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Repository for Oil and Gas Energy Research (ROGER)
The Repository for Oil and Gas Energy Research, or ROGER, is a near-exhaustive collection of bibliographic information, abstracts, and links to many of journal articles that pertain to shale and tight gas development. The goal of this project is to create a single repository for unconventional oil and gas-related research as a resource for academic, scientific, and citizen researchers.
ROGER currently includes 2303 studies.
Last updated: October 12, 2024
Search ROGER
Use keywords or categories (e.g., air quality, climate, health) to identify peer-reviewed studies and view study abstracts.
Topic Areas
Natural gas pipeline compressor stations: VOC emissions and mortality rates
Michael Hendryx and Juhua Luo, May 2020
Natural gas pipeline compressor stations: VOC emissions and mortality rates
Michael Hendryx and Juhua Luo (2020). The Extractive Industries and Society, . 10.1016/j.exis.2020.04.011
Abstract:
Increasing reliance on natural gas for energy has resulted in expansion of the natural gas infrastructure, including pipelines and compressor stations to transport gas. Compressor stations emit numerous particulate and gaseous pollutants including volatile organic compounds (VOCs) but studies of human health in association with compressor stations are almost completely absent from the literature. The objective of the study was to test for associations between VOC emissions from compressor stations and adjusted mortality rates. We conducted a county-level ecological study, using VOC emission data from the 2017 National Emissions Inventory, 2017 age-adjusted total mortality per 100,000 population from CDC data, and covariates from the County Health Rankings data. Results of multiple linear regression models showed that total age-adjusted mortality, controlling for covariates (race/ethnicity, education, poverty, urbanicity, smoking and obesity rates), was significantly higher in association with greater non-methane VOC emissions from compressor stations. Twelve individual VOCs were also associated with significantly higher adjusted mortality. Results provide preliminary evidence that compressor stations along natural gas pipelines are sources of pollutant exposures that may contribute to adverse human health outcomes.
Increasing reliance on natural gas for energy has resulted in expansion of the natural gas infrastructure, including pipelines and compressor stations to transport gas. Compressor stations emit numerous particulate and gaseous pollutants including volatile organic compounds (VOCs) but studies of human health in association with compressor stations are almost completely absent from the literature. The objective of the study was to test for associations between VOC emissions from compressor stations and adjusted mortality rates. We conducted a county-level ecological study, using VOC emission data from the 2017 National Emissions Inventory, 2017 age-adjusted total mortality per 100,000 population from CDC data, and covariates from the County Health Rankings data. Results of multiple linear regression models showed that total age-adjusted mortality, controlling for covariates (race/ethnicity, education, poverty, urbanicity, smoking and obesity rates), was significantly higher in association with greater non-methane VOC emissions from compressor stations. Twelve individual VOCs were also associated with significantly higher adjusted mortality. Results provide preliminary evidence that compressor stations along natural gas pipelines are sources of pollutant exposures that may contribute to adverse human health outcomes.
Quantifying alkane emissions in the Eagle Ford Shale using boundary layer enhancement
Geoffrey Roest and Gunnar Schade, September 2017
Quantifying alkane emissions in the Eagle Ford Shale using boundary layer enhancement
Geoffrey Roest and Gunnar Schade (2017). Atmospheric Chemistry and Physics, 11163-11176. 10.5194/acp-17-11163-2017
Abstract:
The Eagle Ford Shale in southern Texas is home to a booming unconventional oil and gas industry, the climate and air quality impacts of which remain poorly quantified due to uncertain emission estimates. We used the atmospheric enhancement of alkanes from Texas Commission on Environmental Quality volatile organic compound monitors across the shale, in combination with back trajectory and dispersion modeling, to quantify C-2-C-4 alkane emissions for a region in southern Texas, including the core of the Eagle Ford, for a set of 68 days from July 2013 to December 2015. Emissions were partitioned into raw natural gas and liquid storage tank sources using gas and headspace composition data, respectively, and observed enhancement ratios. We also estimate methane emissions based on typical ethane-to-methane ratios in gaseous emissions. The median emission rate from raw natural gas sources in the shale, calculated as a percentage of the total produced natural gas in the upwind region, was 0.7% with an interquartile range (IQR) of 0.5-1.3 %, below the US Environmental Protection Agency's (EPA) current estimates. However, storage tanks contributed 17% of methane emissions, 55% of ethane, 82% percent of propane, 90% of n-butane, and 83% of isobutane emissions. The inclusion of liquid storage tank emissions results in a median emission rate of 1.0% (IQR of 0.7-1.6 %) relative to produced natural gas, overlapping the current EPA estimate of roughly 1.6 %. We conclude that emissions from liquid storage tanks are likely a major source for the observed non-methane hydrocarbon enhancements in the Northern Hemisphere.
