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ArticleApril 5, 2016

Aerial Surveys of Elevated Hydrocarbon Emissions from Oil and Gas Production Sites
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Environmental Science & Technology

Cite this: Environ. Sci. Technol. 2016, 50, 9, 4877–4886

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https://doi.org/10.1021/acs.est.6b00705

Published April 5, 2016

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Abstract

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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, χ² 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.

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Introduction

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Hydrocarbon emissions from oil and gas (O&G) facilities pose multiple risks to the environment and human health. Methane, the primary constituent of natural gas, is a short-lived greenhouse gas with 28–34 and 84–86 times the cumulative radiative forcing of carbon dioxide on a mass basis over 100 and 20 years, respectively. (1) Burning natural gas instead of other fossil fuels may increase net radiative forcing for some time, even if carbon dioxide emissions decline, depending on the loss rate of methane across the O&G supply chain. (2) O&G hydrocarbon emissions also include volatile organic compounds (VOCs), which are defined by the United States Environmental Protection Agency (U.S. EPA) as photochemically reactive organic compounds excluding methane and ethane. VOCs contribute to regional ozone formation and have been linked to elevated ozone levels in several O&G producing regions. (3, 4) Certain VOCs such as benzene are toxic and may be connected to increased risk of cancer and respiratory disease in some areas with O&G development. (5, 6)

Hydrocarbons (HC) can be emitted from vented, fugitive, or combustion sources. Vented HC emissions are intentional releases of natural gas from blowdowns (releasing gas to depressurize equipment for maintenance or safety) or sources that emit as part of routine operations such as pneumatic controllers. Fugitive HC emissions are unplanned releases from equipment leaks or malfunctioning equipment. Combustion HC emissions include uncombusted hydrocarbons in the exhaust of combustion sources such as compressor engines and flares. HC emissions can also occur from storage tanks for oil, natural gas condensate, and produced water. Tanks can be the source of both vented emissions, such as flashing losses when liquids are dumped from high-pressure separators to atmospheric pressure tanks, and fugitive emissions caused by malfunctioning separators or control devices. Unlike emissions of raw natural gas, which are primarily composed of methane, oil and condensate tank flashing emissions tend to be dominated by heavier alkanes such as propane and butane. (7)

Recent studies have used two broad approaches to estimate methane or VOC emissions: top-down methods that quantify emissions at the regional or larger scale at one or more points in time, and bottom-up methods that use activity data and emission factors to scale up component- or facility-level measurements to generate emission inventories. Generally, top-down estimates of methane emissions have been greater than bottom-up estimates. (8, 9) In the Barnett Shale, a coordinated campaign with simultaneous top-down and bottom-up methods was able to reconcile aircraft mass balance estimates of regional O&G methane emissions with a custom emission inventory based on local and national facility-level measurements. (10, 11) Compared to traditional bottom-up inventories, the coordinated campaign inventories estimated higher emissions due to more comprehensive activity data and the inclusion of high emission “superemitter” sites in the development of emission factors. (11, 12)

Many types of O&G facilities have highly skewed emission distributions with a small fraction of sites contributing the majority of emissions. (13-17) These high emission facilities, often referred to as superemitters, may include some sites with persistent emissions and others with intermittent episodes of large releases. (18) High emission rates are likely due to both fugitive emissions caused by malfunctions and vented emissions such as tank flashing or blowdowns. The identification and mitigation of high emission sites is critical to reducing regional emissions since these facilities contribute a large portion of total O&G emissions. (18, 19) If the identity of these sites can be predicted, then it would be effective to focus mitigation efforts on sites with characteristics most often associated with high emissions. However, if the occurrence of high emissions is stochastic, then the only viable mitigation solution would be frequent or continuous monitoring of all sites in order to quickly identify and mitigate those with excess emissions.

A common method to detect HC leaks at O&G facilities is optical gas imaging, which has been proposed by U.S. EPA as a regulatory requirement for new and modified sources. (20) Since methane and other HC emissions are invisible to the naked eye, infrared (IR) cameras are used to visualize HC plumes. (21) IR cameras can not differentiate individual HC species nor quantify emissions under field conditions, but their ability to identify the exact location of an emission source is highly valuable for mitigation. A skilled technician on the ground can use an IR camera to quickly survey thousands of components at an O&G facility for leaks. (22) Helicopter-based IR camera surveys have been used by operators and regulatory agencies to inspect large numbers of sites for high emission rate sources that may indicate equipment issues or noncompliance with environmental regulations. (23)

In this study, we use data collected during helicopter-based IR camera optical gas imaging surveys of more than 8000 O&G well pads to assess the prevalence and distribution of high-emitting HC sources in seven U.S. O&G basins. Survey data were analyzed to determine patterns and statistical relationships of observed emissions with well pad and operator parameters. In turn, observed frequencies of high emission sources were compared to predicted frequencies of observable tank flashing emissions with and without controls to assess if detected emission sources indicate the presence of malfunctioning emission control systems.

Methods

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Survey areas were selected by stratified random sampling in seven U.S. O&G basins accounting for 33% and 39% of U.S. oil and gas production, respectively: Bakken (North Dakota/Montana), Barnett (north central Texas), Eagle Ford (south Texas), Fayetteville (Arkansas), Marcellus (Appalachian Basin), Powder River (Wyoming/Montana), and Uintah (Utah). Subregions in each basin were selected on the basis of their suitability for helicopter surveys (<1500 m above sea level, unrestricted airspace) and subdivided into 10 × 10 km grid cells. Due to their large size, subregions in the Bakken, Marcellus, and Powder River were centered on areas with active drilling in northwest North Dakota, southwest Pennsylvania, and eastern Wyoming, respectively. Data on well pad characteristics for each of these subregions were obtained for wells with an active status from the production database Drillinginfo, which contains data compiled and cleaned from state databases. (24)

One or two defining characteristics were identified for each region that best characterized the heterogeneity of the basin’s O&G production and could be the basis for stratified sampling. The selected strata were gas-oil ratio (GOR) in produced fluids (Barnett and Uintah), well age (Bakken), a combination of well age and GOR (Marcellus), and well type of oil, gas, or coal-bed gas (Powder River). These strata were chosen to reflect the distinguishing characteristics in each region (e.g., GOR does not vary greatly in the Bakken, so no meaningful stratification is possible along that dimension). Parameter thresholds separating strata were selected independently for each basin to divide grid cells into two or three quantiles of average parameter values. After assigning grids to strata based on their average parameters, a list of grids in each stratum was randomly selected for survey. In two basins, this design was not followed. In the Fayetteville, a single 20 × 20 km area was selected due to limited survey time and homogeneous production across the basin (dry gas without oil). In the Eagle Ford, two unstratified 40 × 15 km survey areas that each covered the basin’s broad range in GOR were selected to facilitate efficient measurements by additional research aircraft. A map of surveyed basins is shown in Figure S1.

Survey area boundaries were provided to a professional firm with extensive experience performing leak detection surveys of O&G sites from a helicopter using optical gas imaging (Leak Surveys, Inc.). (25) Flights occurred from June to October 2014 using an R44 helicopter. The survey team identified O&G well pads, compressor stations, and small gas processing plants in the survey areas; for this paper, only data from active well pads are included in the analysis. Camera operators used a FLIR GasFindIR infrared camera to visually survey sites for detectable hydrocarbon plumes at an elevation of approximately 50 m above ground level. At each site with detected emissions, the survey team reported the site’s latitude/longitude and the number and equipment type of each observed emission source. Additionally, an IR video was recorded at each site with detected emissions, typically by circling the site and focusing on observed emission sources for 20 to 80 s. Videos were reviewed by the lead author to verify the number and type of detected sources.

Two independent methods were used to estimate the minimum detection limit of optical gas imaging with an IR camera deployed from the survey helicopter. First, an operator in the Fayetteville performed a controlled release of dry natural gas (97% CH₄) from a pipeline pig receiver at a midstream facility while being observed by the helicopter survey team from a typical survey position during cloudy conditions. A variable orifice was used to release natural gas at three rates. These rates were quantified by the bagging method at ∼3, 8, and 27 g s^–1, respectively. The helicopter survey team recorded observable plumes from all three controlled release tests with the lowest release rate producing only faint images that appeared to represent the detection threshold under test conditions. Second, an aircraft with a methane analyzer used the atmospheric budget method to quantify methane emissions at 19 well pads and compressor stations within 1 h of detection by the helicopter survey team (See the Supporting Information for methodological details). Measured site emission rates ranged from 1 to 24 g CH₄ s^–1 with 84% of central estimates above 3 g CH₄ s^–1 (Table S1). Additionally, the helicopter survey team qualitatively ranked the size of emission sources based on the apparent size and density of plumes, but there was no correlation between the qualitative magnitude of emission sources estimated from experienced camera operators and the quantified methane emission rates; potential reasons are discussed in the Supporting Information. Variability in the IR camera’s sensitivity to different hydrocarbons (HC) is expected to impact the detection limit. The GasFindIR camera can detect at least 20 different HCs with differing functionality and has the highest sensitivity to alkanes; the reported minimum detectable emission rate under controlled conditions is 2–4 times lower for propane than methane under controlled conditions. (21) While there may be differences in the ratio of minimum detectable emissions rates in the field compared to controlled conditions, a ratio of 3 was chosen as representative of the increased sensitivity of the camera to higher molecular weight HCs. Therefore, the helicopter survey detection limit was assumed to be ∼3 g HC s^–1 for dry gas sources with emissions composed primarily of methane and ∼1 g HC s^–1 for sources such as tanks with emissions composed primarily of higher HCs such as propane. The detection limit of the IR camera is also affected by wind speed. We assessed the average wind speed during surveys based on hourly data during daytime hours from local weather stations. Average wind speed ranged from 2.7 m s^–1 in the Uintah to 6.4 m s^–1 in the Powder River (Table S2). On the basis of the power law relationship between wind speed and detection limit reported in Benson et al., the difference in wind speed would cause the average detection limit to be 3–4 times higher in the Powder River compared to the Uintah. (21) Therefore, variability in wind speed contributes uncertainty to the detection limit of a similar magnitude as variable gas composition.

Because survey results were reported for unique well pads rather than by individual well (i.e., many sites had multiple wells), the latitude/longitude of individual wells in surveyed areas were used to aggregate wells into pads by spatially joining all active wells within a 50 m buffer distance. (18) For each pad, well-level data were used to determine the operator, well production type (oil, gas, oil and gas, coal bed methane), well drill type (vertical, horizontal, directional), number of wells, pad age (months since initial production of newest well), gas production, hydrocarbon liquid production, and water production. (24) Hydrocarbon liquid production includes both crude oil and natural gas condensate; for this analysis, the term “oil” is used to refer to all hydrocarbon liquids. Water production data were not available for individual wells in the Fayetteville or Marcellus basins. Parameters were specific to the same survey month for all basins except the Marcellus, for which only annual and semiannual data were available for conventional and unconventional wells, respectively. In addition to pad-specific parameters, operator-specific parameters were calculated for each basin based on operators’ full population of wells in each basin. Surveyed sites with detected emissions were matched to individual pads in the survey area using the reported latitude/longitude as well as Google Earth imagery.

The helicopter-based team surveyed 8220 well pads located throughout an area of 6750 km². Average well pad characteristics by basin and strata are summarized in Table S3. The average number of wells per pad ranged from 1.1 in the Uintah to 2.7 in the Fayetteville. Well pads were newest in the Fayetteville (average age of newest well on each pad of 4.1 years) and oldest in the Barnett (13.4 years). Average gas production ranged from 65 Mcf pad^–1 day^–1 in the Uintah to 1438 Mcf pad^–1 day^–1 in the Fayetteville. Average oil production ranged from 0 bbl pad^–1 day^–1 in the Fayetteville to 312 bbl pad^–1 day^–1 in the Eagle Ford. For the basins with oil production, GOR was lowest in the Bakken (1.2 Mcf bbl^–1) and highest in the Marcellus (153 Mcf bbl^–1). To assess the representativeness of surveyed sites, we compared these parameters between surveyed sites and the total population of active wells in each basin in 2014 (Table S4). For almost all parameters, surveyed sites had statistically different distributions than the entire basin (Kolmogorov–Smirnov p > 0.05) but the percent difference for most values was <25% from the basin mean and almost always within 50%. In all basins, surveyed wells were younger than the full population; in the Bakken, Barnett, Eagle Ford, Marcellus, and Powder River, surveyed wells had higher gas production and/or oil production than the basin average. These slight biases likely resulted from selecting subregions with active drilling to include young sites in our survey areas. Overall, our sampled strata account for the full range of diversity within and across basins and are appropriate for assessing patterns in high emissions.

