Repository for Oil and Gas Energy Research (ROGER)

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Understanding emissions of methane from legacy and ongoing shale gas development requires both regional studies that assess the frequency of emissions and case studies that assess causation. We present the first direct measurements of emissions in a case study of a putatively leaking gas well in the largest shale gas play in the United States. We quantify atmospheric methane emissions in farmland >2 km from the nearest shale gas well cited for casing and cementing issues. We find that emissions are highly heterogeneous as they travel long distances in the subsurface. Emissions were measured near observed patches of dead vegetation and methane bubbling from a stream. An eddy covariance flux tower, chamber flux measurements, and a survey of enhancements of the near-surface methane mole fraction were used to quantify emissions and evaluate the spatial and temporal variability. We combined eddy covariance measurements with the survey of the methane mole fraction to estimate total emissions over the study area (2,800 m2). Estimated at ∼6 kg CH4 day–1, emissions were spatially heterogeneous but showed no temporal trends over 6 months. The isotopic signature of the atmospheric CH4 source (δ13CH4) was equal to −29‰, consistent with methane of thermogenic origin and similar to the isotopic signature of the gas reported from the nearest shale gas well. While the magnitude of emissions from the potential leak is modest compared to large emitters identified among shale gas production sites, it is large compared to estimates of emissions from single abandoned wells. Since other areas of emissions have been identified close to this putatively leaking well, our estimate of emissions likely represents only a portion of total emissions from this event. More comprehensive quantification will require more extensive spatial and temporal sampling of the locations of gas migration to the surface as well as an investigation into the mechanisms of subsurface gas migration. This work highlights an example of atmospheric methane emissions from potential stray gas migration at a location far from a well pad, and further research should explore the frequency and mechanisms behind these types of events to inform careful and strategic natural gas development.

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Development of the Permian Basin in recent years has disrupted the global trade of oil and gas. As of January 2020, it was producing more than five million barrels of oil and 20 billion cubic feet of gas per day, with the greatest growth coming from the Delaware Basin sub-play. In this investigation, we report the results of a novel process-based life cycle assessment (LCA) of the greenhouse gas (GHG) emissions associated with oil and gas products from the Delaware Basin, employing extensive operational data including direct measurements of methane emissions. We find that if 1% of the gross gas produced is flared, then the upstream carbon intensity of crude oil is 19.5 kg CO2eq per barrel of crude oil - substantially lower than “global average” intensities reported in the literature. Moreover, the carbon intensities of gasoline, diesel and jet fuel refined from Delaware Basin crudes are approximately 10% less than the U.S. EPA and Department of Energy baselines when a 1% flaring rate is achieved. The life cycle GHG reductions are also a consequence of the physical and chemical properties of Delaware Basin crudes relative to the average crude blend for the U.S., resulting in reduced refinery GHG emissions. We also find that life cycle GHG emissions associated with natural gas from the Delaware Basin are similar to those reported for U.S. shale gas.

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Methane, a potent greenhouse gas, is the main component of natural gas. Previous research has identified considerable methane emissions associated with oil and gas production, but estimates of emission trends have been inconsistent, in part due to limited in-situ methane observations spanning multiple years in oil/gas production regions. Here we present a unique analysis of one of the longest-running datasets of in-situ methane observations from an oil/gas production region in Utah’s Uinta Basin. The observations indicate Uinta methane emissions approximately halved between 2015 and 2020, along with declining gas production. As a percentage of gas production, however, emissions remained steady over the same years, at ~ 6–8%, among the highest in the U.S. Addressing methane leaks and recovering more of the economically valuable natural gas is critical, as the U.S. seeks to address climate change through aggressive greenhouse emission reductions.

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Methane (CH4) emissions from oil and natural gas (O&NG) systems are an important contributor to greenhouse gas emissions. In the United States, recent synthesis studies of field measurements of CH4 emissions at different spatial scales are ~1.5–2× greater compared to official greenhouse gas inventory (GHGI) estimates, with the production-segment as the dominant contributor to this divergence. Based on an updated synthesis of measurements from component-level field studies, we develop a new inventory-based model for CH4 emissions, for the production-segment only, that agrees within error with recent syntheses of site-level field studies and allows for isolation of equipment-level contributions. We find that unintentional emissions from liquid storage tanks and other equipment leaks are the largest contributors to divergence with the GHGI. If our proposed method were adopted in the United States and other jurisdictions, inventory estimates could better guide CH4 mitigation policy priorities.

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We present an updated fuel-based oil and gas (FOG) inventory with estimates of nitrogen oxide (NOx) emissions from oil and natural gas production in the contiguous US (CONUS). We compare the FOG inventory with aircraft-derived (“top-down”) emissions for NOx over footprints that account for ∼25% of US oil and natural gas production. Across CONUS, we find that the bottom-up FOG inventory combined with other anthropogenic emissions is on average within ∼10% of top-down aircraft-derived NOx emissions. We also find good agreement in the trends of NOx from drilling- and production-phase activities, as inferred by satellites and in the bottom-up inventory. Leveraging tracer−tracer relationships derived from aircraft observations, methane (CH4) and non-methane volatile organic compound (NMVOC) emissions have been added to the inventory. Our total CONUS emission estimates for 2015 of oil and natural gas are 0.45 ± 0.14 Tg NOx/yr, 15.2 ± 3.0 Tg CH4/yr, and 5.7 ± 1.7 Tg NMVOC/yr. Compared to the US National Emissions Inventory and Greenhouse Gas Inventory, FOG NOx emissions are ∼40% lower, while inferred CH4 and NMVOC emissions are up to a factor of ∼2 higher. This suggests that NMVOC/NOx emissions from oil and gas basins are ∼3 times higher than current estimates and will likely affect how air quality models represent ozone formation downwind of oil and gas fields.