The Eagle Ford Shale in southern Texas is home to a booming unconventional oil and gas industry, the climate and air quality impacts of which remain poorly quantified due to uncertain emission estimates. We used the atmospheric enhancement of alkanes from Texas Commission on Environmental Quality volatile organic compound monitors across the shale, in combination with back trajectory and dispersion modeling, to quantify C-2-C-4 alkane emissions for a region in southern Texas, including the core of the Eagle Ford, for a set of 68 days from July 2013 to December 2015. Emissions were partitioned into raw natural gas and liquid storage tank sources using gas and headspace composition data, respectively, and observed enhancement ratios. We also estimate methane emissions based on typical ethane-to-methane ratios in gaseous emissions. The median emission rate from raw natural gas sources in the shale, calculated as a percentage of the total produced natural gas in the upwind region, was 0.7% with an interquartile range (IQR) of 0.5-1.3 %, below the US Environmental Protection Agency's (EPA) current estimates. However, storage tanks contributed 17% of methane emissions, 55% of ethane, 82% percent of propane, 90% of n-butane, and 83% of isobutane emissions. The inclusion of liquid storage tank emissions results in a median emission rate of 1.0% (IQR of 0.7-1.6 %) relative to produced natural gas, overlapping the current EPA estimate of roughly 1.6 %. We conclude that emissions from liquid storage tanks are likely a major source for the observed non-methane hydrocarbon enhancements in the Northern Hemisphere.
Identification and evaluation of well integrity and causes of failure of well integrity barriers (A review)
Kiran et al., September 2017
Identification and evaluation of well integrity and causes of failure of well integrity barriers (A review)
Raj Kiran, Catalin Teodoriu, Younas Dadmohammadi, Runar Nygaard, David Wood, Mehdi Mokhtari, Saeed Salehi (2017). Journal of Natural Gas Science and Engineering, 511-526. 10.1016/j.jngse.2017.05.009
Abstract:
Volatile markets and harsh locations and downhole conditions pose severe challenges for ensuring safe and long-lasting intact well conditions. Well integrity is a crucial issue in the life cycle of all sub-surface boreholes. Failure of wellbore integrity leads not only to negative financial consequences, but also potentially to significant environmental impacts, such as groundwater contamination, gas leakage to the atmosphere, and fluid spills and seepage at the surface. Many studies have specifically focused on well integrity issues related to particular types of conventional and unconventional oil and gas reservoirs. Specific types of wells and well operations (e.g., high pressure high temperature, enhanced oil and gas recovery, deepwater, water and gas injection, geothermal, and plugging and abandonment) pose their specific issues. To understand the barriers to well integrity, and what is required to sustain it, a holistic study encompassing a wide range of issues is highly required. From a practical point of view, there are several factors affecting well integrity issues which can be classified based on chemical, mechanical, and operational factors. The consequence of these well integrity issues is mainly the fluid migration over time within or escaping from the wells. Past studies reveal that well integrity barriers are highly impacted by cement carbonation and casing corrosion processes, fluid migration, in-situ conditions, cement and casing mechanical properties. Cement is the main physical barrier able to seal fluid flow into unintended zones from the wellbore. The sealing efficiency of cement is highly dependent on in-situ environment conditions and cement chemical compositions, influencing the time-dependent stress geometry in the vicinity of wellbores. Casing corrosion is another challenging issue which is often unavoidable due to acidic environments imposed mainly by CO2 and H2S "sour" gasses. Modern studies have also shown the importance of cement fatigue degradation. Pressure regulation during production and temperature variation are the most common influencing variables impacting the mechanical aspects of well integrity. These variables induce extra stresses on the established barriers which can initiate and/or promote fluid migration. In addition, to chemical and mechanical aspects of well integrity, operational interventions can play crucial roles in improving well integrity. This aspect contributes to establishing zonal isolation, not limited to, but specific requirements of plugging and abandonment operations. Continuous evaluation and monitoring using different logging techniques and tests during drilling, completion, and production are required to address the issues that compromise the robustness of the well integrity. Nuances of the interpretation of multiple well logs must be understood in order to effectively respond to the potentially damaging situation, without risking the amplification of negative downhole conditions. Well integrity compensatory factors such as pressure, temperature, chemical changes, corrosion are interdependent. For instance, the variation in temperature or chemical changes will affect the extent of corrosion, hence a comprehensive design and monitoring system is essential to clearly understand the well integrity issues. This paper presents a broad review of research and field experiences related to well integrity. (C) 2017 Elsevier B.V. All rights reserved.