Pearson’s correlation coefficients (r) were used to assess correlation between the presence (nondetect = 0, detect = 1) or number of detected emissions by source type and pad or operator parameters. Binomial generalized linear models (GLM), also known as logistic regression models, were used to predict the probability of detected emissions at a well pad (P_detect) from site and operator parameters. Analysis of variance models and Tukey’s Honest Significance Difference test were used to assess significant differences in P_detect among basins, strata, well type, and drill type. Poisson GLMs were used to predict the number of detected sources by emission type at each pad. For the full data set and individual basins, several single parameter and multiparameter GLMs were evaluated on the basis of their simplicity, Akaike Information Criteria, Pearson’s r, and Hosmer-Lemeshow goodness of fit between observed and predicted values to select models meaningful for explaining the effects of parameters on emissions. An alpha level of 0.05 was used to determine statistical significance in all tests. For statistical analyses, percent energy from oil was used as a surrogate for GOR since it has a discrete range and is more normally distributed; this metric was calculated from oil and gas production using an assumed energy content of 5.8 MMBtu bbl^–1 for oil and 1.05 MMBtu Mcf^–1 for natural gas. (26)

Results and Discussion

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A total of 494 unique high emissions sources at 327 well pads were detected by the helicopter survey team out of 8220 surveyed well pads in seven basins. The percentage of total well pads with detected HC emissions (P_detect) was 4% but ranged from 1% in the Powder River to 14% in the Bakken (Table 1). There were statistically significant differences in P_detect by basin with the Bakken higher than all other basins (see Table 1 for full pairwise comparisons). Emissions were more often observed in oil-producing areas with an average P_detect of 13% in the Bakken and low gas-to-oil ratio strata of mixed production basins (p < 0.0001, χ² test). For example, in the Barnett, 21% of well pads in the low GOR strata showed detectable emissions compared to <1% of sites in the high GOR strata (Table 1). There were also significant differences in P_detect by well production type (oil and gas > oil > gas > coal bed methane) and well drill type (horizontal > directional and vertical).

Table 1. Infrared Camera Survey Results by Basin and Strata^a

		detected sources				well pads with detected sources
basin	strata	number	% tank vents	% tank hatches	% other sources	number	% of pads
Bakken	young	109	9%	83%	7%	57	14.9%^a
	old	61	10%	85%	5%	37	12.4%^a
	all surveyed	170	9%	84%	6%	94	13.8%^w
Barnett	high GOR	10	60%	50%	0%	7	0.7%^a
	medium GOR	9	22%	67%	11%	6	1.4%^a
	low GOR	60	55%	40%	3%	46	20.6%^b
	all surveyed	79	52%	44%	4%	59	3.5%^y
Eagle Ford	east	70	61%	34%	3%	29	11.0%^a
	west	1	0%	100%	0%	1	0.3%^b
	all surveyed	71	61%	35%	3%	30	5.4%^xy
Fayetteville	all surveyed	24	17%	83%	0%	13	4.4%^xyz
Marcellus	high GOR, younger age	17	76%	12%	12%	13	1.4%^a
	high GOR, older age	0				0	0.0%^b
	low GOR	15	13%	87%	0%	11	10.7%^c
	all surveyed	32	47%	47%	6%	24	1.2%^z
Powder River	coal bed methane	0				0	0.0%^a
	oil/CBM mix	0				0	0.0%^a
	oil	18	44%	39%	22%	15	11.2%^b
	all surveyed	18	44%	39%	22%	15	1.0%^z
Uintah	high GOR	3	67%	0%	33%	3	2.2%^a
	medium GOR	59	75%	5%	20%	52	6.3%^ab
	low GOR	38	63%	21%	16%	37	8.8%^b
	all surveyed	100	70%	11%	19%	92	6.6%^x

all basins		494	40%	52%	8%	327	4.0%

For the percentage of pads with detected emissions (P_detect), letters indicate statistically significant differences among strata within each basin (a–c) and among basins (w–z) as determined by Analysis of Variance models and Tukey’s HSD (p < 0.05). For example, within the Barnett, P_detect in the low GOR strata is statistically different than the high GOR and medium GOR strata; the overall Barnett P_detect is statistically different than overall P_detect of the Bakken, Marcellus, Powder River, and Uintah.

Tank hatches and tank vents were the most common source type of detected emissions, comprising 92% of observed sources (Table 1). The remaining 8% of detected emission sources were dehydrators, separators, trucks unloading oil from tanks, and unlit or malfunctioning flares. Detected emission sources represent individual release points with HC emission rates exceeding the survey’s estimated detection limit of approximately 3 g s^–1 for CH₄ or 1 g s^–1 for heavier HC. Given this detection limit, no emissions were observed from equipment leaks, pneumatic controllers, or chemical injection pumps, consistent with two recent studies that observed a maximum emission rate of 1.5 CH₄ g s^–1 at over 1000 such measured sources. (27, 28)

There are several factors that may account for differences among basins in P_detect including operational practices, emission control regulations, and the mix of produced hydrocarbons. The effect of weather conditions on the detection limit may also have impacted the frequency of observed emissions. In particular, the higher average wind speed in the Powder River may have contributed to the low frequency of observations.

Statistical Analyses

There were statistically significant but relatively weak positive correlations between detection and numerous well pad parameters: well count, gas production, oil production, water production, and percent energy from oil (Table 2; r = 0.06 to 0.20). Detection was negatively correlated with well age (r = −0.12), meaning that newer wells were more likely to have detected emissions. The average P_detect by decile of analyzed pad parameters is shown in Figure 1. One binomial generalized linear model, GLM A4, predicted detection that was not significantly different than that observed (Hosmer-Lemeshow >0.05); this multiparameter model used basin, the numerical pad parameters well count, well age, gas production, oil production, and percent energy from oil, and the interactions of basin with each numerical parameter, to explain 14% of the variance in P_detect (r² = 0.14). Three other multiparameter GLMs had observed and predicted detections that were statistically different and explained 3–8% of the variance: A1, using basin only; A2, using numerical parameters only; and A3, using basin and the numerical parameters but not their interactions (Table S5, r² = 0.03, 0.07, and 0.08, respectively). The increase in predictive power indicates that the effect of well pad numerical parameters on P_detect varies by basin. For example, in the Marcellus, Powder River, Barnett, and Uintah basins, which have a mix of produced hydrocarbons with a wide range of GOR, there was a significant positive effect of percent energy from oil on predicted P_detect, while there was no significant effect of this parameter in the basins with more homogeneous production.

Figure 1. Percentage of well pads with detected emissions by deciles of well pad parameters: (a) well count (wells per pad), (b) well age (months since initial production of newest well), (c) gas production (Mcf/day), (d) oil production (bbl/day), (e) water production (bbl/day), and (f) % energy from oil. The median values of each decile are displayed on the x-axes.

Table 2. Correlation of Well Pad and Operator Parameters with P_detect (the Detection of Emissions at a Site; Nondetect = 0, Detect = 1) or the Number of Detected Sources by Type^a

parameters
		P_detect	total sources	tank vents	tank hatches	nontank sources
well pad parameters	well count	0.15	0.16	0.15	0.10
	well age	–0.12	–0.10	–0.08	–0.07	–0.03
	gas production	0.12	0.11	0.15	0.04
	oil production	0.20	0.28	0.24	0.19
	water production	0.06	0.06	0.04	0.06
	% energy from oil	0.19	0.16	0.10	0.12	0.06
operator regional parameters	well count	–0.11	–0.09	–0.06	–0.06	–0.05
	gas production	–0.05	–0.03	–0.03		–0.04
	oil production	0.09	0.10	0.06	0.08
	water production	–0.06	–0.06	–0.04	–0.03	–0.06
	% energy from oil	0.17	0.14	0.08	0.12	0.06

Well pad parameters represent the individual site. Operator parameters represent all regional well pads operated by the same company as each surveyed site. Reported values are Pearson correlation coefficients (r) that are significantly different than zero (p < 0.05).

The most predictive GLM, A4, only explained 14% of the variance, which indicates that the presence of high emissions was primarily stochastic or driven by operational characteristics not included in this analysis. Therefore, statistical models have limited utility for predicting the occurrence of individual high emission sources. However, the relatively weak, statistically significant correlation of several parameters with P_detect does provide some insights into factors affecting the likelihood of high emissions. To assess the effects of well pad characteristics on detection, we evaluated single parameter GLMs for the full data set and individual basins (Table S6). For the full data set, the GLMs with the best fit between observed and predicted detection were based on well age (r² = 0.04), oil production (r² = 0.03), and percent energy from oil (r² = 0.03). The relative strength of the effects of parameters on the likelihood of detection can be assessed by the ratio of GLM predicted P_detect at the 97.5th and 2.5th percentile of parameter distributions. For example, predicted probability of detection for a pad at the 97.5th percentile of well count (P_detect = 0.11; 5 wells per pad) is 3.2 times higher than for a pad at the 2.5th percentile (P_detect = 0.03; 1 well per pad). For individual basins, single parameter GLMs with statistically significant fits had the same directional effects as the full data set but varied in their relative strength. The best fit GLMs were based on well count in the Bakken and Marcellus, well age in the Powder River and Uintah, and oil production in the Barnett and Eagle Ford. In the Fayetteville, no single parameter GLM had a statistically significant fit. Detailed parameters for GLM A4 and single parameter GLMs are reported in Tables S16 and S17.

Other studies have reported a weak positive correlation between gas production and methane emissions. (13, 28, 29) In a prior study of the Barnett Shale, the top 7% of well pads by gas production were estimated to contribute 29% of total methane emissions; this was attributed to higher absolute emissions yet lower proportional loss rates of produced gas at high production sites. (18) The positive correlation between oil production and emission detection may be related to a higher frequency of tank flashing with increased oil production. Brantley et al. reported that oil production was negatively correlated with methane emissions as part of a multivariate linear regression model, which the authors attributed to lower methane content relative to heavier HCs in gas from oil producing wells. (13) In this study, the opposite effect would be expected since the IR camera detects all HCs with higher sensitivity to heavier HCs. The positive relationship between the number of wells per pad and P_detect may be due to greater complexity and potential emission sources at multiwell pads. The negative effect of well pad age, the parameter with the strongest predictive power, is likely related to the inverse relationship between well age and oil and gas production, although all parameters remain significant in multiparameter GLMs. Pads with a well in its first two months of production had over five times the frequency of detected emissions than older pads (p < 0.001). Due to the steep decline in production rates of unconventional wells with age, equipment and control devices may be undersized for handling this period of maximum production. Although older sites would be expected to have a greater likelihood of malfunctions caused by equipment wear, young sites may have initial issues caused by poor setup that have yet to be detected and repaired.

Similar statistical analyses were performed for basin-specific operator characteristics; there were several statistically significant but weak correlations between P_detect and these parameters (Table 2) with the strongest positive and negative correlations for an operator’s regional percent energy from oil (r = 0.17) and regional well count (r = −0.11). Binomial GLMs predicting P_detect from operator parameters are described in the Supporting Information. Relationships between the number of detected emissions by source type and well pad or operator characteristics were also evaluated (Table 2). For tank vents and hatches, the number of detected sources at a pad was most strongly correlated with oil production (r = 0.24 and 0.19). For nontank sources, correlations were weaker (r = −0.06 to 0.06). Poisson GLMs predicting the number of detected sources by type from pad parameters are described in the Supporting Information.

Potential Causes of Observed Emissions

High-emitting sources detected by the survey team may have been caused by both malfunctions and normal operations. For nontank sources, IR videos provide evidence that most sources were the result of malfunctions or intentional releases. There were 14 observations of malfunctioning flares that were unlit or operating with poor combustion efficiency. Emissions were detected from the pressure relief valves of four separators; although these pressure relief valves may have been functioning properly for safety purposes, the overpressurization that triggered their release indicates abnormal operations. Eight emission sources were observed from vents associated with trucks unloading oil from tanks, which may be intentional to relieve pressure of gas that is released as oil is pumped into trucks. Fifteen dehydrators were observed to have HC emissions, primarily from still vents that remove water vapor from the water-saturated glycol solution. On the basis of pad gas production and HC emission factors, no more than three of these dehydrators would be expected to have still vent emissions close to the 1 g s^–1 detection limit. (30) Therefore, most observed emissions from dehydrators were likely the result of abnormal operations that allowed excess HC to slip through the vent. In addition to the IR videos of individual sources, the very weak fit between observed and predicted emissions suggests that nontank emission sources are strongly driven by stochastic processes such as malfunctions.

Attributing tank vent and hatch emissions to malfunctions or normal operations is more difficult due to the many potential causes of tank emissions. As part of normal operations, uncontrolled tanks emit HCs from working, breathing, and flashing losses. Tank working and breathing losses generally are expected to be less than 1 g HC s^–1, but emissions in excess of this rate can occur from tank flashing after a separator dumps liquids into a tank. (13, 31) As discussed below, the emission rate and frequency of tank flashing emissions can be predicted on the basis of parameters including oil production.

