation, probability distributions for factors that have a high degree of uncertainty are used to calculate a range of possible emission levels. For example, ranges of emission factors for drill rigs, hydraulic fracturing pumps, and other sources can be obtained from the literature. There is also increasing amounts of data on how devices are operated in the field. These distributions have a level of uncertainty that can be incorporated into the analysis. Dr. Robinson noted that this type of analysis explicitly acknowledges uncertainty and accounts for it formally, instead of hiding behind it and using it as an excuse for inaction.

These analyses have revealed that aggregate emissions are important. The amount of NO_x emissions due to Marcellus Shale is estimated to be substantial: in 2009, 58 tons per day of NO_x were emitted, and by 2020, this is expected to increase to 129 tons per day. Currently Marcellus sources are responsible for a few percent of the regional NO_x emissions, but, by 2020, this is expected to increase to 12 percent (Roy et al., 2013). Existing regulations are expected to reduce NO_x emissions from power plants and diesel engines. However, as the activities associated with development and production grow; the associated emissions may undermine the gains from regulations and have impacts in the region.

It is possible to do an analogous calculation for VOC emissions. A similar trend is observed—the tonnage of emissions is significant and will increase over time. For VOCs, local effects must be examined as well because the type of gas—wet or dry—varies with location. Wet gas has a higher fraction of condensates and its production releases more VOCs. In the Marcellus region, wet gas is found in West Virginia and southwestern Pennsylvania. The properties of the gas alter its emissions and thus affect the exposure of the surrounding community to air toxics (The Nature Conservancy, 2010).

The analysis also shows that diesel particulate matter and other air toxics may be important components of air pollutants, which again, is predicted to increase. In 2009, approximately 2 tons per day of diesel particulate matter were released, and this is predicted to double by 2020 (Kemball-Cook et al., 2010). Emissions from on-road diesel activity are expected to decrease because diesel particulate filters are now required (EPA, 2006). Combining this regulation with the new, sizeable activity from gas development means that the fraction of emissions due to Marcellus activities is expected to increase.

Regarding ozone, model simulations for the Haynesville Shale in Louisiana and Texas have shown a perturbations as large as 10 parts-perbillion (ppb) in the maximum-daily 8-hour average ozone level for high emission scenarios (Kemball-Cook et al., 2010). Considering that the current air quality standard for ground-level ozone is 75 ppb, this disturbance is a significant increase and an important regional impact.

Dr. Robinson emphasized that effective control measures do exist for emissions from shale gas activities. For example, for compressor stations, technology such as oxidation catalysts, selective catalytic reduction, and stoichiometric combustion engines with three-way catalysts can reduce the emissions of NO_x, VOCs, and formaldehyde. For drill rigs and hydraulic fracturing pumps, it is possible to use selective catalytic reduction and diesel particulate filters to reduce emissions. Fuel switching from diesel to natural gas is also an option, and will reduce diesel particulate matter (but not necessarily NO_x emissions). Finally, removing waste water from drill sites with pipe networks instead of with trucks can reduce emissions. A new oil and gas regulation is going to require green completion, which is predicted to reduce VOCs by 95 percent (EPA, 2006). Flaring also will substantially reduce emissions (by 51 to 84 percent) (EPA, 2006). Vapor recovery units on condensate tanks can reduce emissions by 91 to 95 percent (EPA, 2006). Dr. Robinson noted that society needs to decide what level of emissions is acceptable, and then implement various rules to achieve the necessary reductions. All of the technology currently exists.

When discussing air pollution and natural gas, it cannot be overlooked that natural gas development provides some air quality benefits to end users, Dr. Robinson stated. Natural gas is a cleaner burning fuel and emits less NO_x, sulfur dioxide, PM, and carbon monoxide (Lash and Engelder, 2009). For example, switching from coal to natural gas can improve air quality around power plants. Therefore there are many potential air quality benefits associated with greater use of natural gas. However, one cannot ignore the challenges on the development and production side; it is a matter of deciding what the appropriate level of control is, and then implementing strategies.