Volatile markets and harsh locations and downhole conditions pose severe challenges for ensuring safe and long-lasting intact well conditions. Well integrity is a crucial issue in the life cycle of all sub-surface boreholes. Failure of wellbore integrity leads not only to negative financial consequences, but also potentially to significant environmental impacts, such as groundwater contamination, gas leakage to the atmosphere, and fluid spills and seepage at the surface. Many studies have specifically focused on well integrity issues related to particular types of conventional and unconventional oil and gas reservoirs. Specific types of wells and well operations (e.g., high pressure high temperature, enhanced oil and gas recovery, deepwater, water and gas injection, geothermal, and plugging and abandonment) pose their specific issues. To understand the barriers to well integrity, and what is required to sustain it, a holistic study encompassing a wide range of issues is highly required. From a practical point of view, there are several factors affecting well integrity issues which can be classified based on chemical, mechanical, and operational factors. The consequence of these well integrity issues is mainly the fluid migration over time within or escaping from the wells. Past studies reveal that well integrity barriers are highly impacted by cement carbonation and casing corrosion processes, fluid migration, in-situ conditions, cement and casing mechanical properties. Cement is the main physical barrier able to seal fluid flow into unintended zones from the wellbore. The sealing efficiency of cement is highly dependent on in-situ environment conditions and cement chemical compositions, influencing the time-dependent stress geometry in the vicinity of wellbores. Casing corrosion is another challenging issue which is often unavoidable due to acidic environments imposed mainly by CO2 and H2S "sour" gasses. Modern studies have also shown the importance of cement fatigue degradation. Pressure regulation during production and temperature variation are the most common influencing variables impacting the mechanical aspects of well integrity. These variables induce extra stresses on the established barriers which can initiate and/or promote fluid migration. In addition, to chemical and mechanical aspects of well integrity, operational interventions can play crucial roles in improving well integrity. This aspect contributes to establishing zonal isolation, not limited to, but specific requirements of plugging and abandonment operations. Continuous evaluation and monitoring using different logging techniques and tests during drilling, completion, and production are required to address the issues that compromise the robustness of the well integrity. Nuances of the interpretation of multiple well logs must be understood in order to effectively respond to the potentially damaging situation, without risking the amplification of negative downhole conditions. Well integrity compensatory factors such as pressure, temperature, chemical changes, corrosion are interdependent. For instance, the variation in temperature or chemical changes will affect the extent of corrosion, hence a comprehensive design and monitoring system is essential to clearly understand the well integrity issues. This paper presents a broad review of research and field experiences related to well integrity. (C) 2017 Elsevier B.V. All rights reserved.
Linear infrastructure drives habitat conversion and forest fragmentation associated with Marcellus shale gas development in a forested landscape
Langlois et al., July 2017
Linear infrastructure drives habitat conversion and forest fragmentation associated with Marcellus shale gas development in a forested landscape
Lillie A. Langlois, Patrick J. Drohan, Margaret C. Brittingham (2017). Journal of Environmental Management, 167-176. 10.1016/j.jenvman.2017.03.045
Abstract:
Large, continuous forest provides critical habitat for some species of forest dependent wildlife. The rapid expansion of shale gas development within the northern Appalachians results in direct loss of such habitat at well sites, pipelines, and access roads; however the resulting habitat fragmentation surrounding such areas may be of greater importance. Previous research has suggested that infrastructure supporting gas development is the driver for habitat loss, but knowledge of what specific infrastructure affects habitat is limited by a lack of spatial tracking of infrastructure development in different land uses. We used high-resolution aerial imagery, land cover data, and well point data to quantify shale gas development across four time periods (2010, 2012, 2014, 2016), including: the number of wells permitted, drilled, and producing gas (a measure of pipeline development); land use change; and forest fragmentation on both private and public land. As of April 2016, the majority of shale gas development was located on private land (74% of constructed well pads); however, the number of wells drilled per pad was lower on private compared to public land (3.5 and 5.4, respectively). Loss of core forest was more than double on private than public land (4.3 and 2.0%, respectively), which likely results from better management practices implemented on public land. Pipelines were by far the largest contributor to the fragmentation of core forest due to shale gas development. Forecasting future land use change resulting from gas development suggests that the greatest loss of core forest will occur with pads constructed farthest from pre-existing pipelines (new pipelines must be built to connect pads) and in areas with greater amounts of core forest. To reduce future fragmentation, our results suggest new pads should be placed near pre-existing pipelines and methods to consolidate pipelines with other infrastructure should be used. Without these mitigation practices, we will continue to lose core forest as a result of new pipelines and infrastructure particularly on private land.