Another routine cause of tank emissions is when wells are vented to unload liquids accumulated in the wellbore, which also releases gas. Emissions from well unloadings can be very large; the average emission rate of over 100 measured unloading events was 111 g CH₄ s^–1. (32) U.S. EPA Greenhouse Gas Reporting Program (GHGRP) data were used to estimate the percentage of wells expected to be venting at any one time in surveyed basins. (33) Assuming the duration of unloading events was 1 h, 0.24% and 0.15% of wells in the Fayetteville (Arkoma) and Uintah basins would have been venting due to liquids unloading at any one time, respectively; all other surveyed basins are predicted to have had less than 0.1% of wells venting from unloading. Therefore, liquids unloading events likely could be detected by the helicopter survey but only can explain a small fraction of observed tank sources.

Finally, abnormal emissions can occur if a separator dump valve fails to properly close and allows produced gas to flow through the tank instead of the sales line. These sources can have very large emission rates, theoretically up to a well’s entire gas production if the valve is stuck fully open. In 2014, operators reported over 7000 malfunctioning dump valves to the U.S. EPA GHGRP. (33) On the basis of the reported number of hydrocarbon tanks, approximately 5% of GHGRP tanks was associated with stuck dump valves. Operators do not report the duration of stuck dump valves, but a median duration of 7 days can be back calculated from other GHGRP data. Consequently, less than 0.1% of tanks are expected to have emissions from stuck dump valves at any one time.

Influence of Flashing Emissions by Basin

To determine if flashing could account for the observed P_detect of tank emission sources, potential HC emissions from tank flashing were estimated for surveyed well pads. Flash emission rates per unit of liquids production vary by parameters such as separator pressure and API gravity (a measure of HC liquid density). Since these values were not known for individual sites, basin-level data were obtained from the U.S. EPA O&G Emission Estimation Tool 2014 version 1, which includes a compilation of best available data from several sources including state regulatory agencies. (34) The tool provides separate emission factors for produced water, condensate, and crude oil (Table S11). For hydrocarbon liquids, a weighted average emission factor was derived from basin-level oil and condensate production. If tanks at a well pad are manifolded together with a common vent, then flash emissions will occur when any well’s separator dumps to the tank battery. Therefore, site-level production was used as a conservatively high estimate of flashing emissions. The temporal variability of flash emissions depends on the frequency and duration of separator dumps and duration of subsequent flash gas venting. Brantley et al. reported that a tank at a Denver-Julesburg well pad producing 29 bbl d^–1 condensate flashed ten times in 20 min; the duration of flash events in the study ranged from 30 to 120 s. (31) This indicates that, although individual flash events are short-lived, some sites may have near continuous tank flashing emissions due to frequent venting from separator dumps. To estimate the percentage of sites expected to have flash emissions ≥1 g HC s^–1 detection limit at any one time, the frequency and emission rate of flash emissions were calculated using two sets of assumptions: continuous emissions at a constant rate or intermittent emissions at the detection limit. Both these estimates use the same daily average emission rate but serve as lower and upper bounds for the fraction of sites with concurrent emissions at or above the detection limit. The effects of these assumptions were tested with a sensitivity analysis including alternative emission factors and a 3 g HC s^–1 detection limit (Tables S12–S15). In all basins, the range of predicted frequencies of sites with uncontrolled tank flashing emissions ≥1 g HC s^–1 included or exceeded observed frequencies (Figure 2; Fayetteville was excluded due to lack of reported liquids production). This indicates that tank flashing could explain observed emissions in the absence of tank emission control devices.

Figure 2. Comparison of the observed and predicted frequencies of well pads with detected tank hydrocarbon emissions assuming an observation threshold of 1 g s^–1 and basin-level data from the EPA O&G Estimation Tool. Two sets of predicted estimates are provided: red bars reflect predicted frequencies based on potential emissions without controls; green bars reflect the application of controls to the highest emitting tanks (see text for details). Predicted frequencies are shown as a range reflecting different temporal profiles of tank flashing emissions. For several basins and strata, observed frequencies are lower than frequencies predicted without controls but higher than predicted with controls. For example, the combined Uintah observation of 5.8% is within the range predicted for potential emissions but greater than the maximum of 1.5% predicted if all tank control systems were functioning effectively.

There are several state and federal regulations that require some oil and condensate storage tanks to control VOC emissions, including in North Dakota, Pennsylvania, Utah, and Wyoming. (35, 36) For example, during the time of the survey, U.S. EPA New Source Performance Standard Subpart OOOO required all tanks that began construction after April 12, 2013 and had a potential to emit ≥6 tons per year VOC to install control devices with at least 95% control effectiveness within 60 days of initial production. (37) Tank emission control devices include flares, combustors (enclosed flares), and vapor recovery units. The improper design, construction, or maintenance of tank control devices can reduce the capture or control efficiency of tank control devices. (38) Combustion devices can fail to ignite or have poor combustion efficiency, which causes HC emissions from the combustor stack. Emissions may not be fully captured if control systems are undersized or if condensed liquids in vent lines restrict the flow of gas, which can lead to tank overpressurization that triggers the release of gas from a pressure relief valve or tank hatch. Additionally, tank hatches that are left open accidentally or improperly sealed can allow some portion of vented flash gas to circumvent control devices. To determine if the frequency of observed tank emissions indicates failure of tank control systems, we estimated the percentage of sites expected to be equipped with tank controls by applying basin-level control data from the U.S. EPA O&G Emission Estimation Tool (Table S11). (34) For every surveyed well pad, potential emissions from oil, condensate, and water flashing were estimated with basin-level emission factors. Well pads were ranked by potential emissions, and then, controls were assumed to be equipped at a fraction of sites equal to the percentage of tanks with flares reported in the tool (28–86%). Emissions were assumed to be controlled at the reported basin-level capture efficiency (100%) and control efficiency (91–98%). (34) If these assumptions were true, then no emissions should be observed from hatches or vents of controlled tanks since all emissions are captured by the control device, but emissions could be observed exiting control devices if uncombusted HC in flare exhaust exceeds the detection limit.

In the Barnett, Powder River, Marcellus, and Uintah Basins, the observed frequency of well pads with detected tank emissions exceeded the maximum predicted frequency based on controlled tank flashing emissions, while in the Bakken the observed frequency was lower than expected (Figure 2). U.S. EPA recently issued a compliance alert that reports inspectors frequently observe emissions from tank hatches and pressure relief valves. (38) After an inspection of almost a hundred tanks in Colorado found numerous instances of ineffective control systems caused by design issues such as undersized control devices, an O&G operator entered a consent decree with U.S. EPA and the State of Colorado to evaluate and improve their control systems. (39) In the Bakken and Barnett, we inspected Google Earth imagery to assess the presence of tank control devices at well pads with observed tank emissions; 86% and 56% of well pads with extant imagery, respectively, had apparent control devices. This study’s observation that tank hatches and vents were the origin of the majority of detected large emission sources, even at controlled sites, suggests that the U.S. EPA O&G Emission Estimation Tool’s assumption of 100% capture efficiency is inaccurate and incomplete capture of emissions by tank control systems is a widespread issue.

Policy Implications

There are several strategies for reducing emissions from tanks, such as installing vapor recovery towers or stabilizers to reduce the vapor pressure of liquids entering tanks, properly sizing control equipment, and maintaining pressure relief valves and tank hatches to prevent leaks. Since this study found a higher frequency of detected emissions at sites within the first few months of production, controlling tank emissions as soon as a site enters production could reduce overall emissions. U.S. EPA New Source Performance Standard Subpart OOOO allows the installation of control devices to be delayed up to 60 days after startup, despite this being a period of maximum production, especially for unconventional wells characterized by rapid production decline. (37) The use of properly sized control devices as soon as production is initiated would address a substantial source of emissions. For example, the average Bakken site produces oil about twice the rate in the first two months as it does during the rest of the first year of production. (24) Given the evidence reported in this study that the frequency of observed tank emissions is greater than what would be expected if control systems were functioning effectively, it is clear that identifying anomalous emissions through regular or continuous monitoring of hydrocarbon emissions and/or equipment status, such as leak detection and repair programs, would be an effective strategy to reduce emissions.

Currently, U.S. EPA estimates total annual emissions from all oil and gas production sources of 3.1 Tg VOC and 2.9 Tg CH₄ with 0.6 Tg CH₄ yr^–1 attributed to oil and condensate tanks. (40, 41) The qualitative nature of the IR survey data precludes an accurate estimate of hydrocarbon or methane emissions, but with knowledge of the detection limit of the technology deployed, our observations can be used to estimate a lower bound for tank emissions. Our observation of more than 450 detected tank sources with emission rates ≥1 g HC s^–1 represent at least 450 g HC s^–1 (a more likely estimate is ∼1575 g HC s^–1 based on the median aircraft quantified well pad emission rate of 3.5 g CH₄ s^–1). While these emissions likely include both intermittent and continuous sources, the assumption of a relatively constant emission rate across a large number of sites is robust and yields an emission rate of at least 14.2 Gg HC yr^–1. Since our observations were limited to summer/fall and daylight hours, we were not able to assess how annual average prevalence may be affected by seasonal or diurnal trends such as higher tank breathing losses during warmer conditions. The 8220 surveyed well pads include 1.1%, 3.7%, and 4.5% of U.S. active wells, gas production, and oil production, respectively. There is uncertainty in scaling up emissions from our sample given that the representativeness of surveyed wells to the U.S. national population of O&G wells has not been assessed and there are only weak correlations between the prevalence of high emissions and these parameters. However, scaling up by the best fit parameter, oil production, yields a minimum national HC emission rate of 0.32 Tg yr^–1 from high emission tank sources. This national emission estimate of tank emissions represents a lower bound for high-emitting tanks and excludes common, lower emission rate sources such as tank working and breathing losses. This study provides evidence that the cause of some observed emissions is anomalous conditions rather than routine, intermittent tank flashing. U.S. EPA may be underestimating emissions from O&G tanks by overestimating control effectiveness and failing to comprehensively include abnormal, high emission sources. It is reasonable to assume that tanks are a major contributor to the gap between top-down and bottom-up estimates of O&G CH₄ emissions reported by several studies, as well as to the fat-tail emissions observed in a previous study of the Barnett that closed the gap. (11)

Even though this study found statistically significant correlations between the presence of detected emissions and several well pad and operator parameters, these relationships were weak and GLM models were able to explain less than 15% of the variance. This low degree of predictability indicates that these large emission sources are primarily stochastic and the frequent and widespread inspection of sites to identify and repair high emission sources is critical to reducing emissions. In addition to helicopter-based IR surveys, continuous site-based and mobile leak detection systems may be valuable for quickly identifying these large sources. (13, 14, 42-44) Tank vents and hatches account for the vast majority of high emission sources detected at well pads across the U.S. Although routine tank flashing may be responsible for some of these emission sources, there is evidence that substantial emissions are caused by abnormal conditions such as ineffective tank control systems. Installing tank control devices on existing sources combined with maintenance and monitoring to ensure control systems are operating effectively would be an important step for reducing emissions of methane and VOCs. Tanks and other high emission sources are an important contributor to total hydrocarbon emissions from oil and gas well pads and offer a promising opportunity to reduce emissions, but further reductions targeting the numerous emission sources that are individually smaller but collectively large will also be necessary to minimize the health and climate impacts of oil and gas production.

Supporting Information

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The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.est.6b00705.

8 infrared videos and description of observed sources (ZIP)
Supporting text, 17 tables, and 2 figures (PDF)
Calculations used in tank flashing analysis (XLSX)
Site-level parameter data for well pads in the surveyed areas and basins (XLSX)
List of surveyed sites by latitude/longitude (XLSX)

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Most electronic Supporting Information files are available without a subscription to ACS Web Editions. Such files may be downloaded by article for research use (if there is a public use license linked to the relevant article, that license may permit other uses). Permission may be obtained from ACS for other uses through requests via the RightsLink permission system: http://pubs.acs.org/page/copyright/permissions.html.

Author Information

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Corresponding Author
- David R. Lyon - Environmental Defense Fund, 301 Congress Avenue, Suite 1300, Austin, Texas 78701, United States; Environmental Dynamics Program, University of Arkansas, Fayetteville, Arkansas 72701, United States; Email: [email protected]
Authors
- Ramón A. Alvarez - Environmental Defense Fund, 301 Congress Avenue, Suite 1300, Austin, Texas 78701, United States
- Daniel Zavala-Araiza - Environmental Defense Fund, 301 Congress Avenue, Suite 1300, Austin, Texas 78701, United States
- Adam R. Brandt - Department of Energy Resources Engineering, Stanford University, Stanford, California 94305, United States
- Robert B. Jackson - Department of Earth System Science, Woods Institute for the Environment, and Precourt Institute for Energy, Stanford University, Stanford, California 94305, United States
- Steven P. Hamburg - Environmental Defense Fund, 301 Congress Avenue, Suite 1300, Austin, Texas 78701, United States
Notes
The authors declare no competing financial interest.