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Current approaches relating thermogenic gases to either shale source rocks (predominantly type II kerogen) or coal source rocks (predominantly type III kerogen) are not reliable and not globally applicable. This is because these mostly empirical approaches were developed using small poorly-constrained datasets from limited locations. The evaluation of a large global dataset of molecular and isotopic properties of gases from unconventional shale and coal reservoirs suggests that two genetic diagrams based on stable carbon isotopes of methane and ethane, δ13C-C2H6 versus δ13C-CH4 and δ13C-CH4 versus Δ(δ13C-C2H6 - δ13C-CH4), provide the best separation of shale-sourced and coal-sourced gases. Newly designated genetic fields and shale/coal separation lines on these diagrams were tested and validated using data from five petroleum systems with, likely, only shale (class B and A organofacies) source rocks (the Maracaibo Basin in Venezuela, the Guajira Basin in Colombia and the Rub Al Khali Basin in Iran) and only coal (class F organofacies) source rocks (the Southern Permian Basin in Germany and the Sichuan Basin in China). The practical usefulness of this new approach to gas-source correlations was demonstrated in two case studies from petroleum systems with debated source rock organofacies (the Mozambique Basin in Mozambique and the Indus Basin in Pakistan). These better constrained and more reliable diagrams with genetic fields and shale/coal separation lines represent a new tool for the evaluation of petroleum systems.

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Understanding methane emissions from the natural gas supply chain continues to be of interest. Previous studies identified that measurements are skewed due to “super-emitters”, and recently, researchers identified temporal variability as another contributor to discrepancies among studies. We focused on the latter by performing 17 methane audits at a single production site over 4 years, from 2016 to 2020. Source detection was similar to Method 21 but augmented with accurate methane mass rate quantification. Audit results varied from ∼78 g/h to over 43 kg/h with a mean emissions rate of 4.2 kg/h and a geometric mean of 821 g/h. Such high variability sheds light that even quarterly measurement programs will likely yield highly variable results. Total emissions were typically dominated by those from the produced water storage tank. Of 213 sources quantified, a single tank measurement represented 60% of the cumulative emission rate. Measurements were separated into four categories: wellheads (n = 78), tank (n = 17), enclosed gas process units (n = 31), and others (n = 97). Each subgroup of measurements was skewed and fat-tailed, with the skewness ranging from 2.4 to 5.7 and kurtosis values ranging from 6.5 to 33.7. Analyses found no significant correlations between methane emissions and temperature, whole gas production, or water production. Since measurement results were highly variable and daily production values were known, we completed a Monte Carlo analysis to estimate average throughput-normalized methane emissions which yielded an estimate of 0.093 ± 0.013%.

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Abstract. Methane emissions associated with the production, transport, and use of oil and natural gas increase the climatic impacts of energy use; however, little is known about how emissions vary temporally and with commodity prices. We present airborne and ground-based data, supported by satellite observations, to measure weekly to monthly changes in total methane emissions in the United States' Permian Basin during a period of volatile oil prices associated with the COVID-19 pandemic. As oil prices declined from ∼ USD 60 to USD 20 per barrel, emissions changed concurrently from 3.3 % to 1.9 % of natural gas production; as prices partially recovered, emissions increased back to near initial values. Concurrently, total oil and natural gas production only declined by ∼ 10 % from the peak values seen in the months prior to the crash. Activity data indicate that a rapid decline in well development and subsequent effects on associated gas flaring and midstream infrastructure throughput are the likely drivers of temporary emission reductions. Our results, along with past satellite observations, suggest that under more typical price conditions, the Permian Basin is in a state of overcapacity in which rapidly growing associated gas production exceeds midstream capacity and leads to high methane emissions.

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Methane emission estimates for oil and gas production sites, based on observations lasting seconds to minutes, are becoming more common, but interpreting the emission estimates is challenging. Short-term observations made at the same sites, within days of one another, can lead to very different emission estimates. Using two independent sets of short duration measurements made at a group of 33 dry-gas production sites, this work demonstrates that sets of short duration measurements can be reconciled if distributions of emissions at multiple sites, rather than measurements at individual sites, are compared. This work also demonstrates that short duration measurements made at the equipment level can be extrapolated to longer term emission estimates for individual sites using models that account for intermittency in emissions. This approach can predict expected ranges of emissions for additional sites and can be used to identify site level observations that are outside of predicted ranges, which indicate potential abnormal emissions.

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Background. Prior studies have found that residential proximity to upstream oil and gas production is associated with increased risk of adverse health outcomes. Emissions of ambient air pollutants from oil and gas wells in the preproduction and production stages has been proposed as conferring risk of adverse health effects, but the extent of air pollutant emissions from wells is not clear. Objectives. We examined the effects of upstream oil and gas preproduction (count of drilling sites) and production (total volume of oil and gas) activities on concentrations of five ambient air pollutants in California. Methods. We obtained data on approximately 1 million daily observations from 314 monitors in the EPA Air Quality System, 2006-2019, including daily concentrations of five routinely monitored ambient air pollutants: PM2.5, CO, NO2, O3, and VOCs. We obtained data on preproduction and production operations from Enverus and the California Geographic Energy Management Division (CalGEM) for all wells in the state. For each monitor-day, we assessed exposure to upwind preproduction wells and total oil and gas production volume within 10 km. We used a panel regression approach in the analysis and fit adjusted fixed effects linear regression models for each pollutant, controlling for geographic, seasonal, temporal, and meteorological factors. Results. We observed higher concentrations of PM2.5 and CO with exposure to preproduction wells within 3 km, NO2 for wells at 1-2 km, and O3 with exposure at 2-4 km. Monitor-days with exposure to increases in production volume had higher concentrations of PM2.5, NO2, and VOCs within 1 km and higher O3 concentrations at 1-2 km. Results were robust to sensitivity analyses. Conclusion. Adjusting for geographic, meteorological, seasonal, and time-trending factors, we observed higher concentrations of ambient air pollutants at air quality monitors in proximity to preproduction wells within 4 km and producing wells within 2 km.

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Methane emissions were measured at 6650 sites across six major oil and gas producing regions in Canada to examine regional emission trends, and to derive an inventory estimate for Canada’s upstream oil and gas sector. Emissions varied by fluid type and geographic region, with the heavy oil region of Lloydminster ranking highest on both absolute and intensity-based scales. Emission intensities varied widely for natural gas production, where older, low-producing developments such as Medicine Hat, Alberta showed high emission intensities, and newer developments in Montney, British Columbia showed emission intensities that are amongst the lowest in North America. Overall, we estimate that the Canadian upstream oil and gas methane inventory is underestimated by a factor of 1.5, which is consistent with previous studies of individual regions.