The Monitoring Process in Practice

Dr. Honeycutt described the types of monitoring that are used to monitor emissions. Observational data on levels of criteria and noncriteria pollutants (such as the instance described above) are collected using fixed-site and short-term monitoring methods. TCEQ carries out two types of long-term fixed-site monitoring. One type uses a fixed-site canister to capture air samples. A stainless steel, clean canister is put under vacuum and attached to a timer and flow controller. On the day that samples will be taken, a valve opens at midnight, and air is pulled through the sampler and into the canister. This continues for a 24-hour period. At midnight the next night, the sampler shuts off. A technician travels to the site the following day, takes out the old canister, and puts in a new one. The sampled canister is shipped to Austin to be analyzed by the toxicology lab. Six days later, the monitor takes another 24-hour sample. This type of monitoring station is permanent and provides a 24-hour sample every sixth day.

The other type of long-term sampling is fixed-site auto gas chromatography (AutoGC). This sampler is housed in a trailer. AutoGC takes an hourly sample; of every hour, 40 minutes are used to collect a continuous air sample, 10 minutes are needed to run the GC analysis, and 10 minutes are required to prepare for the next air sample. This machine operates 24 hours a day and 365 days per year; it collects samples 22 hours per day, 1 hour is devoted to a calibration curve, and the other hour is for a quality assurance/quality control sample. The two control steps are alternated so that the same 2 hours are not omitted each day. Because it provides data continuously, AutoGC provides a wealth of information.

AutoGC can be a fixed-site monitor, but, when necessary, mobile laboratories can be equipped with this technology. These laboratories can be placed right on the property line of oil and gas facilities. Investigators can be out in the field for several weeks at a time collecting samples on many types of chemicals with these monitors.

Dr. Honeycutt reported that a monitor in Longview, Texas, in the Haynesville Shale, detected elevated concentrations of benzene. Benzene is an air toxic that TCEQ is monitoring closely. Benzene is the chemical whose measured concentration is closest to what is considered an acceptable level. Every other chemical that is currently being monitored is further below its acceptable level compared to benzene.

The monitor for this site had been functioning since 1998. Dr. Honeycutt noted that in 2005 there were some slight increases in the annual average benzene concentration, and in 2007 it really climbed. It was above the TCEQ long-term screening value of 1.4 ppb.

This monitor is located 1,100 feet to the northeast of a new oil and gas facility. The facility had only been constructed the year before the monitor started detecting elevated levels of benzene. TCEQ explored the facility and collected air samples. They found that some of the storage tanks were not designed properly. There were significant emissions from those tanks (benzene levels of 1,100 ppb were measured in their vicinity). These benzene leaks were being picked up farther away by the permanent monitoring station. TCEQ worked with the responsible operator to figure out what was going on and to fix it. The next year, benzene levels dropped below 1.4 ppb, and they are still trending downward.

This case underscores a concern of TCEQ about air quality and gas developments. There are many gas developments in Longview, Texas—about one every 0.25 mile. The well immediately south of a monitor was the one to which a problem was traced. TCEQ may have been fortunate to have had a monitor in exactly the right location to pick up on the sole source of benzene emissions in the town. But there was also the possibility that these issues were widespread, and there were no long-term monitors near the rest of the wells to alert TCEQ to problems.

To determine how widespread problems were, TCEQ needed to quickly evaluate many shale gas development wells. To carry out this short-term monitoring and evaluation, TCEQ mounted the GasFindIR™ camera (especially developed for detection of gas leaks) on a helicopter. GasFindIR™ reveals VOC emissions such as methane—they cannot be seen by the naked eye, but, on camera, they appear as dark, billowy smoke. TCEQ has conducted flyovers of the Barnett Shale and Eagle Ford Shale. It costs about $100,000 to conduct a flyover, but it is the best money spent in terms of reducing emissions. Using this camera from a helicopter allows thousands of wells to be surveyed at a time. After the footage is examined, TCEQ can approach the well operators and inform them of a problem. But, finding a problem is atypical. Of the 5,000 storage tanks surveyed in the Barnett Shale, only 88 had significant hydrocarbon emissions.