Acknowledgment

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Funding for the Environmental Defense Fund’s methane research series, including this work, was provided by Alfred P. Sloan Foundation, Fiona and Stan Druckenmiller, Heising-Simons Foundation, Bill and Susan Oberndorf, Betsy and Sam Reeves, Robertson Foundation, TomKat Charitable Trust, and the Walton Family Foundation. We thank Leak Surveys, Inc., Bud McCorkle, Lisa Cantrell, Michael Mayfield, Korey Morris, C.R. Thompson, Steve Conley, and Ian Faloona for collecting data. We appreciate Tegan Lavoie, Hillary Hull, and Bob Harriss for providing comments. Elizabeth Paranhos, Jennifer Snyder, Cindy Beeler, and Jacob Englander provided helpful information on tank regulations and emissions. We thank Kelsey Robinson for editing the TOC graphic based on an infrared video taken by David Lyon.

References

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Proceedings of the National Academy of Sciences of the United States of America (2015), 112 (51), 15597-15602CODEN: PNASA6; ISSN:0027-8424. (National Academy of Sciences)
Published ests. of methane emissions from atm. 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 ests. 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 ests. by using repeated mass balance measurements, as well as ethane as a fingerprint for source attribution. Similarly, our bottom-up est. incorporates a more complete count of facilities than past inventories, which omitted a significant no. 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 ests. based on the US Environmental Protection Agency's Greenhouse Gas Inventory and correspond to 1.5% of natural gas prodn. This rate of methane loss increases the 20-y climate impacts of natural gas consumed in the region by roughly 50%.
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Lyon, D. R.; Zavala-Araiza, D.; Alvarez, R. A.; Harriss, R.; Palacios, V.; Lan, X.; Talbot, R.; Lavoie, T.; Shepson, P.; Yacovitch, T. I. Constructing a Spatially Resolved Methane Emission Inventory for the Barnett Shale Region Environ. Sci. Technol. 2015, 49 (13) 8147– 8157 DOI: 10.1021/es506359c
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Constructing a Spatially Resolved Methane Emission Inventory for the Barnett Shale Region
Lyon, David R.; Zavala-Araiza, Daniel; Alvarez, Ramon A.; Harriss, Robert; Palacios, Virginia; Lan, Xin; Talbot, Robert; Lavoie, Tegan; Shepson, Paul; Yacovitch, Tara I.; Herndon, Scott C.; Marchese, Anthony J.; Zimmerle, Daniel; Robinson, Allen L.; Hamburg, Steven P.
Environmental Science & Technology (2015), 49 (13), 8147-8157CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
CH4 emissions from the oil and gas industry (O&G) and other sources in the Barnett Shale region (Texas) were estd. by developing a spatially resolved emission inventory. In total, 18 source categories were estd. using multiple datasets, including empirical measurements at regional O&G sites and a national study of collecting/processing facilities. Spatially referenced activity data were compiled from federal and state databases and combined with O&G facility emission factors calcd. by Monte Carlo simulations which accounted for high emission sites representing the very upper portion, or fat-tail, of obsd. emissions distributions. Total CH4 emissions in the 25-county Barnett Shale region in Oct. 2013 were estd. to be 72,300 (63,400-82,400) kg CH4/h. O&G emissions were estd. to be 46,200 (40,000-54,100) kg CH4/h; 19% of emissions from fat-tail sites represented <2% of sites. Estd. O&G emissions in the Barnett Shale region were higher than alternative inventories based on the USEPA Greenhouse Gas Inventory, EPA Greenhouse Gas Reporting Program, and Emissions Database for Global Atm. Research by factors of 1.5, 2.7, and 4.3, resp. Collecting compressor sites, accounting for 40% of O&G emissions in this inventory, had the largest difference from emission ests. based on EPA data sources. This inventory higher O&G emissions est. was due primarily to its more comprehensive activity factors and inclusion of fat-tail sites.
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Brantley, H. L.; Thoma, E. D.; Squier, W. C.; Guven, B. B.; Lyon, D. Assessment of Methane Emissions from Oil and Gas Production Pads using Mobile Measurements Environ. Sci. Technol. 2014, 48 (24) 14508– 14515 DOI: 10.1021/es503070q
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Assessment of methane emissions from oil and gas production pads using mobile measurements
Brantley, Halley L.; Thoma, Eben D.; Squier, William C.; Guven, Birnur B.; Lyon, David
Environmental Science & Technology (2014), 48 (24), 14508-14515CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
A new mobile methane emissions inspection approach, Other Test Method (OTM) 33A, was used to quantify short-term emission rates from 210 oil and gas prodn. pads during eight two-week field studies in Texas, Colorado, and Wyoming from 2010 to 2013. Emission rates were log-normally distributed with geometric means and 95% confidence intervals (CIs) of 0.33 (0.23, 0.48), 0.14 (0.11, 0.19), and 0.59 (0.47, 0.74) g/s in the Barnett, Denver-Julesburg, and Pinedale basins, resp. This study focused on sites with emission rates above 0.01 g/s and included short-term (i.e., condensate tank flashing) and maintenance-related emissions. The results fell within the upper ranges of the distributions obsd. in recent onsite direct measurement studies. Considering data across all basins, a multivariate linear regression was used to assess the relationship of methane emissions to well age, gas prodn., and hydrocarbon liqs. (oil or condensate) prodn. Methane emissions were pos. correlated with gas prodn., but only approx. 10% of the variation in emission rates was explained by variation in prodn. levels. The weak correlation between emission and prodn. rates may indicate that maintenance-related stochastic variables and design of prodn. and control equipment are factors detg. emissions.
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Rella, C. W.; Tsai, T. R.; Botkin, C. G.; Crosson, E. R.; Steele, D. Measuring Emissions from Oil and Natural Gas Well Pads Using the Mobile Flux Plane Technique Environ. Sci. Technol. 2015, 49 (7) 4742– 4748 DOI: 10.1021/acs.est.5b00099
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Mitchell, A. L.; Tkacik, D. S.; Roscioli, J. R.; Herndon, S. C.; Yacovitch, T. I.; Martinez, D. M.; Vaughn, T. L.; Williams, L. L.; Sullivan, M. R.; Floerchinger, C. Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results Environ. Sci. Technol. 2015, 49 (5) 3219– 3227 DOI: 10.1021/es5052809
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Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results
Mitchell, Austin L.; Tkacik, Daniel S.; Roscioli, Joseph R.; Herndon, Scott C.; Yacovitch, Tara I.; Martinez, David M.; Vaughn, Timothy L.; Williams, Laurie L.; Sullivan, Melissa R.; Floerchinger, Cody; Omara, Mark; Subramanian, R.; Zimmerle, Daniel; Marchese, Anthony J.; Robinson, Allen L.
Environmental Science & Technology (2015), 49 (5), 3219-3227CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
Facility-level methane emissions were measured at 114 gathering facilities and 16 processing plants in the United States natural gas system. At gathering facilities, the measured methane emission rates ranged from 0.7 to 700 kg per h (kg/h) (0.6 to 600 std. cfm (scfm)). Normalized emissions (as a % of total methane throughput) were less than 1% for 85 gathering facilities and 19 had normalized emissions less than 0.1%. The range of methane emissions rates for processing plants was 3 to 600 kg/h (3 to 524 scfm), corresponding to normalized methane emissions rates <1% in all cases. The distributions of methane emissions, particularly for gathering facilities, are skewed. For example, 30% of gathering facilities contribute 80% of the total emissions. Normalized emissions rates are neg. correlated with facility throughput. The variation in methane emissions also appears driven by differences between inlet and outlet pressure, as well as venting and leaking equipment. Substantial venting from liqs. storage tanks was obsd. at 20% of gathering facilities. Emissions rates at these facilities were, on av., around four times the rates obsd. at similar facilities without substantial venting.
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Subramanian, R.; Williams, L. L.; Vaughn, T. L.; Zimmerle, D.; Roscioli, J. R.; Herndon, S. C.; Yacovitch, T. I.; Floerchinger, C.; Tkacik, D. S.; Mitchell, A. L. Methane Emissions from Natural Gas Compressor Stations in the Transmission and Storage Sector: Measurements and Comparisons with the EPA Greenhouse Gas Reporting Program Protocol Environ. Sci. Technol. 2015, 49 (5) 3252– 3261 DOI: 10.1021/es5060258
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Methane Emissions from Natural Gas Compressor Stations in the Transmission and Storage Sector: Measurements and Comparisons with the EPA Greenhouse Gas Reporting Program Protocol
Subramanian, R.; Williams, Laurie L.; Vaughn, Timothy L.; Zimmerle, Daniel; Roscioli, Joseph R.; Herndon, Scott C.; Yacovitch, Tara I.; Floerchinger, Cody; Tkacik, Daniel S.; Mitchell, Austin L.; Sullivan, Melissa R.; Dallmann, Timothy R.; Robinson, Allen L.
Environmental Science & Technology (2015), 49 (5), 3252-3261CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
Equipment- and site-level methane emissions from 45 compressor stations in the transmission and storage (T&S) sector of the US natural gas system were measured, including 25 sites required to report under the EPA greenhouse gas reporting program (GHGRP). Direct measurements of fugitive and vented sources were combined with AP-42-based exhaust emission factors (for operating reciprocating engines and turbines) to produce a study onsite est. Site-level methane emissions were also concurrently measured with downwind-tracer-flux techniques. At most sites, these two independent ests. agreed within exptl. uncertainty. Site-level methane emissions varied from 2-880 SCFM. Compressor vents, leaky isolation valves, reciprocating engine exhaust, and equipment leaks were major sources, and substantial emissions were obsd. at both operating and standby compressor stations. The site-level methane emission rates were highly skewed; the highest emitting 10% of sites (including two superemitters) contributed 50% of the aggregate methane emissions, while the lowest emitting 50% of sites contributed less than 10% of the aggregate emissions. Excluding the two superemitters, study-av. methane emissions from compressor housings and noncompressor sources are comparable to or lower than the corresponding effective emission factors used in the EPA greenhouse gas inventory. If the two superemitters are included in the anal., then the av. emission factors based on this study could exceed the EPA greenhouse gas inventory emission factors, which highlights the potentially important contribution of superemitters to national emissions. However, quantification of their influence requires knowledge of the magnitude and frequency of superemitters across the entire T&S sector. Only 38% of the methane emissions measured by the comprehensive onsite measurements were reportable under the new EPA GHGRP because of a combination of inaccurate emission factors for leakers and exhaust methane, and various exclusions. The bias is even larger if one accounts for the superemitters, which were not captured by the onsite measurements. The magnitude of the bias varied from site to site by site type and operating state. Therefore, while the GHGRP is a valuable new source of emissions information, care must be taken when incorporating these data into emission inventories. The value of the GHGRP can be increased by requiring more direct measurements of emissions (as opposed to using counts and emission factors), eliminating exclusions such as rod-packing vents on pressurized reciprocating compressors in standby mode under Subpart-W, and using more appropriate emission factors for exhaust methane from reciprocating engines under Subpart-C.
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Lamb, B. K.; Edburg, S. L.; Ferrara, T. W.; Howard, T.; Harrison, M. R.; Kolb, C. E.; Townsend-Small, A.; Dyck, W.; Possolo, A.; Whetstone, J. R. Direct Measurements Show Decreasing Methane Emissions from Natural Gas Local Distribution Systems in the United States Environ. Sci. Technol. 2015, 49 (8) 5161– 5169 DOI: 10.1021/es505116p
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Direct Measurements Show Decreasing Methane Emissions from Natural Gas Local Distribution Systems in the United States
Lamb, Brian K.; Edburg, Steven L.; Ferrara, Thomas W.; Howard, Touche; Harrison, Matthew R.; Kolb, Charles E.; Townsend-Small, Amy; Dyck, Wesley; Possolo, Antonio; Whetstone, James R.
Environmental Science & Technology (2015), 49 (8), 5161-5169CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
Fugitive losses from natural gas distribution systems are a significant source of anthropogenic methane. Here, we report on a national sampling program to measure methane emissions from 13 urban distribution systems across the U. S. Emission factors were derived from direct measurements at 230 underground pipeline leaks and 229 metering and regulating facilities using stratified random sampling. When these new emission factors are combined with ests. for customer meters, maintenance, and upsets, and current pipeline miles and nos. of facilities, the total est. is 393 Gg/yr with a 95% upper confidence limit of 854 Gg/yr (0.10% to 0.22% of the methane delivered nationwide). This fraction includes emissions from city gates to the customer meter, but does not include other urban sources or those downstream of customer meters. The upper confidence limit accounts for the skewed distribution of measurements, where a few large emitters accounted for most of the emissions. This emission est. is 36% to 70% less than the 2011 EPA inventory, (based largely on 1990s emission data), and reflects significant upgrades at metering and regulating stations, improvements in leak detection and maintenance activities, as well as potential effects from differences in methodologies between the two studies.