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Background Hundreds of oil wells were drilled along Oil Creek in Pennsylvania in the mid-1800s, birthing the modern oil industry. No longer in operation, many wells are now classified as abandoned, and, due to their age, their locations are either unknown or inaccurately recorded. These historic well sites present environmental, safety, and economic concerns in the form of possible methane leaks and physical hazards. Methods Airborne magnetic and LiDAR surveys were conducted in the Pioneer Run watershed in Oil Creek State Park to find abandoned wells in a historically significant but physically challenging location. Wells were drilled in this area prior to modern geolocation and legal documentation. Although a large number of old wells were abandoned summarily without remediation of the site, much of the land area within Oil Creek State Park is now covered in trees and dense underbrush, which can obscure wellheads. The thick vegetation and steep terrain limited the possibility of ground-based surveys to easily find well sites for methane emissions studies. The data from remote sensing surveys were used to corroborate potential well locations from historic maps and photographs. Potential well sites were verified in a ground-based field survey and monitored for methane emissions. Results Two historic photographs documenting oil activity in the late 1800s were georeferenced using a combination of magnetic and LiDAR data. LiDAR data, which were more useful in georeferencing and in field verification, identified 290 field locations in the Pioneer Run watershed, 86% of which were possible well sites. Sixty-two percent of the ground-verified wells remained unplugged and comprised the majority of leaking wells. The mean methane emissions factor for unplugged wells was 0.027 ± 0.099 kg/day, lower than other Appalachian Basin methane emissions estimates. Conclusions LiDAR was used for the first time, in combination with an airborne magnetic survey, to reveal underground oil industry features and inform well identification and remediation efforts in difficult-to-navigate regions. In the oldest oil fields, where well casing has been removed or wood conductor casing was installed, historic photographs provide additional lines of evidence for oil wells where ground disturbances have concealed surface features. Identification of well sites is necessary for mitigation efforts, as unplugged wells emit methane, a potent greenhouse gas.

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Abandoned oil and gas wells are one of the most uncertain sources of methane emissions into the atmosphere. To reduce these uncertainties and improve emission estimates, we geospatially and statistically analyze 598 direct methane emission measurements from abandoned oil and gas wells and aggregate well counts from regional databases for the United States (U.S.) and Canada. We estimate the number of abandoned wells to be at least 4,000,000 wells for the U.S. and at least 370,000 for Canada. Methane emission factors range from 1.8 × 10–3 g/h to 48 g/h per well depending on the plugging status, well type, and region, with the overall average at 6.0 g/h. We find that annual methane emissions from abandoned wells are underestimated by 150% in Canada and by 20% in the U.S. Even with the inclusion of two to three times more measurement data than used in current inventory estimates, we find that abandoned wells remain the most uncertain methane source in the U.S. and become the most uncertain source in Canada. Understanding methane emissions from abandoned oil and gas wells can provide critical insights into broader environmental impacts of abandoned wells, which are rapidly growing in number around the world.

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In this study, a ground-based mobile measurement system was developed to provide rapid and cost-effective emission surveillance of both methane (CH4) and volatile organic compounds (VOCs) from oil and gas (O&G) production sites. After testing in several controlled release experiments, the system was deployed in a field campaign in the Eagle Ford basin, TX. We found fat-tail distributions for both methane and total VOC (C4–C12) emissions (e.g., the top 20% sites ranked according to methane and total VOC (C4–C12) emissions were responsible for ∼60 and ∼80% of total emissions, respectively) and a good correlation between them (Spearman’s R = 0.74). This result suggests that emission controls targeting relatively large emitters may help significantly reduce both methane and VOCs in oil and wet gas basins, such as the Eagle Ford. A strong correlation (Spearman’s R = 0.84) was found between total VOC (C4–C12) emissions estimated using SUMMA canisters and data reported from a local ambient air monitoring station. This finding suggests that this system has the potential for rapid emission surveillance targeting relatively large emitters, which can help achieve emission reductions for both greenhouse gas (GHG) and air toxics from O&G production well pads in a cost-effective way.

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This study explores the effect of different phases of unconventional shale gas well-pad development on ambient air quality and the relationship between ambient concentrations of air pollutants and operator activity. The U.S. Department of Energy’s National Energy Technology Laboratory operated a mobile air-monitoring laboratory on two shale well pad sites in Pennsylvania and six shale well pad sites in West Virginia. The purpose of this study is to integrate expert knowledge and collected ambient air monitoring data by developing a Bayesian network (BN) model. The monitoring period included well-pad site development; construction, including vertical and horizontal drilling; hydraulic fracturing; flowback; and production. The observed data includes meteorological data with high time resolution and air quality data (volatile organic compounds (VOCs), ozone, methane and carbon isotopes in methane, carbon dioxide (CO2) and carbon isotopes in CO2, coarse and fine particulate matter (PM10 and PM2.5), and organic and elemental carbon). The results provide useful information for evaluating the influence of on- and off-site pollutant sources and determining future research efforts for building the BN model. The overall results of the developed six scenarios show that the prediction power of the proposed model for the vertical drilling phase is 94%. The high concentration of methane increases the probability of fracturing phase as source; the low concentration of PM10 and O3 occurrence increases the same probability to 82%; the low concentration of ethane and CO2 increases the probability to 98%. This study shows how expert Bayesian models can improve our ability to predict future air pollution risk associated with unconventional shale gas development.

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In 2014, a satellite-based map of regional anomalies of atmospheric methane (CH4) column retrievals singled out the fossil fuel rich San Juan Basin (SJB) as the biggest CH4 regional anomaly (“hot spot”) in the United States. Over a 3-week period in April 2015, we conducted ground and airborne atmospheric measurements to investigate daily wind regimes and CH4 emissions in this region of SW Colorado and NW New Mexico. The SJB, similar to other topographical basins with local sources, experienced elevated surface air pollution under low wind and surface temperature inversion at night and early morning. Survey drives in the basin identified multiple CH4 and ethane (C2H6) sources with distinct C2H6-to-CH4 emission plume ratios for coal bed methane (CBM), natural gas, oil, and coal production operations. Air samples influenced by gas seepage from the Fruitland coal formation outcrop in La Plata County, CO, had enhanced CH4, with no C2-5 light alkane enhancements. In situ fast-response data from seven basin survey flights, all with westerly winds, were used to map and attribute the detected C2H6 and CH4 emission plumes. C2H6-to-CH4 plume enhancement correlation slopes increased from north to south, reflecting the composition of the natural gas and/or CBM extracted in different parts of the basin. Nearly 75% of the total detected CH4 and 85% of the total detected C2H6 hot spot were located in New Mexico. Emissions from CBM and natural gas operations contributed 66% to 75% of the CH4 hot spot. Emissions from oil operations in New Mexico contributed 5% to 6% of the CH4 hot spot and 8% to 14% of the C2H6 hot spot. Seepage from the Fruitland coal outcrop in Colorado contributed at most 8% of the total detected CH4, while gas venting from the San Juan underground coal mine contributed <2%.