Large, continuous forest provides critical habitat for some species of forest dependent wildlife. The rapid expansion of shale gas development within the northern Appalachians results in direct loss of such habitat at well sites, pipelines, and access roads; however the resulting habitat fragmentation surrounding such areas may be of greater importance. Previous research has suggested that infrastructure supporting gas development is the driver for habitat loss, but knowledge of what specific infrastructure affects habitat is limited by a lack of spatial tracking of infrastructure development in different land uses. We used high-resolution aerial imagery, land cover data, and well point data to quantify shale gas development across four time periods (2010, 2012, 2014, 2016), including: the number of wells permitted, drilled, and producing gas (a measure of pipeline development); land use change; and forest fragmentation on both private and public land. As of April 2016, the majority of shale gas development was located on private land (74% of constructed well pads); however, the number of wells drilled per pad was lower on private compared to public land (3.5 and 5.4, respectively). Loss of core forest was more than double on private than public land (4.3 and 2.0%, respectively), which likely results from better management practices implemented on public land. Pipelines were by far the largest contributor to the fragmentation of core forest due to shale gas development. Forecasting future land use change resulting from gas development suggests that the greatest loss of core forest will occur with pads constructed farthest from pre-existing pipelines (new pipelines must be built to connect pads) and in areas with greater amounts of core forest. To reduce future fragmentation, our results suggest new pads should be placed near pre-existing pipelines and methods to consolidate pipelines with other infrastructure should be used. Without these mitigation practices, we will continue to lose core forest as a result of new pipelines and infrastructure particularly on private land.
Integrating membrane distillation with waste heat from natural gas compressor stations for produced water treatment in Pennsylvania
Lokare et al., July 2017
Integrating membrane distillation with waste heat from natural gas compressor stations for produced water treatment in Pennsylvania
Omkar R. Lokare, Sakineh Tavakkoli, Gianfranco Rodriguez, Vikas Khanna, Radisav D. Vidic (2017). Desalination, 144-153. 10.1016/j.desal.2017.03.022
Abstract:
Direct contact membrane distillation (DCMD) has immense potential in the desalination of highly saline waste-waters where reverse osmosis is not feasible. This study evaluated the potential of DCMD for treatment of produced water generated during extraction of natural gas from unconventional (shale) reservoirs. Exhaust stream from Natural Gas Compressor Station (NG CS), which has been identified as a potential waste heat source, can be used to operate DCMD thereby providing economically viable option to treat high salinity produced water. An ASPEN Plus simulation of DCMD for the desalination of produced/saline water was developed in this study and calibrated using laboratory-scale experiments. This model was used to optimize the design and operation of large scale systems and estimate energy requirements of the DCMD process. The concept of minimum temperature approach used in heat exchanger design was applied to determine the optimum membrane area for large scale DCMD plants. Energy analysis revealed that the waste heat available from NG CS is sufficient to concentrate all the produced water generated in Pennsylvania to 30 wt% regardless of its initial salinity. (C) 2017 Elsevier B.V. All rights reserved.
Direct contact membrane distillation (DCMD) has immense potential in the desalination of highly saline waste-waters where reverse osmosis is not feasible. This study evaluated the potential of DCMD for treatment of produced water generated during extraction of natural gas from unconventional (shale) reservoirs. Exhaust stream from Natural Gas Compressor Station (NG CS), which has been identified as a potential waste heat source, can be used to operate DCMD thereby providing economically viable option to treat high salinity produced water. An ASPEN Plus simulation of DCMD for the desalination of produced/saline water was developed in this study and calibrated using laboratory-scale experiments. This model was used to optimize the design and operation of large scale systems and estimate energy requirements of the DCMD process. The concept of minimum temperature approach used in heat exchanger design was applied to determine the optimum membrane area for large scale DCMD plants. Energy analysis revealed that the waste heat available from NG CS is sufficient to concentrate all the produced water generated in Pennsylvania to 30 wt% regardless of its initial salinity. (C) 2017 Elsevier B.V. All rights reserved.
Rapid, Vehicle-Based Identification of Location and Magnitude of Urban Natural Gas Pipeline Leaks
Fischer et al., March 2017
Rapid, Vehicle-Based Identification of Location and Magnitude of Urban Natural Gas Pipeline Leaks
Joseph C. von Fischer, Daniel Cooley, Sam Chamberlain, Adam Gaylord, Claire J. Griebenow, Steven P. Hamburg, Jessica Salo, Russ Schumacher, David Theobald, Jay Ham (2017). Environmental Science & Technology, . 10.1021/acs.est.6b06095
Abstract:
Information about the location and magnitudes of natural gas (NG) leaks from urban distribution pipelines is important for minimizing greenhouse gas emissions and optimizing investment in pipeline management. To enable rapid collection of such data, we developed a relatively simple method using high-precision methane analyzers in Google Street View cars. Our data indicate that this automated leak survey system can document patterns in leak location and magnitude within and among cities, even without wind data. We found that urban areas with prevalent corrosion-prone distribution lines (Boston, MA, Staten Island, NY, and Syracuse, NY), leaked approximately 25-fold more methane than cities with more modern pipeline materials (Burlington, VT, and Indianapolis, IN). Although this mobile monitoring method produces conservative estimates of leak rates and leak counts, it can still help prioritize both leak repairs and replacement of leak-prone sections of distribution lines, thus minimizing methane emissions over short and long terms.