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Zavala-Araiza, D.; Lyon, D.; Alvarez, R. A.; Palacios, V.; Harriss, R.; Lan, X.; Talbot, R.; Hamburg, S. P. Toward a Functional Definition of Methane Super-Emitters: Application to Natural Gas Production Sites Environ. Sci. Technol. 2015, 49 (13) 8167– 8174 DOI: 10.1021/acs.est.5b00133
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Toward a Functional Definition of Methane Super-Emitters: Application to Natural Gas Production Sites
Zavala-Araiza, Daniel; Lyon, David; Alvarez, Ramon A.; Palacios, Virginia; Harriss, Robert; Lan, Xin; Talbot, Robert; Hamburg, Steven P.
Environmental Science & Technology (2015), 49 (13), 8167-8174CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
Natural gas prodn. site emissions 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. This work designed a conceptual framework to functionally define super-emitting sites as those with the highest proportional loss rates (Ch4 emitted vs. CH4 produced). Using this concept, total CH4 emissions from Barnett Shale natural gas prodn. sites (Texas) were estd.; super-emitting sites functionally accounted for approx. 3/4 of total emissions. The potential to reduce emissions from these sites is discussed under the assumption that sites with high proportional loss rates have excess emissions resulting from abnormal or otherwise avoidable operating conditions, e.g., malfunctioning equipment. Since the population of functionally super-emitting sites is not expected to be static over time, continuous monitoring will be necessary to identify them and improve their operation. This work suggested that achieving and maintaining uniformly low emissions across the entire population of prodn. sites will require mitigation steps at a large fraction of sites.
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Jackson, R. B.; Vengosh, A.; Carey, J. W.; Davies, R. J.; Darrah, T. H.; O’Sullivan, F.; Pétron, G. The Environmental Costs and Benefits of Fracking Annu. Rev. Environ. Resour. 2014, 39 (1) 327– 362 DOI: 10.1146/annurev-environ-031113-144051
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Proposed Rule: Oil and Natural Gas Sector: Emission Standards for New and Modified Sources; Sep 18, 2015. Available from: https://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-21023.pdf.
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Benson, R.; Madding, R.; Lucier, R.; Lyons, J.; Czerepuszko, P. Standoff passive optical leak detection of volatile organic compounds using a cooled InSb based infrared imager. AWMA 99th Annual Meeting Papers, 2006; Vol. 131.
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Robinson, D. R.; Luke-Boone, R.; Aggarwal, V.; Harris, B.; Anderson, E.; Ranum, D.; Kulp, T. J.; Armstrong, K.; Sommers, R.; McRae, T. G. Refinery evaluation of optical imaging to locate fugitive emissions J. Air Waste Manage. Assoc. 2007, 57 (7) 803– 810 DOI: 10.3155/1047-3289.57.7.803
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Refinery evaluation of optical imaging to locate fugitive emissions
Robinson, Donald R.; Luke-Boone, Ronke; Aggarwal, Vineet; Harris, Buzz; Anderson, Eric; Ranum, David; Kulp, Thomas J.; Armstrong, Karla; Sommers, Ricky; McRae, Thomas G.; Ritter, Karin; Siegell, Jeffrey H.; Van Pelt, Doug; Smylie, Mike
Journal of the Air & Waste Management Association (2007), 57 (7), 803-810CODEN: JAWAFC; ISSN:1096-2247. (Air & Waste Management Association)
Fugitive emissions account for approx. 50% of total hydrocarbon emissions from process plants. Federal and state regulations aiming at controlling these emissions require refineries and petrochem. plants in the United States to implement a Leak Detection and Repair Program (LDAR). The current regulatory work practice, U.S. Environment Protection Agency Method 21, requires designated components to be monitored individually at regular intervals. The annual costs of these LDAR programs in a typical refinery can exceed US$1,000,000. Previous studies have shown that a majority of controllable fugitive emissions come from a very small fraction of components. The Smart LDAR program aims to find cost-effective methods to monitor and reduce emissions from these large leakers. Optical gas imaging has been identified as one such technol. that can help achieve this objective. This paper discusses a refinery evaluation of an instrument based on backscatter absorption gas imaging technol. This portable camera allows an operator to scan components more quickly and image gas leaks in real time. During the evaluation, the instrument was able to identify leaking components that were the source of 97% of the total mass emissions from leaks detected. More than 27,000 components were monitored. This was achieved in far less time than it would have taken using Method 21. In addn., the instrument was able to find leaks from components that are not required to be monitored by the current LDAR regulations. The technol. principles and the parameters that affect instrument performance are also discussed in the paper.
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Biennial Report to the 84th Legislature, Chapter 1: Agency Highlights, FY2013–2014; Texas Commision on Environmental Quality: Austin, TX, 2015. Available from: http://www.tceq.state.tx.us/publications/sfr/index84/chapter1.
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Drillinginfo. DI Desktop; Drillinginfo: Austin, TX; 2015. Available from: http://www.didesktop.com/.
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Leak Surveys, Inc. Available from: http://www.leaksurveysinc.com/.
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Monthly Energy Review; United States Energy Information Administration: Washington, DC; 2015, Sep. Available from: http://www.eia.gov/totalenergy/data/monthly/archive/00351509.pdf.
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Allen, D. T.; Pacsi, A. P.; Sullivan, D. W.; Zavala-Araiza, D.; Harrison, M.; Keen, K.; Fraser, M. P.; Daniel Hill, A.; Sawyer, R. F.; Seinfeld, J. H. Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers Environ. Sci. Technol. 2015, 49 (1) 633– 640 DOI: 10.1021/es5040156
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Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers
Allen, David T.; Pacsi, Adam P.; Sullivan, David W.; Zavala-Araiza, Daniel; Harrison, Matthew; Keen, Kindal; Fraser, Matthew P.; Daniel Hill, A.; Sawyer, Robert F.; Seinfeld, John H.
Environmental Science & Technology (2015), 49 (1), 633-640CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
Pollutant emissions from 377 gas-actuated (pneumatic) controllers were measured at natural gas prodn. sites and several oil prodn. sites throughout the US. A small subset of devices (19%), with whole gas emission rates >6 std. ft3/h (scf/h) accounted for 95% of emissions. More than half the controllers recorded emissions of ≤0.001 scf/h during a 15-min measurement. Pneumatic controllers in level control applications on separators and in compressor applications had higher emission rates than controllers in other types of applications. Regional emission differences were obsd.; lowest emissions were measured in the Rocky Mountains, highest emissions were measured at the Gulf Coast. Av. reported CH4 emissions/controller were 17% higher than av. emissions/controller in the 2012 USEPA greenhouse gas national emission inventory (2012 GHG NEI, released in 2014). The av. of 2.7 controllers/well obsd. in this work was higher than the 1.0 controllers/well reported in the 2012 GHG NEI.
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Allen, D. T.; Torres, V. M.; Thomas, J.; Sullivan, D. W.; Harrison, M.; Hendler, A.; Herndon, S. C.; Kolb, C. E.; Fraser, M. P.; Hill, A. D. Measurements of methane emissions at natural gas production sites in the United States Proc. Natl. Acad. Sci. U. S. A. 2013, 110 (44) 17768– 73 DOI: 10.1073/pnas.1304880110
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Measurements of methane emissions at natural gas production sites in the United States
Allen, David T.; Torres, Vincent M.; Thomas, James; Sullivan, David W.; Harrison, Matthew; Hendler, Al; Herndon, Scott C.; Kolb, Charles E.; Fraser, Matthew P.; Hill, A. Daniel; Lamb, Brian K.; Miskimins, Jennifer; Sawyer, Robert F.; Seinfeld, John H.
Proceedings of the National Academy of Sciences of the United States of America (2013), 110 (44), 17768-17773,S17768/1-S17768/77CODEN: PNASA6; ISSN:0027-8424. (National Academy of Sciences)
Engineering ests. of CH4 emissions from natural gas prodn. led to varied projections of national emissions. This work reports direct measurements of CH4 emissions at 190 on-shore natural gas sites in the US (150 prodn. sites, 27 well completion flow-backs, 9 well unloadings, 4 work-overs). For well completion flow-backs, which clear fractured wells of liq. to allow gas prodn., CH4 emissions were 0.01-17 Mg (mean, 1.7 Mg; 95% confidence interval bounds, 0.67-3.3 Mg) vs. an av. of 81 Mg/event in the 2011 USEPA national emission inventory (Apr. 2013). Emission factors for pneumatic pumps/controllers and equipment leaks were comparable to and higher than national inventory ests. If emission factors from this work for completion flow-backs, equipment leaks, and pneumatic pumps/controllers were assumed to be representative of national populations and were used to est. national emissions, total annual emissions from these source categories were calcd. to be 957 Gg CH4 (with sampling and measurement uncertainties estd. at ±200 Gg). The est. for comparable source categories in the USEPA national inventory is ∼1200 Gg. Addnl. measurements of unloadings and work-overs are needed to produce national emission ests. for these source categories. The 957 Gg emissions for completion flow-backs, pneumatics, and equipment leaks, in conjunction with USEPA national inventory ests. for other categories, led to an estd. 2300 Gg CH4 emissions from natural gas prodn. (0.42% of gross gas prodn.).
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Omara, M.; Sullivan, M. R.; Li, X.; Subramanian, R.; Robinson, A. L.; Presto, A. A. Methane Emissions from Conventional and Unconventional Natural Gas Production Sites in the Marcellus Shale Basin Environ. Sci. Technol. 2016, 50 (4) 2099– 2107 DOI: 10.1021/acs.est.5b05503
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Methane Emissions from Conventional and Unconventional Natural Gas Production Sites in the Marcellus Shale Basin
Omara, Mark; Sullivan, Melissa R.; Li, Xiang; Subramanian, R.; Robinson, Allen L.; Presto, Albert A.
Environmental Science & Technology (2016), 50 (4), 2099-2107CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
There is a need to continually assess CH4 emissions assocd. with natural gas (NG) prodn., particularly since recent advancements in horizontal drilling in conjunction with staged hydraulic fracturing technologies dramatically increased NG prodn. (i.e., unconventional NG wells). This work measured facility-level CH4 emissions rates from the NG prodn. sector in the Marcellus region, comparing CH4 emissions between unconventional NG (UNG) well pad sites and relatively smaller, older conventional NG (CvNG) sites consisting of wells drilled vertically into permeable geol. formations. A top-down tracer-flux CH4 measurement approach using mobile downwind intercepts of CH4, ethane, and tracer (N2O and acetylene) plumes was performed at 18 CvNG sites (19 individual wells) and 17 UNG sites (88 individual wells). The 17 UNG sites included 4 sites undergoing completion flow-back (FB). The mean facility-level CH4 emission rate among UNG well pad sites in routine prodn. (18.8 kg/h [95% confidence interval (CI) with a mean 12.0-26.8 kg/h]) was 23 times greater than mean CH4 emissions from CvNG sites. These differences were attributed, in part, to the large size (i.e., no. of wells and ancillary NG prodn. equipment) and the significantly higher prodn. rate of UNG sites. However, CvNG sites generally had much higher prodn.-normalized CH4 emission rates (median: 11%; range: 0.35-91%) vs. UNG sites (median: 0.13%, range: 0.01-1.2%), likely due to a greater prevalence of avoidable process operating conditions (e.g., unresolved equipment maintenance issues). At a regional scale, it was estd. that total annual CH4 emissions from 88,500 combined CvNG well pads in Pennsylvania and West Virginia (660 Gg [95% CI: 500-800 Gg]) exceeded that from 3390 UNG well pads by 170 Gg, reflecting the large no. of CvNG wells and the comparably large fraction of CH4 lost/unit prodn. These new emissions data suggested recently instituted Pennsylvania CH4 emissions inventory substantially underestimated measured facility-level CH4 emissions by >10-40 times for 4 UNG sites in this study.
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Methane Emissions from the Natural Gas Industry. Volume 14: Glycol Dehydrators; Gas Research Institute/United States Environmental Protection Agency: Washington, DC, 1996, Jun. Available from: http://www3.epa.gov/gasstar/documents/emissions_report/14_glycol.pdf.
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Brantley, H. L.; Thoma, E. D.; Eisele, A. P. Assessment of volatile organic compound and hazardous air pollutant emissions from oil and natural gas well pads using mobile remote and on-site direct measurements J. Air Waste Manage. Assoc. 2015, 65 (9) 1072– 1082 DOI: 10.1080/10962247.2015.1056888
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Assessment of volatile organic compound and hazardous air pollutant emissions from oil and natural gas well pads using mobile remote and on-site direct measurements
Brantley, Halley L.; Thoma, Eben D.; Eisele, Adam P.
Journal of the Air & Waste Management Association (2015), 65 (9), 1072-1082CODEN: JAWAFC; ISSN:1096-2247. (Taylor & Francis Ltd.)
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Environmental Science & Technology