There are also handheld GasFindIR™ cameras that make it possible to screen many facilities quickly. They are slightly bigger than home camcorders, and field investigators can walk around a facility with them. Since August 2009, TCEQ has surveyed 2,122 gas development sites using GasFindIR™ cameras, and, at 2,078 of these sites, handheld VOC samplers were also used. Whenever there is something of interest, an instantaneous or short-term (30 minutes to 1 hour) canister sample can be taken. On the basis of observations with these instruments, 1,126 canister samples have been collected and analyzed for VOCs. There are other VOCs that TCEQ assesses as well, and this is possible with other instruments that detect nonmethane hydrocarbons. Short-term samples also have been collected and analyzed for carbonyls, NO_x, and sulfur compounds.

Indications from Short-Term Monitoring

Dr. Honeycutt provided an overview of findings from short-term monitoring. He said that less than 5 percent of the more than 1,100 VOC canister samples mentioned above exceeded a short-term, health- or odor-based air monitoring comparison value (AMCV).¹ Texas regulates chemicals for odor, and some VOCs, such as isobutane and isopentane, have been detected above an odor-based AMCV. Some samples (e.g., benzene and carbon disulfide) have been elevated above a short-term health-based AMCV. Most of these were discovered when TCEQ initiated its monitoring program. The actions taken by TCEQ since then have decreased the number of residents’ complaints of odor.

TCEQ continues to receive some citizen complaints of odor and irritation, and investigators are experiencing similar symptoms in the field. These complaints are thought to be related to a glycol degradation product. TCEQ researchers are trying to figure out what could possibly be emitted with the aim of designing sampling and analysis techniques to monitor these emissions in the future, Dr. Honeycutt said.

Indications from Long-Term Monitoring

Dr. Honeycutt also provided an overview of results from long-term monitoring. Six million to 7 million people live in the DFW metro area (U.S. Census Bureau, 2013). There are about 15,000 wells in the Barnett Shale geologic formation. There are seven fixed-site canister samplers, five fixed-site AutoGC monitors, and two sites where they are co-located (for the purpose of comparing the data between methodologies). There are pros and cons to both types of samplers. The target analyte list for the canister sampler includes about 85 chemicals. The target analyte list for the AutoGC sampler includes only about 55 chemicals. But the hourly aspect of the outputs from the AutoGCs provides more data with which TCEQ can work. The state is prepared to set up five more AutoGC monitors, but it takes time to select an appropriate site for the monitoring station. It is expected that the amount of data available is going to grow exponentially in the near future.

Despite the massive growth in the number of wells, there is no indication from the long-term monitoring of benzene that there is a health risk. (Recall that benzene is the chemical closest to exceeding its acceptable level and is therefore considered the risk driver.) The newer stations are aptly situated both to capture community exposure and to monitor sources. Based on the monitoring data, there is nothing that concerns TCEQ on an airshed level; all levels of benzene are below the 10^-5 risk level² used by the U.S. Environmental Protection Agency (EPA). In fact, some of the lowest monitored levels of benzene across the state are in the Barnett Shale—other parts of Texas have higher benzene concentrations, Dr. Honeycutt said.

In the town of Dish, Texas, many residents were concerned about the effects of shale gas development. The state health department visited the town in 2010 to collect biological samples from 28 residents. The health department examined VOCs in blood and VOC breakdown products in urine, and took samples of tapwater. They compared these data to National Health and Nutrition Examination Survey data and concluded that community-wide exposures from gas wells or compressor stations have not occurred in the sample population.

The results of the analyses of all of TCEQ’s samples are online in the form of an interactive map.³ It is possible to click on a region of the map to determine the concentrations found there, and it is also possible to enter an address to find the data from the nearest station. According to Dr. Honeycutt, this is a great public relations and communications tool.