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California hosts ∼124,000 abandoned and plugged (AP) oil and gas wells, ∼38,000 idle wells, and ∼63,000 active wells, whose methane (CH4) emissions remain largely unquantified at levels below ∼2 kg CH4 h–1. We sampled 121 wells using two methods: a rapid mobile plume integration method (detection ∼0.5 g CH4 h–1) and a more sensitive static flux chamber (detection ∼1 × 10–6 g CH4 h–1). We measured small but detectable methane emissions from 34 of 97 AP wells (mean emission: 0.286 g CH4 h–1). In contrast, we found emissions from 11 of 17 idle wells—which are not currently producing (mean: 35.4 g CH4 h–1)—4 of 6 active wells (mean: 189.7 g CH4 h–1), and one unplugged well—an open casing with no infrastructure present (10.9 g CH4 h–1). Our results support previous findings that emissions from plugged wells are low but are more substantial from idle wells. In addition, our smaller sample of active wells suggests that their reported emissions are consistent with previous studies and deserve further attention. Due to limited access, we could not measure wells in most major active oil and gas fields in California; therefore, we recommend additional data collection from all types of wells but especially active and idle wells.

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Methane emission fluxes were estimated for 71 oil and gas well pads in the western Permian Basin (Delaware Basin), using a mobile laboratory and an inverse Gaussian dispersion method (OTM 33A). Sites with emissions that were below detection limit (BDL) for OTM 33A were recorded and included in the sample. Average emission rate per site was estimated by bootstrapping and by maximum likelihood best log-normal fit. Sites had to be split into “complex” (sites with liquid storage tanks and/or compressors) and “simple” (sites with only wellheads/pump jacks/separators) categories to achieve acceptable log-normal fits. For complex sites, the log-normal fit depends heavily on the number of BDL sites included. As more BDL sites are included, the log-normal distribution fit to the data is falsely widened, overestimating the mean, highlighting the importance of correctly characterizing low end emissions when using log-normal fits. Basin-wide methane emission rates were estimated for the production sector of the New Mexico portion of the Permian and range from ∼520 000 tons per year, TPY (bootstrapping, 95% CI: 300 000–790 000) to ∼610 000 TPY (log-normal fit method, 95% CI: 330 000–1 000 000). These estimates are a factor of 5.5–9.0 times greater than EPA National Emission Inventory (NEI) estimates for the region.

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Recent studies have reported methane (CH4) emissions from abandoned oil and gas wells across the United States and the United Kingdom. These emissions can reach hundreds of kg CH4 per year per well and are important to include in greenhouse gas emission inventories and mitigation strategies. Emission estimates are generally based on single, short-term measurements that assume constant emission rates over both short (hours) and longer (months/years) time periods. To investigate this assumption, we measure CH4 emissions from 18 abandoned oil and gas wells in the USA and the UK continuously over 24 h and then make repeat 24 -h measurements at a single site over 12 months. While the lack of historical records for these wells makes it impossible to determine the underlying leakage-pathways, we observed that CH4 emissions at all wells varied over 24 h (range 0.2-81,000 mg CH4 hr−1) with average emissions varying by a factor of 18 and ranging from factors of 1.1–142. We did not find a statistically significant relationship between the magnitude of emissions and variability or that variability is correlated with temperature, relative humidity or atmospheric pressure. The results presented here suggest high CH4 emission events tend to be short-lived, so short-term (< 1 h) sampling is likely to miss them. Our findings present the dynamic nature of CH4 emissions from abandoned oil and gas wells which should be considered when planning measurement methodologies and developing greenhouse gas inventories/mitigation strategies. Incorporation of these temporal dynamics could improve national greenhouse gas emissions inventories.

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As natural gas has grown in importance as a global energy source, leakage of methane (CH4) from wells has been noted. Leakage of this greenhouse gas is important because it affects groundwater quality and, when emitted to the atmosphere, climate. We hypothesized that streams might be most contaminated by CH4 in the northern Appalachian Basin in regions with the longest history of hydrocarbon extraction activities. To test this, we searched for CH4-contaminated streams basin. Methane concentrations ([CH4]) for 529 stream sites are reported, in New York, West Virginia and mostly Pennsylvania. Despite targeting contaminated areas, the median [CH4], 1.1 μg/L, was lower than a recently identified threshold indicating potential contamination, 4.0 μg/L. [CH4] values were higher in a few streams because they receive high-[CH4] groundwaters, often from upwelling seeps. By analogy to the more commonly observed type of groundwater seep known as abandoned mine drainage (AMD), we introduce the term, “gas leak discharge” (GLD) for these waters where they are not associated with coal mines. GLD and AMD, observed in all parts of the study area, are both CH4-rich. Surprisingly, the region of oldest and most productive oil/gas development did not show the highest median for stream [CH4]. Instead, the median was statistically highest where dense coal mining was accompanied by conventional and unconventional oil and gas development, emphasizing the importance of CH4 contamination from coal mines into streams.

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Oil/gas well integrity failures are a common but poorly constrained source of methane emissions to the atmosphere. As of 2014, Pennsylvania requires gas and oil well operators to report gas losses, both fugitive and process, from all active and unplugged abandoned gas and oil wells. We analyze 589,175 operator reports and find that lower-bound reported annual methane emissions averaged 22.1 Gg (-16.9, +19.5) between 2014 and 2018 from 62,483 wells, an average of only 47% of the statewide well inventory for those years. Extrapolating to the 2019 oil and gas well inventory yields well average emissions of 55.6 Gg CH4. These emissions are not currently included in the state’s oil and gas emissions inventory. We also assess compliance in reporting among operators and note anomalies in reporting and apparent workarounds to reduce reported emissions. Suggestions for improving the accuracy and reliability in reporting and reducing emissions are offered.