Cite this: Environ. Sci. Technol. 2016, 50, 9, 4877–4886

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Published April 5, 2016

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Abstract
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Figure 1
Figure 1. Percentage of well pads with detected emissions by deciles of well pad parameters: (a) well count (wells per pad), (b) well age (months since initial production of newest well), (c) gas production (Mcf/day), (d) oil production (bbl/day), (e) water production (bbl/day), and (f) % energy from oil. The median values of each decile are displayed on the x-axes.
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Figure 2
Figure 2. Comparison of the observed and predicted frequencies of well pads with detected tank hydrocarbon emissions assuming an observation threshold of 1 g s^–1 and basin-level data from the EPA O&G Estimation Tool. Two sets of predicted estimates are provided: red bars reflect predicted frequencies based on potential emissions without controls; green bars reflect the application of controls to the highest emitting tanks (see text for details). Predicted frequencies are shown as a range reflecting different temporal profiles of tank flashing emissions. For several basins and strata, observed frequencies are lower than frequencies predicted without controls but higher than predicted with controls. For example, the combined Uintah observation of 5.8% is within the range predicted for potential emissions but greater than the maximum of 1.5% predicted if all tank control systems were functioning effectively.
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References
This article references 44 other publications.
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  https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BC2cXjvVOiuro%253D&md5=919ddc43ceb2719af54e1d6c4217c995
9. 9
  Miller, S. M.; Wofsy, S. C.; Michalak, A. M.; Kort, E. A.; Andrews, A. E.; Biraud, S. C.; Dlugokencky, E. J.; Eluszkiewicz, J.; Fischer, M. L.; Janssens-Maenhout, G. Anthropogenic emissions of methane in the United States Proc. Natl. Acad. Sci. U. S. A. 2013, 110 (50) 20018– 20022 DOI: 10.1073/pnas.1314392110
  9
  Anthropogenic emissions of methane in the United States
  Miller, Scot M.; Wofsy, Steven C.; Michalak, Anna M.; Kort, Eric A.; Andrews, Arlyn E.; Biraud, Sebastien C.; Dlugokencky, Edward J.; Eluszkiewicz, Janusz; Fischer, Marc L.; Janssens-Maenhout, Greet; Miller, Ben R.; Miller, John B.; Montzka, Stephen A.; Nehrkorn, Thomas; Sweeney, Colm
  Proceedings of the National Academy of Sciences of the United States of America (2013), 110 (50), 20018-20022,S20018/1-S20018/11CODEN: PNASA6; ISSN:0027-8424. (National Academy of Sciences)
  This work quant. estd. the spatial distribution of anthropogenic CH4 sources in the US by combining comprehensive atm. CH4 observations, extensive spatial datasets, and a high resoln. atm. transport model. Results showed current USEPA and Emissions Database for Global Atm. Research (EDGAR) inventories underestimated national CH4 emissions a factor of ∼1.5 and ∼1.7, resp. Results indicated emissions due to ruminants and manure are up to twice the magnitude of existing inventories. Discrepancies in CH4 source ests. are particularly pronounced in the south-central US where total emissions are ∼2.7 times greater than in most inventories and account for 24 ± 3% of national emissions. Spatial patterns of emission fluxes and obsd. CH4/C3H8 correlations indicated fossil fuel extn. and refining are major contributors (45 ± 13%) in the south-central US. This suggested regional CH4 emissions due to fossil fuel extn. and processing could be 4.9 ± 2.6 times larger than in EDGAR, the most comprehensive global CH4 inventory. Results cast doubt on a recent USEPA decision to down-scale its est. of national natural gas emissions by 25-30%. It was concluded that CH4 emissions assocd. with animal husbandry and fossil fuel industries have larger greenhouse gas impacts than indicated by existing inventories.
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10. 10
  Harriss, R.; Alvarez, R. A.; Lyon, D.; Zavala-Araiza, D.; Nelson, D.; Hamburg, S. P. Using Multi-Scale Measurements to Improve Methane Emission Estimates from Oil and Gas Operations in the Barnett Shale Region, Texas Environ. Sci. Technol. 2015, 49 (13) 7524– 7526 DOI: 10.1021/acs.est.5b02305
  There is no corresponding record for this reference.
11. 11
  Zavala-Araiza, D.; Lyon, D. R.; Alvarez, R. A.; Davis, K. J.; Harriss, R.; Herndon, S. C.; Karion, A.; Kort, E. A.; Lamb, B. K.; Lan, X. Reconciling divergent estimates of oil and gas methane emissions Proc. Natl. Acad. Sci. U. S. A. 2015, 112 (51) 15597– 15602 DOI: 10.1073/pnas.1522126112
  11
  Reconciling divergent estimates of oil and gas methane emissions
  Zavala-Araiza, Daniel; Lyon, David R.; Alvarez, Ramon A.; Davis, Kenneth J.; Harriss, Robert; Herndon, Scott C.; Karion, Anna; Kort, Eric Adam; Lamb, Brian K.; Lan, Xin; Marchese, Anthony J.; Pacala, Stephen W.; Robinson, Allen L.; Shepson, Paul B.; Sweeney, Colm; Talbot, Robert; Townsend-Small, Amy; Yacovitch, Tara I.; Zimmerle, Daniel J.; Hamburg, Steven P.
  Proceedings of the National Academy of Sciences of the United States of America (2015), 112 (51), 15597-15602CODEN: PNASA6; ISSN:0027-8424. (National Academy of Sciences)
  Published ests. of methane emissions from atm. 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 ests. 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 ests. by using repeated mass balance measurements, as well as ethane as a fingerprint for source attribution. Similarly, our bottom-up est. incorporates a more complete count of facilities than past inventories, which omitted a significant no. 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 ests. based on the US Environmental Protection Agency's Greenhouse Gas Inventory and correspond to 1.5% of natural gas prodn. This rate of methane loss increases the 20-y climate impacts of natural gas consumed in the region by roughly 50%.
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12. 12
  Lyon, D. R.; Zavala-Araiza, D.; Alvarez, R. A.; Harriss, R.; Palacios, V.; Lan, X.; Talbot, R.; Lavoie, T.; Shepson, P.; Yacovitch, T. I. Constructing a Spatially Resolved Methane Emission Inventory for the Barnett Shale Region Environ. Sci. Technol. 2015, 49 (13) 8147– 8157 DOI: 10.1021/es506359c
  12
  Constructing a Spatially Resolved Methane Emission Inventory for the Barnett Shale Region
  Lyon, David R.; Zavala-Araiza, Daniel; Alvarez, Ramon A.; Harriss, Robert; Palacios, Virginia; Lan, Xin; Talbot, Robert; Lavoie, Tegan; Shepson, Paul; Yacovitch, Tara I.; Herndon, Scott C.; Marchese, Anthony J.; Zimmerle, Daniel; Robinson, Allen L.; Hamburg, Steven P.
  Environmental Science & Technology (2015), 49 (13), 8147-8157CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  CH4 emissions from the oil and gas industry (O&G) and other sources in the Barnett Shale region (Texas) were estd. by developing a spatially resolved emission inventory. In total, 18 source categories were estd. using multiple datasets, including empirical measurements at regional O&G sites and a national study of collecting/processing facilities. Spatially referenced activity data were compiled from federal and state databases and combined with O&G facility emission factors calcd. by Monte Carlo simulations which accounted for high emission sites representing the very upper portion, or fat-tail, of obsd. emissions distributions. Total CH4 emissions in the 25-county Barnett Shale region in Oct. 2013 were estd. to be 72,300 (63,400-82,400) kg CH4/h. O&G emissions were estd. to be 46,200 (40,000-54,100) kg CH4/h; 19% of emissions from fat-tail sites represented <2% of sites. Estd. O&G emissions in the Barnett Shale region were higher than alternative inventories based on the USEPA Greenhouse Gas Inventory, EPA Greenhouse Gas Reporting Program, and Emissions Database for Global Atm. Research by factors of 1.5, 2.7, and 4.3, resp. Collecting compressor sites, accounting for 40% of O&G emissions in this inventory, had the largest difference from emission ests. based on EPA data sources. This inventory higher O&G emissions est. was due primarily to its more comprehensive activity factors and inclusion of fat-tail sites.
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13. 13
  Brantley, H. L.; Thoma, E. D.; Squier, W. C.; Guven, B. B.; Lyon, D. Assessment of Methane Emissions from Oil and Gas Production Pads using Mobile Measurements Environ. Sci. Technol. 2014, 48 (24) 14508– 14515 DOI: 10.1021/es503070q
  13
  Assessment of methane emissions from oil and gas production pads using mobile measurements
  Brantley, Halley L.; Thoma, Eben D.; Squier, William C.; Guven, Birnur B.; Lyon, David
  Environmental Science & Technology (2014), 48 (24), 14508-14515CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  A new mobile methane emissions inspection approach, Other Test Method (OTM) 33A, was used to quantify short-term emission rates from 210 oil and gas prodn. pads during eight two-week field studies in Texas, Colorado, and Wyoming from 2010 to 2013. Emission rates were log-normally distributed with geometric means and 95% confidence intervals (CIs) of 0.33 (0.23, 0.48), 0.14 (0.11, 0.19), and 0.59 (0.47, 0.74) g/s in the Barnett, Denver-Julesburg, and Pinedale basins, resp. This study focused on sites with emission rates above 0.01 g/s and included short-term (i.e., condensate tank flashing) and maintenance-related emissions. The results fell within the upper ranges of the distributions obsd. in recent onsite direct measurement studies. Considering data across all basins, a multivariate linear regression was used to assess the relationship of methane emissions to well age, gas prodn., and hydrocarbon liqs. (oil or condensate) prodn. Methane emissions were pos. correlated with gas prodn., but only approx. 10% of the variation in emission rates was explained by variation in prodn. levels. The weak correlation between emission and prodn. rates may indicate that maintenance-related stochastic variables and design of prodn. and control equipment are factors detg. emissions.
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14. 14
  Rella, C. W.; Tsai, T. R.; Botkin, C. G.; Crosson, E. R.; Steele, D. Measuring Emissions from Oil and Natural Gas Well Pads Using the Mobile Flux Plane Technique Environ. Sci. Technol. 2015, 49 (7) 4742– 4748 DOI: 10.1021/acs.est.5b00099
  There is no corresponding record for this reference.
15. 15
  Mitchell, A. L.; Tkacik, D. S.; Roscioli, J. R.; Herndon, S. C.; Yacovitch, T. I.; Martinez, D. M.; Vaughn, T. L.; Williams, L. L.; Sullivan, M. R.; Floerchinger, C. Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results Environ. Sci. Technol. 2015, 49 (5) 3219– 3227 DOI: 10.1021/es5052809
  15
  Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results
  Mitchell, Austin L.; Tkacik, Daniel S.; Roscioli, Joseph R.; Herndon, Scott C.; Yacovitch, Tara I.; Martinez, David M.; Vaughn, Timothy L.; Williams, Laurie L.; Sullivan, Melissa R.; Floerchinger, Cody; Omara, Mark; Subramanian, R.; Zimmerle, Daniel; Marchese, Anthony J.; Robinson, Allen L.
  Environmental Science & Technology (2015), 49 (5), 3219-3227CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  Facility-level methane emissions were measured at 114 gathering facilities and 16 processing plants in the United States natural gas system. At gathering facilities, the measured methane emission rates ranged from 0.7 to 700 kg per h (kg/h) (0.6 to 600 std. cfm (scfm)). Normalized emissions (as a % of total methane throughput) were less than 1% for 85 gathering facilities and 19 had normalized emissions less than 0.1%. The range of methane emissions rates for processing plants was 3 to 600 kg/h (3 to 524 scfm), corresponding to normalized methane emissions rates <1% in all cases. The distributions of methane emissions, particularly for gathering facilities, are skewed. For example, 30% of gathering facilities contribute 80% of the total emissions. Normalized emissions rates are neg. correlated with facility throughput. The variation in methane emissions also appears driven by differences between inlet and outlet pressure, as well as venting and leaking equipment. Substantial venting from liqs. storage tanks was obsd. at 20% of gathering facilities. Emissions rates at these facilities were, on av., around four times the rates obsd. at similar facilities without substantial venting.
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16. 16
  Subramanian, R.; Williams, L. L.; Vaughn, T. L.; Zimmerle, D.; Roscioli, J. R.; Herndon, S. C.; Yacovitch, T. I.; Floerchinger, C.; Tkacik, D. S.; Mitchell, A. L. Methane Emissions from Natural Gas Compressor Stations in the Transmission and Storage Sector: Measurements and Comparisons with the EPA Greenhouse Gas Reporting Program Protocol Environ. Sci. Technol. 2015, 49 (5) 3252– 3261 DOI: 10.1021/es5060258
  16
  Methane Emissions from Natural Gas Compressor Stations in the Transmission and Storage Sector: Measurements and Comparisons with the EPA Greenhouse Gas Reporting Program Protocol
  Subramanian, R.; Williams, Laurie L.; Vaughn, Timothy L.; Zimmerle, Daniel; Roscioli, Joseph R.; Herndon, Scott C.; Yacovitch, Tara I.; Floerchinger, Cody; Tkacik, Daniel S.; Mitchell, Austin L.; Sullivan, Melissa R.; Dallmann, Timothy R.; Robinson, Allen L.