Information about the location and magnitudes of natural gas (NG) leaks from urban distribution pipelines is important for minimizing greenhouse gas emissions and optimizing investment in pipeline management. To enable rapid collection of such data, we developed a relatively simple method using high-precision methane analyzers in Google Street View cars. Our data indicate that this automated leak survey system can document patterns in leak location and magnitude within and among cities, even without wind data. We found that urban areas with prevalent corrosion-prone distribution lines (Boston, MA, Staten Island, NY, and Syracuse, NY), leaked approximately 25-fold more methane than cities with more modern pipeline materials (Burlington, VT, and Indianapolis, IN). Although this mobile monitoring method produces conservative estimates of leak rates and leak counts, it can still help prioritize both leak repairs and replacement of leak-prone sections of distribution lines, thus minimizing methane emissions over short and long terms.
System-wide and Superemitter Policy Options for the Abatement of Methane Emissions from the U.S. Natural Gas System
Mayfield et al., February 2017
System-wide and Superemitter Policy Options for the Abatement of Methane Emissions from the U.S. Natural Gas System
Erin Noel Mayfield, Allen L. Robinson, Jared L. Cohon (2017). Environmental Science & Technology, . 10.1021/acs.est.6b05052
Abstract:
This paper assesses tradeoffs between system-wide and superemitter policy options for reducing methane emissions from compressor stations in the U.S. transmission and storage system. Leveraging recently collected national emissions and activity datasets, we developed a new processed-based emissions model implemented in a Monte Carlo simulation framework to estimate emissions for each component and facility in the system. We find that approximately 83% of emissions, given the existing suite of technologies, have the potential to be abated, with only a few emission categories comprising a majority of emissions. We then formulate optimization models to determine optimal abatement strategies. Most emissions across the system (approximately 80%) are efficient to abate, resulting in net benefits ranging from $160M to $1.2B annually across the system. The private cost burden is minimal under standard and tax instruments, and if firms market the abated natural gas, private net benefits may be generated. Superemitter policies, namely those that target the highest emitting facilities, may reduce the private cost burden and achieve high emission reductions, especially if emissions across facilities are highly skewed. However, detection across all facilities is necessary regardless of the policy option and there are nontrivial net benefits resulting from abatement of relatively low-emitting sources.
This paper assesses tradeoffs between system-wide and superemitter policy options for reducing methane emissions from compressor stations in the U.S. transmission and storage system. Leveraging recently collected national emissions and activity datasets, we developed a new processed-based emissions model implemented in a Monte Carlo simulation framework to estimate emissions for each component and facility in the system. We find that approximately 83% of emissions, given the existing suite of technologies, have the potential to be abated, with only a few emission categories comprising a majority of emissions. We then formulate optimization models to determine optimal abatement strategies. Most emissions across the system (approximately 80%) are efficient to abate, resulting in net benefits ranging from $160M to $1.2B annually across the system. The private cost burden is minimal under standard and tax instruments, and if firms market the abated natural gas, private net benefits may be generated. Superemitter policies, namely those that target the highest emitting facilities, may reduce the private cost burden and achieve high emission reductions, especially if emissions across facilities are highly skewed. However, detection across all facilities is necessary regardless of the policy option and there are nontrivial net benefits resulting from abatement of relatively low-emitting sources.
Risk assessment of oil and gas pipelines with consideration of induced seismicity and internal corrosion
Oleg Shabarchin and Solomon Tesfamariam, October 2024
Risk assessment of oil and gas pipelines with consideration of induced seismicity and internal corrosion
Oleg Shabarchin and Solomon Tesfamariam (2024). Journal of Loss Prevention in the Process Industries, . 10.1016/j.jlp.2017.03.002
Abstract:
Over the last decade, unconventional oil and gas production has increased due to use of hydraulic fracturing and second oil recovery techniques. However, this activity is followed by prevalence of induced seismicity and has the potential to damage pipelines. The integrity of these pipelines is essential for oil and gas companies, regulator organizations, and stakeholders due to adverse environmental consequences and significant financial losses. Therefore, it is important to investigate a potential impact of the induced seismicity on the pipeline infrastructure in order to enhance informed decision making (e.g. permitting decisions). To accomplish this task, this paper presents a probabilistic seismic risk assessment approach, which has been used for pipeline infrastructure located in the Northeast of British Columbia, Canada. Spatial clustering analysis is used for earthquakes, previously registered in the region, to delineate areas, which are particularly prone to the induced seismicity. The state-of-the-art ground motion prediction equation for induced seismicity is applied in Monte Carlo simulation to obtain a stochastic field of the seismic intensity. Based on the pipelines’ seismic fragility formulations as well as its mechanical characteristics and corrosion conditions, spatial and probabilistic distributions of the repair rate and probability of failure have been obtained and visualized with the aid of the Geospatial Information System.