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Hydraulic fracturing (hydrofracking) for natural gas has increased rapidly in the area of the Marcellus Shale in the last thirty years but estimates of CH4 emissions from hydrofracking operations are still uncertain. Previous studies on CH4 emissions at hydrofracking operations have used bottom-up approaches collected at discrete timepoints or discrete aerial surveys covering a wide spatial area, constraining the temporal scale of inference regarding these emissions. This project monitored atmospheric CH4 concentrations and stable carbon isotopes at a half-hourly temporal resolution from a 20-m tower downwind of a hydrofracking well pad in West Virginia for eighteen months. We collected four months of baseline observations prior to onsite well development to construct an empirical artificial neural-network model of baseline CH4 concentrations. We compared the CH4 concentrations against the ANN-modeled CH4 baseline to identify CH4 concentration spikes that coincided with different stages of onsite well development, from the baseline period through fracking. CH4 concentration spikes were significantly more frequent than baseline conditions during the vertical drilling and fracking phases of operations. We found that the median magnitude of CH4 concentration spikes during the vertical drilling phase was 316% larger than that of the baseline phase, and the median magnitude of CH4 concentration spikes was 509% larger in the hydraulic stimulation (fracking) stage compared to the baseline phase. We also partitioned the sources of measured CH4 concentrations to biogenic ruminant and geologic shale gas isotopic signatures by measuring 13CH4 gas at high temporal resolution and using a source-partitioning 13CH4 model. The measured median value of half-hourly CH4 concentration spikes attributed to a geologic shale gas isotopic origin was 27% larger than the median CH4 concentration spikes attributed to ruminants, and the maximum half-hourly CH4 concentration spike attributed to shale gas was up to 179% higher than maximum CH4 concentration spike for ruminant-dominated half-hours. This study developed a framework for off-site, single tower measurements to identify CH4 concentration spikes associated with the phases of unconventional natural gas well development in a complex CH4 emissions airshed.

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Isotopic evidence from ice cores indicates that preindustrial-era geological methane emissions were lower than previously thought, suggesting that present-day emissions of methane from fossil fuels are underestimated.

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During the 2004–16 shale-gas development in the Appalachian basin, United States, premature mortality from lower air quality and employment followed a boom-and-bust cycle, whereas climate impacts will persist for generations beyond the activity.

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We report a 24-month statistical baseline climatology for continuously-measured atmospheric carbon dioxide (CO2) and methane (CH4) mixing ratios linked to surface meteorology as part of a wider environmental baselining project tasked with understanding pre-existing local environmental conditions prior to shale gas exploration in the United Kingdom. The baseline was designed to statistically characterise high-precision measurements of atmospheric composition gathered over two full years (between February 1st 2016 and January 31st 2018) at fixed ground-based measurement stations on, or near to, two UK sites being developed for shale gas exploration involving hydraulic fracturing. The sites, near Blackpool (Lancashire) and Kirby Misperton (North Yorkshire), were the first sites approved in the UK for shale gas exploration since a moratorium was lifted in England. The sites are operated by Cuadrilla Resources Ltd. and Third Energy Ltd., respectively. A statistical climatology of greenhouse gas mixing ratios linked to prevailing local surface meteorology is presented. This study diagnoses and interprets diurnal, day-of-week, and seasonal trends in measured mixing ratios and the contributory role of local, regional and long-range emission sources. The baseline provides a set of contextual statistical quantities against which the incremental impacts of new activities (in this case, future shale gas exploration) can be quantitatively assessed. The dataset may also serve to inform the design of future case studies, as well as direct baseline monitoring design at other potential shale gas and industrial sites. In addition, it provides a quantitative reference for future analyses of the impact, and efficacy, of specific policy interventions or mitigating practices. For example, statistically significant excursions in measured concentrations from this baseline (e.g. >99th percentile) observed during phases of operational extraction may be used to trigger further examination in order to diagnose the source(s) of emission and links to on-site activities at the time, which may be of importance to regulators, site operators and public health stakeholders. A guideline algorithm for identifying these statistically significant excursions, or “baseline deviation events”, from the expected baseline conditions is presented and tested. Gaussian plume modelling is used to further these analyses, by simulating approximate upper-limits of CH4 fluxes which could be expected to give observable enhancements at the monitoring stations under defined meteorological conditions.

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Well plugging, the main strategy for reducing methane emissions from millions of unplugged abandoned oil and gas (AOG) wells in the U.S. and abroad, is expensive and many wells remain unplugged. In addition, plugging does not necessarily reduce methane emissions and some categories of plugged wells are high emitters. We analyze strategies and costs of five options for reducing methane emissions from high-emitting AOG wells - those which are unplugged and plugged/vented gas wells. The five options are: plugging without gas venting, plugging with gas venting and flaring, plugging with gas venting and usage, gas flaring only, and gas capture/usage only. Average plugging costs ($37,000 per well) can be justified by the social cost of methane, which considers air quality, climate, and human/ecosystem impacts. Savings as measured by natural gas prices and alternative energy credits can offset low plugging costs (<$15,400 per well) but are not large enough to offset average plugging costs. Nonetheless, reducing methane emissions from AOG wells is a cost-effective strategy for addressing climate change that has comparable costs to some current greenhouse gas mitigation options and can produce co-benefits such as groundwater protection. Therefore, we recommend including the mitigation of AOG wells in climate and energy policies in the U.S., Canada, and other oil-and-gas-producing regions.