TCEQ’s Current Activities

Dr. Honeycutt concluded his remarks by noting that the issues TCEQ did document were found early in the monitoring process. Almost all of those were human and mechanical failures on the part of the companies. Corrective actions for those—tightening valves, replacing gaskets, closing hatches—were easy to implement. TCEQ is still actively executing compliance investigations with handheld monitors, but when an issue is found, there is usually an easy fix for the problem. TCEQ is also implementing new rules for best management practices. It is conducting outreach and attempting to educate well operators and the public. For the well operators, TCEQ instructs them about the differences between percentages and parts per billion as they pertain to monitoring emissions. For the public, they host open houses to disseminate information about shale gas development and monitoring activities. Transparency and citizen access to information is important; therefore all data are available on TCEQ’s website.

The HIA in Garfield County

Dr. Adgate discussed the process used to conduct the HIA. Garfield County has long-term air monitoring stations operated by their Department of Public Health. These stations collected canister air samples over 24-hour periods that were analyzed in EPA-certified labs. The lab quantified 78 nonmethane VOCs. Overall, there were 163 ambient air samples; one was collected every 6 days over the span of almost 3 years. These samples were used to characterize ambient air levels in the natural gas development area between 2008 and 2010; this was the period over which production peaked and then started to wane.

To collect additional data for the HIA, representatives of Garfield County Public Health staff visited a well site to conduct air sampling. Surrounding the well site was the supporting infrastructure that develops over time, and farther away were previously established agricultural zones, ranches, and beehives. There were no houses within 1,000 feet of this particular operation. The team noted that hatches were open on the tanks that hold the wastewater after it flows out of the well, and they were able to smell odors.

To characterize the peak emissions of the well development process Garfield County Public Health staff collected samples from the period of flowback and well completion while at the well site. The flowback process is when the water used for fracturing exits the well, usually carrying hydrocarbons. There were 24 samples collected at distances between about 150 and 500 feet from these well sites, and they were used as part of this human health risk assessment process.

To develop risk estimates, many questions needed to be addressed. How long are these wells in place? How long does it take to develop a well? How many wells are on a pad? How many pads are there in a community? To address some of these, EPA methods were used to estimate risks over two durations: subchronic (short-term effects) and chronic (longer-term effects). The subchronic exposure scenario assumed a 20-month period,⁴ because this is the length of time a resident would be exposed to pollutants from well development. The chronic exposure scenario assumes a 30-year period because natural gas could be produced from a mature well for 20–30 years.

Dr. Adgate noted that to address uncertainty in these estimations, many assumptions were made during these calculations. One assumption concerned the two distance-related categories of exposure. Exposures were divided into “near” and “far” based on citizen complaints about odor. Essentially, those who could smell gas well activities and lived less than half a mile away were classified as near to a well. Everyone else was classified as living far from the well. Also, the analysis used “default” options that assume reasonable maximum exposure and are designed to be health protective. They presume that a resident remains in the town 24 hours per day, 350 days per year, which necessitates using the upper bound (95 percent upper confidence limit) of mean concentration estimates for the various air toxics.

To conduct the human health risk assessment, researchers from the Colorado School of Public Health used standard EPA methodology. The researchers combined existing data with interesting new data that had not yet been reported in the scientific literature. The longer-term and peak data just described went into creating exposure scenarios. There were four scenarios: chronic-far, subchronic-far, chronic-near, subchronic-near. Both far scenarios relied only on the ambient air data from the permanent monitoring stations. The subchronic-near scenario used only the 24 air samples from the peak well-completion phase. The chronicnear scenario used the time-weighted average of the peak wellcompletion samples (a duration of 20 months) and ambient air samples over a duration of 30 years.

To quantify noncancer health risks, hazard indexes (HIs) were used. The HI is the sum of all applicable semiquantitative hazard quotients (HQs). For each compound detected, an HQ is computed, which is the ratio of the estimated exposure to the reference concentration (RfC). RfCs are values that are suggestive of exposures at which noncancer health effects may occur, and are catalogued in the EPA’s Integrated Risk Information System. This system provides both chronic and subchronic RfCs, and each RfC was applied in the appropriate scenario. Dr. Adgate said that the meaningful question is whether the HI is greater than 1. If it is less than 1, it is possible to be confident of few health effects. If it is greater than 1, then risks to health are more likely.