Over the last decade, unconventional oil and gas production has increased due to use of hydraulic fracturing and second oil recovery techniques. However, this activity is followed by prevalence of induced seismicity and has the potential to damage pipelines. The integrity of these pipelines is essential for oil and gas companies, regulator organizations, and stakeholders due to adverse environmental consequences and significant financial losses. Therefore, it is important to investigate a potential impact of the induced seismicity on the pipeline infrastructure in order to enhance informed decision making (e.g. permitting decisions). To accomplish this task, this paper presents a probabilistic seismic risk assessment approach, which has been used for pipeline infrastructure located in the Northeast of British Columbia, Canada. Spatial clustering analysis is used for earthquakes, previously registered in the region, to delineate areas, which are particularly prone to the induced seismicity. The state-of-the-art ground motion prediction equation for induced seismicity is applied in Monte Carlo simulation to obtain a stochastic field of the seismic intensity. Based on the pipelines’ seismic fragility formulations as well as its mechanical characteristics and corrosion conditions, spatial and probabilistic distributions of the repair rate and probability of failure have been obtained and visualized with the aid of the Geospatial Information System.
Characterization of methane plumes downwind of natural gas compressor stations in Pennsylvania and New York
Jr et al., December 2016
Characterization of methane plumes downwind of natural gas compressor stations in Pennsylvania and New York
Bryce F. Payne Jr, Robert Ackley, A. Paige Wicker, Zacariah L. Hildenbrand, Doug D. Carlton Jr, Kevin A. Schug (2016). Science of The Total Environment, . 10.1016/j.scitotenv.2016.12.082
Abstract:
The extraction of unconventional oil and natural gas from shale energy reservoirs has raised concerns regarding upstream and midstream activities and their potential impacts on air quality. Here we present in situ measurements of ambient methane concentrations near multiple natural gas compressor stations in New York and Pennsylvania using cavity ring-down laser spectrometry coupled with global positioning system technology. These data reveal discernible methane plumes located proximally to compressor stations, which exhibit high variability in their methane emissions depending on the weather conditions and on-site activities. During atmospheric temperature inversions, when near-ground mixing of the atmosphere is limited or does not occur, residents and properties located within 1 mile of a compressor station can be exposed to rogue methane from these point sources. These data provide important insight into the characterization and potential for optimization of natural gas compressor station operations.
The extraction of unconventional oil and natural gas from shale energy reservoirs has raised concerns regarding upstream and midstream activities and their potential impacts on air quality. Here we present in situ measurements of ambient methane concentrations near multiple natural gas compressor stations in New York and Pennsylvania using cavity ring-down laser spectrometry coupled with global positioning system technology. These data reveal discernible methane plumes located proximally to compressor stations, which exhibit high variability in their methane emissions depending on the weather conditions and on-site activities. During atmospheric temperature inversions, when near-ground mixing of the atmosphere is limited or does not occur, residents and properties located within 1 mile of a compressor station can be exposed to rogue methane from these point sources. These data provide important insight into the characterization and potential for optimization of natural gas compressor station operations.
Methane emissions measurements of natural gas components using a utility terrain vehicle and portable methane quantification system
Derek Johnson and Robert Heltzel, November 2016
Methane emissions measurements of natural gas components using a utility terrain vehicle and portable methane quantification system
Derek Johnson and Robert Heltzel (2016). Atmospheric Environment, 1-7. 10.1016/j.atmosenv.2016.08.065
Abstract:
Greenhouse Gas (GHG) emissions are a growing problem in the United States (US). Methane (CH4) is a potent GHG produced by several stages of the natural gas sector. Current scrutiny focuses on the natural gas boom associated with unconventional shale gas; however, focus should still be given to conventional wells and outdated equipment. In an attempt to quantify these emissions, researchers modified an off-road utility terrain vehicle (UTV) to include a Full Flow Sampling system (FFS) for methane quantification. GHG emissions were measured from non-producing and remote low throughput natural gas components in the Marcellus region. Site audits were conducted at eleven locations and leaks were identified and quantified at seven locations including at a low throughput conventional gas and oil well, two out-of-service gathering compressors, a conventional natural gas well, a coalbed methane well, and two conventional and operating gathering compressors. No leaks were detected at the four remaining sites, all of which were coal bed methane wells. The total methane emissions rate from all sources measured was 5.3 ± 0.23 kg/hr, at a minimum.