  Environmental Science & Technology (2015), 49 (5), 3252-3261CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  Equipment- and site-level methane emissions from 45 compressor stations in the transmission and storage (T&S) sector of the US natural gas system were measured, including 25 sites required to report under the EPA greenhouse gas reporting program (GHGRP). Direct measurements of fugitive and vented sources were combined with AP-42-based exhaust emission factors (for operating reciprocating engines and turbines) to produce a study onsite est. Site-level methane emissions were also concurrently measured with downwind-tracer-flux techniques. At most sites, these two independent ests. agreed within exptl. uncertainty. Site-level methane emissions varied from 2-880 SCFM. Compressor vents, leaky isolation valves, reciprocating engine exhaust, and equipment leaks were major sources, and substantial emissions were obsd. at both operating and standby compressor stations. The site-level methane emission rates were highly skewed; the highest emitting 10% of sites (including two superemitters) contributed 50% of the aggregate methane emissions, while the lowest emitting 50% of sites contributed less than 10% of the aggregate emissions. Excluding the two superemitters, study-av. methane emissions from compressor housings and noncompressor sources are comparable to or lower than the corresponding effective emission factors used in the EPA greenhouse gas inventory. If the two superemitters are included in the anal., then the av. emission factors based on this study could exceed the EPA greenhouse gas inventory emission factors, which highlights the potentially important contribution of superemitters to national emissions. However, quantification of their influence requires knowledge of the magnitude and frequency of superemitters across the entire T&S sector. Only 38% of the methane emissions measured by the comprehensive onsite measurements were reportable under the new EPA GHGRP because of a combination of inaccurate emission factors for leakers and exhaust methane, and various exclusions. The bias is even larger if one accounts for the superemitters, which were not captured by the onsite measurements. The magnitude of the bias varied from site to site by site type and operating state. Therefore, while the GHGRP is a valuable new source of emissions information, care must be taken when incorporating these data into emission inventories. The value of the GHGRP can be increased by requiring more direct measurements of emissions (as opposed to using counts and emission factors), eliminating exclusions such as rod-packing vents on pressurized reciprocating compressors in standby mode under Subpart-W, and using more appropriate emission factors for exhaust methane from reciprocating engines under Subpart-C.
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17. 17
  Lamb, B. K.; Edburg, S. L.; Ferrara, T. W.; Howard, T.; Harrison, M. R.; Kolb, C. E.; Townsend-Small, A.; Dyck, W.; Possolo, A.; Whetstone, J. R. Direct Measurements Show Decreasing Methane Emissions from Natural Gas Local Distribution Systems in the United States Environ. Sci. Technol. 2015, 49 (8) 5161– 5169 DOI: 10.1021/es505116p
  17
  Direct Measurements Show Decreasing Methane Emissions from Natural Gas Local Distribution Systems in the United States
  Lamb, Brian K.; Edburg, Steven L.; Ferrara, Thomas W.; Howard, Touche; Harrison, Matthew R.; Kolb, Charles E.; Townsend-Small, Amy; Dyck, Wesley; Possolo, Antonio; Whetstone, James R.
  Environmental Science & Technology (2015), 49 (8), 5161-5169CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  Fugitive losses from natural gas distribution systems are a significant source of anthropogenic methane. Here, we report on a national sampling program to measure methane emissions from 13 urban distribution systems across the U. S. Emission factors were derived from direct measurements at 230 underground pipeline leaks and 229 metering and regulating facilities using stratified random sampling. When these new emission factors are combined with ests. for customer meters, maintenance, and upsets, and current pipeline miles and nos. of facilities, the total est. is 393 Gg/yr with a 95% upper confidence limit of 854 Gg/yr (0.10% to 0.22% of the methane delivered nationwide). This fraction includes emissions from city gates to the customer meter, but does not include other urban sources or those downstream of customer meters. The upper confidence limit accounts for the skewed distribution of measurements, where a few large emitters accounted for most of the emissions. This emission est. is 36% to 70% less than the 2011 EPA inventory, (based largely on 1990s emission data), and reflects significant upgrades at metering and regulating stations, improvements in leak detection and maintenance activities, as well as potential effects from differences in methodologies between the two studies.
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18. 18
  Zavala-Araiza, D.; Lyon, D.; Alvarez, R. A.; Palacios, V.; Harriss, R.; Lan, X.; Talbot, R.; Hamburg, S. P. Toward a Functional Definition of Methane Super-Emitters: Application to Natural Gas Production Sites Environ. Sci. Technol. 2015, 49 (13) 8167– 8174 DOI: 10.1021/acs.est.5b00133
  18
  Toward a Functional Definition of Methane Super-Emitters: Application to Natural Gas Production Sites
  Zavala-Araiza, Daniel; Lyon, David; Alvarez, Ramon A.; Palacios, Virginia; Harriss, Robert; Lan, Xin; Talbot, Robert; Hamburg, Steven P.
  Environmental Science & Technology (2015), 49 (13), 8167-8174CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  Natural gas prodn. site emissions 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. This work designed a conceptual framework to functionally define super-emitting sites as those with the highest proportional loss rates (Ch4 emitted vs. CH4 produced). Using this concept, total CH4 emissions from Barnett Shale natural gas prodn. sites (Texas) were estd.; super-emitting sites functionally accounted for approx. 3/4 of total emissions. The potential to reduce emissions from these sites is discussed under the assumption that sites with high proportional loss rates have excess emissions resulting from abnormal or otherwise avoidable operating conditions, e.g., malfunctioning equipment. Since the population of functionally super-emitting sites is not expected to be static over time, continuous monitoring will be necessary to identify them and improve their operation. This work suggested that achieving and maintaining uniformly low emissions across the entire population of prodn. sites will require mitigation steps at a large fraction of sites.
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19. 19
  Jackson, R. B.; Vengosh, A.; Carey, J. W.; Davies, R. J.; Darrah, T. H.; O’Sullivan, F.; Pétron, G. The Environmental Costs and Benefits of Fracking Annu. Rev. Environ. Resour. 2014, 39 (1) 327– 362 DOI: 10.1146/annurev-environ-031113-144051
  There is no corresponding record for this reference.
20. 20
  Proposed Rule: Oil and Natural Gas Sector: Emission Standards for New and Modified Sources; Sep 18, 2015. Available from: https://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-21023.pdf.
  There is no corresponding record for this reference.
21. 21
  Benson, R.; Madding, R.; Lucier, R.; Lyons, J.; Czerepuszko, P. Standoff passive optical leak detection of volatile organic compounds using a cooled InSb based infrared imager. AWMA 99th Annual Meeting Papers, 2006; Vol. 131.
  There is no corresponding record for this reference.
22. 22
  Robinson, D. R.; Luke-Boone, R.; Aggarwal, V.; Harris, B.; Anderson, E.; Ranum, D.; Kulp, T. J.; Armstrong, K.; Sommers, R.; McRae, T. G. Refinery evaluation of optical imaging to locate fugitive emissions J. Air Waste Manage. Assoc. 2007, 57 (7) 803– 810 DOI: 10.3155/1047-3289.57.7.803
  22
  Refinery evaluation of optical imaging to locate fugitive emissions
  Robinson, Donald R.; Luke-Boone, Ronke; Aggarwal, Vineet; Harris, Buzz; Anderson, Eric; Ranum, David; Kulp, Thomas J.; Armstrong, Karla; Sommers, Ricky; McRae, Thomas G.; Ritter, Karin; Siegell, Jeffrey H.; Van Pelt, Doug; Smylie, Mike
  Journal of the Air & Waste Management Association (2007), 57 (7), 803-810CODEN: JAWAFC; ISSN:1096-2247. (Air & Waste Management Association)
  Fugitive emissions account for approx. 50% of total hydrocarbon emissions from process plants. Federal and state regulations aiming at controlling these emissions require refineries and petrochem. plants in the United States to implement a Leak Detection and Repair Program (LDAR). The current regulatory work practice, U.S. Environment Protection Agency Method 21, requires designated components to be monitored individually at regular intervals. The annual costs of these LDAR programs in a typical refinery can exceed US$1,000,000. Previous studies have shown that a majority of controllable fugitive emissions come from a very small fraction of components. The Smart LDAR program aims to find cost-effective methods to monitor and reduce emissions from these large leakers. Optical gas imaging has been identified as one such technol. that can help achieve this objective. This paper discusses a refinery evaluation of an instrument based on backscatter absorption gas imaging technol. This portable camera allows an operator to scan components more quickly and image gas leaks in real time. During the evaluation, the instrument was able to identify leaking components that were the source of 97% of the total mass emissions from leaks detected. More than 27,000 components were monitored. This was achieved in far less time than it would have taken using Method 21. In addn., the instrument was able to find leaks from components that are not required to be monitored by the current LDAR regulations. The technol. principles and the parameters that affect instrument performance are also discussed in the paper.
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23. 23
  Biennial Report to the 84th Legislature, Chapter 1: Agency Highlights, FY2013–2014; Texas Commision on Environmental Quality: Austin, TX, 2015. Available from: http://www.tceq.state.tx.us/publications/sfr/index84/chapter1.
  There is no corresponding record for this reference.
24. 24
  Drillinginfo. DI Desktop; Drillinginfo: Austin, TX; 2015. Available from: http://www.didesktop.com/.
  There is no corresponding record for this reference.
25. 25
  Leak Surveys, Inc. Available from: http://www.leaksurveysinc.com/.
  There is no corresponding record for this reference.
26. 26
  Monthly Energy Review; United States Energy Information Administration: Washington, DC; 2015, Sep. Available from: http://www.eia.gov/totalenergy/data/monthly/archive/00351509.pdf.
  There is no corresponding record for this reference.
27. 27
  Allen, D. T.; Pacsi, A. P.; Sullivan, D. W.; Zavala-Araiza, D.; Harrison, M.; Keen, K.; Fraser, M. P.; Daniel Hill, A.; Sawyer, R. F.; Seinfeld, J. H. Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers Environ. Sci. Technol. 2015, 49 (1) 633– 640 DOI: 10.1021/es5040156
  27
  Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers
  Allen, David T.; Pacsi, Adam P.; Sullivan, David W.; Zavala-Araiza, Daniel; Harrison, Matthew; Keen, Kindal; Fraser, Matthew P.; Daniel Hill, A.; Sawyer, Robert F.; Seinfeld, John H.
  Environmental Science & Technology (2015), 49 (1), 633-640CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  Pollutant emissions from 377 gas-actuated (pneumatic) controllers were measured at natural gas prodn. sites and several oil prodn. sites throughout the US. A small subset of devices (19%), with whole gas emission rates >6 std. ft3/h (scf/h) accounted for 95% of emissions. More than half the controllers recorded emissions of ≤0.001 scf/h during a 15-min measurement. Pneumatic controllers in level control applications on separators and in compressor applications had higher emission rates than controllers in other types of applications. Regional emission differences were obsd.; lowest emissions were measured in the Rocky Mountains, highest emissions were measured at the Gulf Coast. Av. reported CH4 emissions/controller were 17% higher than av. emissions/controller in the 2012 USEPA greenhouse gas national emission inventory (2012 GHG NEI, released in 2014). The av. of 2.7 controllers/well obsd. in this work was higher than the 1.0 controllers/well reported in the 2012 GHG NEI.
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28. 28
  Allen, D. T.; Torres, V. M.; Thomas, J.; Sullivan, D. W.; Harrison, M.; Hendler, A.; Herndon, S. C.; Kolb, C. E.; Fraser, M. P.; Hill, A. D. Measurements of methane emissions at natural gas production sites in the United States Proc. Natl. Acad. Sci. U. S. A. 2013, 110 (44) 17768– 73 DOI: 10.1073/pnas.1304880110
  28
  Measurements of methane emissions at natural gas production sites in the United States
  Allen, David T.; Torres, Vincent M.; Thomas, James; Sullivan, David W.; Harrison, Matthew; Hendler, Al; Herndon, Scott C.; Kolb, Charles E.; Fraser, Matthew P.; Hill, A. Daniel; Lamb, Brian K.; Miskimins, Jennifer; Sawyer, Robert F.; Seinfeld, John H.
  Proceedings of the National Academy of Sciences of the United States of America (2013), 110 (44), 17768-17773,S17768/1-S17768/77CODEN: PNASA6; ISSN:0027-8424. (National Academy of Sciences)