The process of estimating cancer risk is distinct from estimating noncancer health effects. The long-term average exposure for each carcinogen was estimated for a 30-year time period using the ambient air sampling data. This exposure was multiplied by an inhalation unit risk value, which indicates potency of the carcinogen, to compute the lifetime excess cancer risk. The risk level was summed across the different carcinogens that were detected to compute cumulative lifetime cancer risk. The lifetime cancer risk is an indication of the number of excess cancers in a population of 1 million people. The criterion used to evaluate risk from carcinogens is whether the risks are greater than 1 in 1 million (i.e., is there more than 1 excess cancer within a population of 1 million people).

Findings of the HIA

Dr. Adgate reiterated that there were four different scenarios used to calculate HIs: chronic-far, subchronic-far, chronic-near, subchronic-near. For noncancer health effects, it was determined that the HI is greater for those living closer to well sites (see Figure 5-3), although most HIs did not reach a level of concern. The HI for chronic-far was 0.4, and the HI for chronic-near was 1. The HI for subchronic-far was 0.2, and the HI for subchronic-near was 5 (McKenzie et al., 2012). Only the HI for subchronicnear was above 1—which is above the level of concern. The next question is what can be done about this, that is, how can exposures and risk be reduced.

FIGURE 5-3

Hazard indexes by duration of exposure and distance from source. SOURCE: Adgate, 2012.

Instead of averaging all HQs to find a single HI, it is possible to categorize toxics by health outcome and calculate an HI for neurological effects only, or respiratory effects only, etc. For the subchronic-near exposures, the data were parsed on the basis of health end points. For neurological effects, the HI was 4. For respiratory effects, the HI was 2. For hematological effects, the HI was 3. For developmental effects, the HI was 1 (see Figure 5-4) (McKenzie et al., 2012). The first three health end point categories are in the range of concern, Dr. Adgate noted, where action likely should be taken to reduce exposure. For example, new controls could be mandated to be put in place to limit citizens’ exposures.

FIGURE 5-4

Hazard indexes by health end point: Near wells, 20-month exposure scenario. SOURCE: Adgate, 2012.

The biggest contributor to the hazard index was trimethylbenzenes, which were responsible for 46 percent of the estimated risk. The next biggest contributors were aliphatic hydrocarbons (21 percent) and xylenes (15 percent) (McKenzie et al., 2012). Adgate noted that benzene was a relatively small contributor, at only 5 percent. So, a range of compounds is responsible for the health effects, and a fair amount is known about these from a toxicological standpoint. These data may inform some of the practices aimed at reducing risks and health effects.

Dr. Adgate noted that the estimated cancer risks for a 30-year exposure were in the range that does not typically warrant concern. There was a 6 in 1 million risk for residents living far from a well, and 10 in 1 million risk for residents living close to a well. This is above the 1 in 1 million risk level, but below the level at which the EPA typically requires remediation. Overall, concentrations were similar to or higher than those observed in many urban areas. Benzene, although it contributed little to the noncancer health effects, was, along with ethylbenzene, the main risk driver for cancer risk.

Residents living near well completion activities are potentially exposed to substantial levels of air toxics. Subchronic noncancer cumulative and end point specific hazard indexes are greater than 1 for residents living near well pads. Also, estimated cancer risks and chronic noncancer hazard indexes are greater for these residents living near the well pads, but are within a generally acceptable range.

There are many uncertainties and limitations within this study, Dr. Adgate noted. The sample size was small, using only 24 samples to assess 78 compounds collected from 150 to 500 feet around the well source. In general, limited data exist on emissions around well completion sites. In addition, nonmethane pollutant emissions appear to vary substantially by field type, number of wellheads, completion process, and controls used. Only a limited suite of volatile compounds was explored here, which excluded other primary or secondary pollutants (e.g., aldehydes, diesel exhaust, etc.). In summary, Dr. Adgate said that short-term exposures are probably important to address and that prevention strategies should be directed at minimizing exposures during well completion activities to reduce potential subchronic noncancer risks.