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Since advances in horizontal drilling and hydraulic fracturing technologies have opened oil and gas development in previously unreachable areas, air pollution emissions have increased from the burning (i.e., flaring) or releasing (i.e., venting) of natural gas at oil and gas extraction sites. While venting and flaring is a growing concern, accounting of how much gas is vented and flared, and where this occurs, remains limited. The purpose of this paper is to describe two methods for estimating venting and flaring volumes - self-reports required by state law and satellite imagery radiant heat measurements - and to compare these methods using the case of Texas Eagle Ford and Permian Basin venting and flaring practices from 2012 to 2015. First, we used data self-reported by companies to the Texas Railroad Commission (TxRRC), and National Oceanic and Atmospheric Administration (NOAA) data captured by satellite-based Visible Infrared Imaging Radiometer Suite sensors, to estimate the annual total volumes of gas vented and flared in the Eagle Ford and Permian Basin from 2012 to 2015. Next, we developed a method using a geographic information system to link and compare TxRRC and NOAA county-based and point-based volume estimates. Finally, we conducted case studies of two oil and gas fields to better understand how TxRRC and NOAA venting and flaring volumes differ. We find both TxRRC and NOAA estimated venting and/or flaring volumes steadily increased from 2012 to 2015. Additionally, TxRRC reports captured about half the volumes estimated by NOAA. This suggests that self-reported volumes significantly underestimate the volume of gas being vented or flared. However, this research is limited by the data currently available. As such, future research and policy should further develop methods to systemically capture the extent to which oil and gas extraction facilities vent and flare natural gas.

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Greenhouse gases (GHGs) produced by the extraction of natural gas are an important contributor to lifecycle emissions and account for a significant fraction of anthropogenic methane emissions in the USA. The timing as well as the magnitude of these emissions matters, as the short term climate warming impact of methane is up to 120 times that of CO2. This study uses estimates of CO2 and methane emissions associated with different upstream operations to build a deterministic model of GHG emissions from conventional and unconventional gas fields as a function of time. By combining these emissions with a dynamic, techno-economic model of gas supply we assess their potential impact on the value of different types of project and identify stranded resources in various carbon price scenarios. We focus in particular on the effects of different emission metrics for methane, using the global warming potential (GWP) and the global temperature potential (GTP), with both fixed 20-year and 100-year CO2-equivalent values and in a time-dependent way based on a target year for climate stabilisation. We report a strong time dependence of emissions over the lifecycle of a typical field, and find that bringing forward the stabilisation year dramatically increases the importance of the methane contribution to these emissions. Using a commercial database of the remaining reserves of individual projects, we use our model to quantify future emissions resulting from the extraction of current US non-associated reserves. A carbon price of at least 400 USD/tonne CO2 is effective in reducing cumulative GHGs by 30–60%, indicating that decarbonising the upstream component of the natural gas supply chain is achievable using carbon prices similar to those needed to decarbonise the energy system as a whole. Surprisingly, for large carbon prices, the choice of emission metric does not have a significant impact on cumulative emissions.

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Article: Emission scenarios of a potential shale gas industry in Germany and the United Kingdom

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The Bacharach Hi Flow® Sampler (BHFS) has been widely used to monitor methane leaks from industrial sources, however results have been challenged due to possible instrument performance issues. This study focused on improving the understanding of the BHFS performance by investigating its characteristics and potential failure modes. BHFS operation was split into three modes: catalytic oxidation (CO), thermal conductivity (TC) and a transition region. Good linear performance was observed in CO and TC modes (R2 > 0.992), however, the calibration factor changed between experiments highlighting the importance of regular calibration. Measurements in the middle region were dominated by noise with poor linearity. Instrument failure due to high non-methane hydrocarbons occurred sometimes; a hypothesis to explain this has been established. We found the BHFS to be a suitable instrument for measuring methane emissions if operated correctly and with knowledge of its limitations. Some key operational guidelines are provided in the conclusions.

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A large-scale study of methane emissions from well pads was conducted in the Marcellus shale (Pennsylvania), the largest producing natural gas shale play in the United States, to better identify the prevalence and characteristics of superemitters. Roughly 2100 measurements were taken from 673 unique unconventional well pads corresponding to ∼18% of the total population of active sites and ∼32% of the total statewide unconventional natural gas production. A log-normal distribution with a geometric mean of 2.0 kg h–1 and arithmetic mean of 5.5 kg h–1 was observed, which agrees with other independent observations in this region. The geometric standard deviation (4.4 kg h–1) compared well to other studies in the region, but the top 10% of emitters observed in this study contributed 77% of the total emissions, indicating an extremely skewed distribution. The integrated proportional loss of this representative sample was equal to 0.53% with a 95% confidence interval of 0.45–0.64% of the total production of the sites, which is greater than the U.S. Environmental Protection Agency inventory estimate (0.29%), but in the lower range of other mobile observations (0.09–3.3%). These results emphasize the need for a sufficiently large sample size when characterizing emissions distributions that contain superemitters.

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Recent studies show conflicting estimates of trends in methane (CH4) emissions from oil and natural gas (ONG) operations in the U.S. We analyze atmospheric CH4 measurements from 20 North American sites in the NOAA Global Greenhouse Gas Reference Network and determined trends for 2006-2015. Using CH4 vertical gradients as an indicator of regional surface emissions, we find no significant increase in emissions at most sites and modest increases at three sites heavily influenced by ONG activities. Our estimated increases in North American ONG CH4 emissions (on average 3.4 ± 1.4 % yr-1 for 2006-2015, ±σ) are much smaller than estimates from some previous studies and below our detection threshold for total emissions increases at the east coast sites that are sensitive to U.S. outflows. We also find an increasing trend in ethane/methane emission ratios which has resulted in major overestimation of oil and gas emissions trends in some previous studies.

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Natural gas (NG) from shale formations (or shale gas) is an unconventional energy resource whose potential environmental impacts are still not adequately assessed. Hence, this study performs a Life Cycle Assessment (LCA) of shale gas considering a gas well under appraisal in Burgos, Spain. An attributional model was developed, considering the NG pre-production and production phases in the system boundaries, considering 1 MJ of processed NG as a functional unit. Results were obtained through the CML-IA baseline method (developed by the Center of Environmental Science of Leiden University) and showed that well design, drilling and casing, hydraulic fracturing, NG production, gathering, and processing are critical processes. To better address the environmental impacts, a comparison with similar studies was carried out, as well as a sensitivity and an uncertainty analysis using Monte Carlo simulation (MCS). The model was found to be particularly sensitive to water usage in hydraulic fracturing and to the number of workovers with hydraulic fracturing. Limited data availability for shale gas exploration still poses a challenge for an accurate LCA. Even though shale gas remains controversial, it still can be considered as a strategic energy resource, requiring a precautionary approach when considering its exploitation and exploration.