  Engineering ests. of CH4 emissions from natural gas prodn. led to varied projections of national emissions. This work reports direct measurements of CH4 emissions at 190 on-shore natural gas sites in the US (150 prodn. sites, 27 well completion flow-backs, 9 well unloadings, 4 work-overs). For well completion flow-backs, which clear fractured wells of liq. to allow gas prodn., CH4 emissions were 0.01-17 Mg (mean, 1.7 Mg; 95% confidence interval bounds, 0.67-3.3 Mg) vs. an av. of 81 Mg/event in the 2011 USEPA national emission inventory (Apr. 2013). Emission factors for pneumatic pumps/controllers and equipment leaks were comparable to and higher than national inventory ests. If emission factors from this work for completion flow-backs, equipment leaks, and pneumatic pumps/controllers were assumed to be representative of national populations and were used to est. national emissions, total annual emissions from these source categories were calcd. to be 957 Gg CH4 (with sampling and measurement uncertainties estd. at ±200 Gg). The est. for comparable source categories in the USEPA national inventory is ∼1200 Gg. Addnl. measurements of unloadings and work-overs are needed to produce national emission ests. for these source categories. The 957 Gg emissions for completion flow-backs, pneumatics, and equipment leaks, in conjunction with USEPA national inventory ests. for other categories, led to an estd. 2300 Gg CH4 emissions from natural gas prodn. (0.42% of gross gas prodn.).
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  https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BC3sXhvVWmtbjE&md5=2879393705e3234284752239a9222374
29. 29
  Omara, M.; Sullivan, M. R.; Li, X.; Subramanian, R.; Robinson, A. L.; Presto, A. A. Methane Emissions from Conventional and Unconventional Natural Gas Production Sites in the Marcellus Shale Basin Environ. Sci. Technol. 2016, 50 (4) 2099– 2107 DOI: 10.1021/acs.est.5b05503
  29
  Methane Emissions from Conventional and Unconventional Natural Gas Production Sites in the Marcellus Shale Basin
  Omara, Mark; Sullivan, Melissa R.; Li, Xiang; Subramanian, R.; Robinson, Allen L.; Presto, Albert A.
  Environmental Science & Technology (2016), 50 (4), 2099-2107CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  There is a need to continually assess CH4 emissions assocd. with natural gas (NG) prodn., particularly since recent advancements in horizontal drilling in conjunction with staged hydraulic fracturing technologies dramatically increased NG prodn. (i.e., unconventional NG wells). This work measured facility-level CH4 emissions rates from the NG prodn. sector in the Marcellus region, comparing CH4 emissions between unconventional NG (UNG) well pad sites and relatively smaller, older conventional NG (CvNG) sites consisting of wells drilled vertically into permeable geol. formations. A top-down tracer-flux CH4 measurement approach using mobile downwind intercepts of CH4, ethane, and tracer (N2O and acetylene) plumes was performed at 18 CvNG sites (19 individual wells) and 17 UNG sites (88 individual wells). The 17 UNG sites included 4 sites undergoing completion flow-back (FB). The mean facility-level CH4 emission rate among UNG well pad sites in routine prodn. (18.8 kg/h [95% confidence interval (CI) with a mean 12.0-26.8 kg/h]) was 23 times greater than mean CH4 emissions from CvNG sites. These differences were attributed, in part, to the large size (i.e., no. of wells and ancillary NG prodn. equipment) and the significantly higher prodn. rate of UNG sites. However, CvNG sites generally had much higher prodn.-normalized CH4 emission rates (median: 11%; range: 0.35-91%) vs. UNG sites (median: 0.13%, range: 0.01-1.2%), likely due to a greater prevalence of avoidable process operating conditions (e.g., unresolved equipment maintenance issues). At a regional scale, it was estd. that total annual CH4 emissions from 88,500 combined CvNG well pads in Pennsylvania and West Virginia (660 Gg [95% CI: 500-800 Gg]) exceeded that from 3390 UNG well pads by 170 Gg, reflecting the large no. of CvNG wells and the comparably large fraction of CH4 lost/unit prodn. These new emissions data suggested recently instituted Pennsylvania CH4 emissions inventory substantially underestimated measured facility-level CH4 emissions by >10-40 times for 4 UNG sites in this study.
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30. 30
  Methane Emissions from the Natural Gas Industry. Volume 14: Glycol Dehydrators; Gas Research Institute/United States Environmental Protection Agency: Washington, DC, 1996, Jun. Available from: http://www3.epa.gov/gasstar/documents/emissions_report/14_glycol.pdf.
  There is no corresponding record for this reference.
31. 31
  Brantley, H. L.; Thoma, E. D.; Eisele, A. P. Assessment of volatile organic compound and hazardous air pollutant emissions from oil and natural gas well pads using mobile remote and on-site direct measurements J. Air Waste Manage. Assoc. 2015, 65 (9) 1072– 1082 DOI: 10.1080/10962247.2015.1056888
  31
  Assessment of volatile organic compound and hazardous air pollutant emissions from oil and natural gas well pads using mobile remote and on-site direct measurements
  Brantley, Halley L.; Thoma, Eben D.; Eisele, Adam P.
  Journal of the Air & Waste Management Association (2015), 65 (9), 1072-1082CODEN: JAWAFC; ISSN:1096-2247. (Taylor & Francis Ltd.)
  Emissions of volatile org. compds. (VOCs) and hazardous air pollutants (HAPs) from oil and natural gas prodn. were investigated using direct measurements of component-level emissions on pads in the Denver-Julesburg (DJ) Basin and remote measurements of prodn. pad-level emissions in the Barnett, DJ, and Pinedale basins. Results from the 2011 DJ on-site study indicate that emissions from condensate storage tanks are highly variable and can be an important source of VOCs and HAPs, even when control measures are present. Comparison of the measured condensate tank emissions with potentially emitted concns. modeled using E&P TANKS (American Petroleum Institute [API] Publication 4697) suggested that some of the tanks were likely effectively controlled (emissions less than 95% of potential), whereas others were not. Results also indicate that the use of a com. high-vol. sampler (HVS) without corresponding canister measurements may result in severe underestimates of emissions from condensate tanks. Instantaneous VOC and HAP emissions measured on-site on controlled systems in the DJ Basin were significantly higher than VOC and HAP emission results from the study conducted by Eastern Research Group (ERG) for the City of Fort Worth (2011) using the same method in the Barnett on pads with low or no condensate prodn. The measured VOC emissions were either lower or not significantly different from the results of studies of uncontrolled emissions from condensate tanks measured by routing all emissions through a single port monitored by a flow measurement device for 24 h. VOC and HAP concns. measured remotely using the U. S. Environmental Protection Agency (EPA) Other Test Method (OTM) 33A in the DJ Basin were not significantly different from the on-site measurements, although significant differences between basins were obsd. Implications: VOC and HAP emissions from upstream prodn. operations are important due to their potential impact on regional ozone levels and proximate populations. This study provides information on the sources and variability of VOC and HAP emissions from prodn. pads as well as a comparison between different measurement techniques and lab. anal. protocols. On-site and remote measurements of VOC and HAP emissions from oil and gas prodn. pads indicate that measurable emissions can occur despite the presence of control measures, often as a result of leaking thief hatch seals on condensate tanks. Furthermore, results from the remote measurement method OTM 33A indicate that it can be used effectively as an inspection technique for identifying oil and gas well pads with large fugitive emissions.
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32. 32
  Allen, D. T.; Sullivan, D. W.; Zavala-Araiza, D.; Pacsi, A. P.; Harrison, M.; Keen, K.; Fraser, M. P.; Daniel Hill, A.; Lamb, B. K.; Sawyer, R. F. Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Liquid Unloadings Environ. Sci. Technol. 2015, 49 (1) 641– 648 DOI: 10.1021/es504016r
  32
  Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Liquid Unloadings
  Allen, David T.; Sullivan, David W.; Zavala-Araiza, Daniel; Pacsi, Adam P.; Harrison, Matthew; Keen, Kindal; Fraser, Matthew P.; Daniel Hill, A.; Lamb, Brian K.; Sawyer, Robert F.; Seinfeld, John H.
  Environmental Science & Technology (2015), 49 (1), 641-648CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  CH4 emissions from liq. unloading were measured at 107 wells at natural gas prodn. regions throughout the US. Unloading clear well accumulated liqs. to increase prodn. uses a variety of liq. lift mechanisms. This work sampled wells with and without plunger lifts. Most wells without plunger lifts unload <10 times/yr with emissions averaging 21,000-35,000 std. ft3 (scf) CH4 (0.4-0.7 Mg)/event (95% confidence limits = 10,000-50,000 scf/event). For wells with plunger lifts, emissions averaged 1000-10,000 scf CH4 (0.02-0.2 Mg)/event (95% confidence limits = 500-12,000 scf/event). Some wells with plunger lifts are automatically triggered and unload thousands of times/yr; these wells account for the majority of the emissions from all wells with liq. unloading. If data collected in this work are assumed to be representative of national populations, they suggested the central unloading emission est. (270 Gg/yr, 95% confidence range = 190-400 Gg) were within a few percent of emissions estd. by the USEPA 2012 Greenhouse Gas National Emission Inventory (released in 2014), with emissions dominated by wells with high unloading frequency.
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33. 33
  Greenhouse Gas Reporting Program. United States Environmental Protection Agency: Washington, DC, 2015. Available from: http://www.epa.gov/ghgreporting.
  There is no corresponding record for this reference.
34. 34
  Oil and Gas Emission Estimation Tool 2014 Version 1; United States Environmental Protection Agency: Washington, DC, 2015. Available from: ftp://ftp.epa.gov/EmisInventory/2011nei/doc/Tool_and_Report112614.zip.
  There is no corresponding record for this reference.
35. 35
  Utah Department of Environmental Quality. Utah General Approval Order for Crude Oil and Natural Gas Well Site and/or Tank Battery, Section II.B.2. Jun 5, 2014. Available from: http://www.deq.utah.gov/Permits/GAOs/docs/2014/6June/DAQE-AN149250001-14.pdf.
  There is no corresponding record for this reference.
36. 36
  North Dakota Department of Health. Bakken Pool, Oil and Gas Production Facilities, Air Pollution Control, Permitting and Compliance Guidance. May 2, 2011. Available from: https://www.ndhealth.gov/AQ/Policy/20110502Oil%20%20Gas%20Permitting%20Guidance.pdf.
  There is no corresponding record for this reference.
37. 37
  Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution. Available from: http://www.ecfr.gov/cgi-bin/text-idx?node=sp40.7.60.oooo.
  There is no corresponding record for this reference.
38. 38
  EPA Observes Air Emissions from Controlled Storage Vessels at Onshore Oil and Natural Gas Production Facilities; United States Environmental Protection Agency: Washington, DC, 2015. Available from: http://www.epa.gov/sites/production/files/2015-09/documents/oilgascompliancealert.pdf.
  There is no corresponding record for this reference.
39. 39
  Consent Decree: United States of America, and the State of Colorado v. Noble Energy, Inc.; United States District Court for the District of Colorado, Denver, CO, 2015. Available from: http://www.epa.gov/sites/production/files/2015-04/documents/noble-cd.pdf.
  There is no corresponding record for this reference.
40. 40
  2011 National Emissions Inventory; United States Environmental Protection Agency: Washington, DC, 2013. Available from: http://www3.epa.gov/ttnchie1/net/2011inventory.html.
  There is no corresponding record for this reference.
41. 41
  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2013; United States Environmental Protection Agency: Washington, DC, 2015. Available from: http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.
  There is no corresponding record for this reference.
42. 42
  Albertson, J. D.; Harvey, T.; Foderaro, G.; Zhu, P.; Zhou, X.; Ferrari, S.; Amin, M. S.; Modrak, M.; Brantley, H.; Thoma, E. D. A Mobile Sensing Approach for Regional Surveillance of Fugitive Methane Emissions in Oil and Gas Production Environ. Sci. Technol. 2016, 50 (5) 2487– 2497 DOI: 10.1021/acs.est.5b05059
  There is no corresponding record for this reference.
43. 43
  Advanced Research Projects Agency – Energy, United States Department of Energy. Methane Observation Networks with Innovative Technology to Obtain Reductions – MONITOR; 2014; http://arpa-e.energy.gov/sites/default/files/documents/files/MONITOR_ProgramOverview.pdf.
  There is no corresponding record for this reference.
44. 44
  Environmental Defense Fund. Methane Detectors Challenge; 2015; https://www.edf.org/energy/natural-gas-policy/methane-detectors-challenge.
  There is no corresponding record for this reference.
Supporting Information
Supporting Information
The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.est.6b00705.
- 8 infrared videos and description of observed sources (ZIP)
- Supporting text, 17 tables, and 2 figures (PDF)
- Calculations used in tank flashing analysis (XLSX)
- Site-level parameter data for well pads in the surveyed areas and basins (XLSX)
- List of surveyed sites by latitude/longitude (XLSX)
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Aerial Surveys of Elevated Hydrocarbon Emissions from Oil and Gas Production Sites
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