Greenhouse Gas (GHG) emissions are a growing problem in the United States (US). Methane (CH4) is a potent GHG produced by several stages of the natural gas sector. Current scrutiny focuses on the natural gas boom associated with unconventional shale gas; however, focus should still be given to conventional wells and outdated equipment. In an attempt to quantify these emissions, researchers modified an off-road utility terrain vehicle (UTV) to include a Full Flow Sampling system (FFS) for methane quantification. GHG emissions were measured from non-producing and remote low throughput natural gas components in the Marcellus region. Site audits were conducted at eleven locations and leaks were identified and quantified at seven locations including at a low throughput conventional gas and oil well, two out-of-service gathering compressors, a conventional natural gas well, a coalbed methane well, and two conventional and operating gathering compressors. No leaks were detected at the four remaining sites, all of which were coal bed methane wells. The total methane emissions rate from all sources measured was 5.3 ± 0.23 kg/hr, at a minimum.
Metabolic Capability of a Predominant Halanaerobium sp. in Hydraulically Fractured Gas Wells and Its Implication in Pipeline Corrosion
Liang et al., June 2016
Metabolic Capability of a Predominant Halanaerobium sp. in Hydraulically Fractured Gas Wells and Its Implication in Pipeline Corrosion
Renxing Liang, Irene A. Davidova, Christopher R. Marks, Blake W. Stamps, Brian H. Harriman, Bradley S. Stevenson, Kathleen E. Duncan, Joseph M. Suflita (2016). Microbiotechnology, Ecotoxicology and Bioremediation, 988. 10.3389/fmicb.2016.00988
Abstract:
Microbial activity associated with produced water from hydraulic fracturing operations can lead to gas souring and corrosion of carbon-steel equipment. We examined the microbial ecology of produced water and the prospective role of the prevalent microorganisms in corrosion in a gas production field in the Barnett Shale. The microbial community was mainly composed of halophilic, sulfidogenic bacteria within the order Halanaerobiales, which reflected the geochemical conditions of highly saline water containing sulfur species (S2O32-, SO42-, and HS-). A predominant, halophilic bacterium (strain DL-01) was subsequently isolated and identified as belonging to the genus Halanaerobium. The isolate could degrade guar gum, a polysaccharide polymer used in fracture fluids, to produce acetate and sulfide in a 10% NaCl medium at 37°C when thiosulfate was available. To mitigate potential deleterious effects of sulfide and acetate, a quaternary ammonium compound was found to be an efficient biocide in inhibiting the growth and metabolic activity of strain DL-01 relative to glutaraldehyde and tetrakis (hydroxymethyl) phosphonium sulfate. Collectively, our findings suggest that predominant halophiles associated with unconventional shale gas extraction could proliferate and produce sulfide and acetate from the metabolism of polysaccharides used in hydraulic fracturing fluids. These metabolic products might be returned to the surface and transported in pipelines to cause pitting corrosion in downstream infrastructure.
Microbial activity associated with produced water from hydraulic fracturing operations can lead to gas souring and corrosion of carbon-steel equipment. We examined the microbial ecology of produced water and the prospective role of the prevalent microorganisms in corrosion in a gas production field in the Barnett Shale. The microbial community was mainly composed of halophilic, sulfidogenic bacteria within the order Halanaerobiales, which reflected the geochemical conditions of highly saline water containing sulfur species (S2O32-, SO42-, and HS-). A predominant, halophilic bacterium (strain DL-01) was subsequently isolated and identified as belonging to the genus Halanaerobium. The isolate could degrade guar gum, a polysaccharide polymer used in fracture fluids, to produce acetate and sulfide in a 10% NaCl medium at 37°C when thiosulfate was available. To mitigate potential deleterious effects of sulfide and acetate, a quaternary ammonium compound was found to be an efficient biocide in inhibiting the growth and metabolic activity of strain DL-01 relative to glutaraldehyde and tetrakis (hydroxymethyl) phosphonium sulfate. Collectively, our findings suggest that predominant halophiles associated with unconventional shale gas extraction could proliferate and produce sulfide and acetate from the metabolism of polysaccharides used in hydraulic fracturing fluids. These metabolic products might be returned to the surface and transported in pipelines to cause pitting corrosion in downstream infrastructure.
Natural Gas Pipeline Replacement Programs Reduce Methane Leaks and Improve Consumer Safety
Gallagher et al., September 2015
Natural Gas Pipeline Replacement Programs Reduce Methane Leaks and Improve Consumer Safety
Morgan E. Gallagher, Adrian Down, Robert C. Ackley, Kaiguang Zhao, Nathan Phillips, Robert B. Jackson (2015). Environmental Science & Technology Letters, 286-291. 10.1021/acs.estlett.5b00213
Abstract:
From production through distribution, oil and gas infrastructure provides the largest source of anthropogenic methane in the United States and the second largest globally. Using a Picarro G2132i Cavity Ring-Down spectrometer, we mapped natural gas leaks across the streets of three United States cities?Durham, NC, Cincinnati, OH, and Manhattan, NY?at different stages of pipeline replacement of cast iron and other older materials. We identified 132, 351, and 1050 leaks in Durham, Cincinnati, and Manhattan, respectively, across 595, 750, and 247 road miles driven. Leak densities were an order of magnitude lower for Durham and Cincinnati (0.22 and 0.47 leaks/mi, respectively) than for Manhattan (4.25 leaks/mi) and two previously mapped cities, Boston (4.28 leaks/mi) and Washington, DC (3.93 leaks/mi). Cities with successful pipeline replacement programs have 90% fewer leaks per mile than cities without such programs. Similar programs around the world should provide additional environmental, economic, and consumer safety benefits.