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The recent advent of shale gas in the U.S. has redefined the economics of ethylene manufacturing globally, causing a shift towards low-cost U.S. production due to natural gas feedstock, while reinforcing the industry’s reliance on fossil fuels. At the same time, the global climate change crisis compels a transition to a low-carbon economy. These two influencing factors are complex, contested, and uncertain. This paper projects the United States’ (U.S.) future ethylene supply in the context of two megatrends: the natural gas surge and global climate change. The analysis models the future U.S. supply of ethylene in 2050 based on plausible socio-economic scenarios in response to climate change mitigation and adaptation pathways as well as a range of natural gas feedstock prices. This Vector Error Correction Model explores the relationships between these variables. The results show that ethylene supply increased in nearly all modeled scenarios. A combination of lower population growth, lower consumption, and higher natural gas prices reduced ethylene supply by 2050. In most cases, forecasted CO2 emissions from ethylene production rose. This is the first study to project future ethylene supply to go beyond the price of feedstocks and include socio-economic variables relevant to climate change mitigation and adaptation.

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This study spatially and temporally aligns top-down and bottom-up methane emission estimates for a natural gas production basin, using multiscale emission measurements and detailed activity data reporting. We show that episodic venting from manual liquid unloadings, which occur at a small fraction of natural gas well pads, drives a factor-of-two temporal variation in the basin-scale emission rate of a US dry shale gas play. The midafternoon peak emission rate aligns with the sampling time of all regional aircraft emission studies, which target well-mixed boundary layer conditions present in the afternoon. A mechanistic understanding of emission estimates derived from various methods is critical for unbiased emission verification and effective greenhouse gas emission mitigation. Our results demonstrate that direct comparison of emission estimates from methods covering widely different timescales can be misleading.

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The Marcellus Shale Energy and Environment Laboratory (MSEEL) in West Virginia provides a unique opportunity in the field of unconventional energy research. By studying near-surface atmospheric chemistry over several phases of a hydraulic fracturing event, the project will help evaluate the impact of current practices, as well as new techniques and mitigation technologies. A total of 10 mobile surveys covering a distance of approximately 1500 km were conducted through Morgantown. Our surveying technique involved using a vehicle-mounted Los Gatos Research gas analyzer to provide geo-located measurements of methane (CH4) and carbon dioxide (CO2). The ratios of super-ambient concentrations of CO2 and CH4 were used to separate well-pad emissions from the natural background concentrations over the various stages of well-pad development, as well as for comparisons to other urban sources of CH4. We found that regional background methane concentrations were elevated in all surveys, with a mean concentration of 2.699 ± 0.006 ppmv, which simply reflected the complexity of this riverine urban location. Emissions at the site were the greatest during the flow-back phase, with an estimated CH4 volume output of 20.62 ± 7.07 g/s, which was significantly higher than other identified urban emitters. Our study was able to successfully identify and quantify MSEEL emissions within this complex urban environment.

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We used site-level methane (CH4) emissions data from over 1,000 natural gas (NG) production sites in eight basins, including 92 new site-level CH4 measurements in the Uinta, northeastern Marcellus, and Denver-Julesburg basins, to investigate CH4 emissions characteristics and develop a new national CH4 emission estimate for the NG production sector. The distribution of site-level emissions is highly skewed, with the top 5% of sites accounting for 50% of cumulative emissions. High emitting sites are predominantly also high producing (>10 Mcfd). However, low NG production sites emit a comparably larger fraction of their CH4 production. When combined with activity data, we predict that this creates substantial variability in the basin-level CH4 emissions which, as a fraction of basin-level CH4 production, range from 0.90% for the Appalachian and Greater Green River to > 4.5% in the San Juan and San Joaquin. This suggests that much of the basin-level differences in production-normalized emissions reported by aircraft studies can be explained by differences in site size and distribution of site-level production rates. We estimate that NG production sites emit total CH4 emissions of 830 Mg/h (95% CI: 530—1,200), 63% of which come from the sites producing <100 Mcfd that account for only 10% of total NG production. Our total CH4 emissions estimate is 2.3 times higher than the U.S. EPA’s estimate and likely attributable to the disproportionate influence of high emitting sites.

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The recent growth in U.S. natural gas reserves has led to interest in exporting liquefied natural gas (LNG) to countries in Asia, Europe and Latin America. Here, we estimate the life cycle greenhouse gas (GHG) emissions and life cycle freshwater consumption associated with exporting Marcellus shale gas as LNG for power generation in different import markets. The well-to-wire analysis relies on operations data for gas production, processing, transmission, and regasification, while also accounting for the latest measurements of fugitive CH4 emissions from U.S. natural gas activities. To estimate GHG emissions from a typical U.S. liquefaction facility, we use a bottom-up process model that can evaluate the impact of gas composition, technology choices for gas treatment and on-site power generation on overall facility GHG emissions. For LNG exports to Mumbai, India for power generation in a combined cycle power plant with 50% efficiency, the base case life cycle GHG emissions, freshwater consumption, and CH4 emissions as fraction of gross gas production are estimated to be 473 kg CO2eq/MWh (80% confidence interval: 452–503 kg CO2eq/MWh), 243 gal/MWh (80% CI: 200–300 gal/MWh) and 1.2% (80% CI: 0.81–1.79%), respectively. Among all destinations considered, typical life cycle GHG emissions range from 459 kg CO2eq/MWh to 473 kg CO2eq/MWh, with GHG emissions from liquefaction, shipping and regasification contributing 7–10% of life cycle GHG emissions.

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. Large-eddy simulations (LES) coupled to a model that simulates methane emissions from oil and gas production facilities are used to generate realistic distributions of meteorological variables and methane concentrations. These are sampled to obtain simulated observations used to develop and evaluate source term estimation (STE) methods. A widely used EPA STE method (OTM33A) is found to provide emission estimates with little bias when averaged over six time-periods and seven well-pads. Sixty-four percent of the emissions estimated with OTM33A are within +/-30% of the simulated emissions, showing slightly larger spread than the 72% found previously using controlled release experiments. A newly developed method adopts the OTM33A sampling strategy and uses a variational or a stochastic STE approach coupled to an LES to obtain a better fit to the sampled meteorological conditions and to account for multiple sources within the well-pad. This method can considerably reduce the spread of the emissions estimates compared to OTM33A (92-95% within +/-30% percent error), but it is associated to a substantial increase in computational cost due to the LES. It thus provides an alternative when the additional costs can be afforded to obtain more precise emission estimates.

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The oil and gas extraction industry is an energy-intensive and high CO2 emission sector in China. This study estimates the cost-effective CO2 emission reduction potentials until 2050 by classifying key low-carbon technology bundles and investigating the energy efficiency, market penetration rate, and emission reduction cost of each technology bundle. A bottom-up technical evaluation model is established to give a comprehensive perspective to the Chinese oil and gas extraction industry and policymakers about the emission reduction potential and its associated cost. Results show that the carbon emission reduction potential in the Chinese oil and gas extraction industry in 2050 can reach 16.71 million tons in the case of all low-carbon technologies available and that the decrease rate can be as high as 14.3%. The contributions of emission reductions are mainly the improvement of energy efficiency, the transformation of production process, and the utilization of new energy sources. Most low-carbon technologies are cost-effective, with an average annual cost savings of 71.43 billion RMB. Nonetheless, the diffusions of low-carbon technologies are still significantly affected by energy price volatility and firms' expectations of future investment risk.

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Microbial Ecology![Figure][1] Microbes increase methane output from shale gas wells. CREDIT: NAMTHIP MUANTHONGTHAE/SHUTTERSTOCK Microbes are thought to contribute to chemical processes that occur during hydraulic fracturing of shale. How these communities develop after injection of fracking

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Methane emissions from the U.S. oil and natural gas supply chain were estimated using ground-based, facility-scale measurements and validated with aircraft observations in areas accounting for ~30% of U.S. gas production. When scaled up nationally, our facility-based estimate of 2015 supply chain emissions is 13 ± 2 Tg/y, equivalent to 2.3% of gross U.S. gas production. This value is ~60% higher than the U.S. EPA inventory estimate, likely because existing inventory methods miss emissions released during abnormal operating conditions. Methane emissions of this magnitude, per unit of natural gas consumed, produce radiative forcing over a 20-year time horizon comparable to the CO2 from natural gas combustion. Significant emission reductions are feasible through rapid detection of the root causes of high emissions and deployment of less failure-prone systems.

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Natural gas from shale plays dominates new production and growth. However, unconventional well development is an energy intensive process. The prime movers, which include over-the-road service trucks, horizontal drilling rigs, and hydraulic fracturing pumps, are predominately powered by diesel engines that impact air quality. Instead of relying on certification data or outdated emission factors, this model uses new in-use emissions and activity data combined with historical literature to develop a national emissions inventory. For the diesel only case, hydraulic fracturing engines produced the most NOx emissions, while drilling engines produced the most CO emissions, and truck engines produced the most THC emissions. By implementing dual-fuel and dedicated natural gas engines, total fuel energy consumed, CO2, CO, THC, and CH4 emissions would increase, while NOx emissions, diesel fuel consumption, and fuel costs would decrease. Dedicated natural gas engines offered significant reductions in NOx emissions. Additional scenarios examined extreme cases of full fleet conversions. While deep market penetrations could reduce fuel costs, both technologies could significantly increase CH4 emissions. While this model is based on a small sample size of engine configurations, data were collected during real in-use activity and is representative of real world activity.

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In Reply Drs Frumkin and Patz extend the dialogue begun in our Viewpoint on the potential health implications of fracking to include a discussion about climate change. We agree that regulatory agencies monitoring compliance need to be supported. We also agree with the need to further the dialogue...

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To the Editor Drs Wilke and Freeman provided a helpful discussion of air and water contamination related to fracking.1 However, they omitted key parts of the fracking story. First, methane leaks from fracked wells, sometimes in high quantities, likely accounting in part for recent observed increases...

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We measured fluxes of methane, a suite of non-methane hydrocarbons (C2–C11), light alcohols, and carbon dioxide from oil and gas produced water storage and disposal ponds in Utah (Uinta Basin) and Wyoming (Upper Green River Basin) United States during 2013–2016. In this paper, we discuss the characteristics of produced water composition and air-water fluxes, with a focus on flux chamber measurements. In companion papers, we will (1) report on inverse modeling methods used to estimate emissions from produced water ponds, including comparisons with flux chamber measurements, and (2) discuss the development of mass transfer coefficients to estimate emissions and place emissions from produced water ponds in the context of all regional oil and gas-related emissions. Alcohols (made up mostly of methanol) were the most abundant organic compound group in produced water (91% of total volatile organic concentration, with upper and lower 95% confidence levels of 89 and 93%) but accounted for only 34% (28 to 41%) of total organic compound fluxes from produced water ponds. Non-methane hydrocarbons, which are much less water-soluble than methanol and less abundant in produced water, accounted for the majority of emitted organics. C6–C9 alkanes and aromatics dominated hydrocarbon fluxes, perhaps because lighter hydrocarbons had already volatilized from produced water prior to its arrival in storage or disposal ponds, while heavier hydrocarbons are less water soluble and less volatile. Fluxes of formaldehyde and other carbonyls were low (1% (1 to 2%) of total organic compound flux). The speciation and magnitude of fluxes varied strongly across the facilities measured and with the amount of time water had been exposed to the atmosphere. The presence or absence of ice also impacted fluxes.

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Environmental and economic impacts of methane escaping from the natural gas supply chain remain uncertain. Flowback emissions from hydraulically fractured natural gas wells are a key component of emissions from unconventional gas wells. While reduced emission completions in the United States are required by regulation, Canada’s proposed regulation will only be implemented in 2020 with the two highest producing provinces under exemption. To understand potential benefits of regulations, we use predictive modelling of well-level production data of 1633 hydraulically fractured shale gas wells in five plays to estimate pre-production emissions. The mean estimate for flowback emissions (2,346±95% confidence interval of 91 Mg CO2e/completion) fall within the 95% confidence limits of measured potential emissions (2,566±777 Mg CO2e/completion). Our results indicate that in 2015, the average emissions per shale gas well undergoing flowback was 2,347 Mg CO2e/completion in the U.S. and 1,859 Mg CO2e/completion in Canada. Mean potential profits from controlling methane emissions using reduced emission completions were US$17,200/well in the U.S. and US$11,200/well in Canada.