From production through distribution, oil and gas infrastructure provides the largest source of anthropogenic methane in the United States and the second largest globally. Using a Picarro G2132i Cavity Ring-Down spectrometer, we mapped natural gas leaks across the streets of three United States cities?Durham, NC, Cincinnati, OH, and Manhattan, NY?at different stages of pipeline replacement of cast iron and other older materials. We identified 132, 351, and 1050 leaks in Durham, Cincinnati, and Manhattan, respectively, across 595, 750, and 247 road miles driven. Leak densities were an order of magnitude lower for Durham and Cincinnati (0.22 and 0.47 leaks/mi, respectively) than for Manhattan (4.25 leaks/mi) and two previously mapped cities, Boston (4.28 leaks/mi) and Washington, DC (3.93 leaks/mi). Cities with successful pipeline replacement programs have 90% fewer leaks per mile than cities without such programs. Similar programs around the world should provide additional environmental, economic, and consumer safety benefits.
Atmospheric Mercury in the Barnett Shale Area, Texas: Implications for Emissions from Oil and Gas Processing
Lan et al., September 2015
Atmospheric Mercury in the Barnett Shale Area, Texas: Implications for Emissions from Oil and Gas Processing
Xin Lan, Robert Talbot, Patrick Laine, Azucena Torres, Barry Lefer, James Flynn (2015). Environmental Science & Technology, 10692-10700. 10.1021/acs.est.5b02287
Abstract:
Atmospheric mercury emissions in the Barnett Shale area were studied by employing both stationary measurements and mobile laboratory surveys. Stationary measurements near the Engle Mountain Lake showed that the median mixing ratio of total gaseous mercury (THg) was 138 ppqv (140 ± 29 ppqv for mean ± S.D.) during the June 2011 study period. A distinct diurnal variation pattern was observed in which the highest THg levels appeared near midnight, followed by a monotonic decrease until midafternoon. The influence of oil and gas (ONG) emissions was substantial in this area, as inferred from the i-pentane/n-pentane ratio (1.17). However, few THg plumes were captured by our mobile laboratory during a ?3700 km survey with detailed downwind measurements from 50 ONG facilities. One compressor station and one natural gas condensate processing facility were found to have significant THg emissions, with maximum THg levels of 963 and 392 ppqv, respectively, and the emissions rates were estimated to be 7.9 kg/yr and 0.3 kg/yr, respectively. Our results suggest that the majority of ONG facilities in this area are not significant sources of THg; however, it is highly likely that a small number of these facilities contribute a relatively large amount of emissions in the ONG sector.
Atmospheric mercury emissions in the Barnett Shale area were studied by employing both stationary measurements and mobile laboratory surveys. Stationary measurements near the Engle Mountain Lake showed that the median mixing ratio of total gaseous mercury (THg) was 138 ppqv (140 ± 29 ppqv for mean ± S.D.) during the June 2011 study period. A distinct diurnal variation pattern was observed in which the highest THg levels appeared near midnight, followed by a monotonic decrease until midafternoon. The influence of oil and gas (ONG) emissions was substantial in this area, as inferred from the i-pentane/n-pentane ratio (1.17). However, few THg plumes were captured by our mobile laboratory during a ?3700 km survey with detailed downwind measurements from 50 ONG facilities. One compressor station and one natural gas condensate processing facility were found to have significant THg emissions, with maximum THg levels of 963 and 392 ppqv, respectively, and the emissions rates were estimated to be 7.9 kg/yr and 0.3 kg/yr, respectively. Our results suggest that the majority of ONG facilities in this area are not significant sources of THg; however, it is highly likely that a small number of these facilities contribute a relatively large amount of emissions in the ONG sector.
Methane Emissions from United States Natural Gas Gathering and Processing
Marchese et al., August 2015
Methane Emissions from United States Natural Gas Gathering and Processing
Anthony J. Marchese, Timothy L. Vaughn, Daniel J. Zimmerle, David M. Martinez, Laurie L. Williams, Allen L. Robinson, Austin L. Mitchell, R. Subramanian, Daniel S. Tkacik, Joseph R. Roscioli, Scott C. Herndon (2015). Environmental Science & Technology, 10718-10727. 10.1021/acs.est.5b02275
Abstract:
New facility-level methane (CH4) emissions measurements obtained from 114 natural gas gathering facilities and 16 processing plants in 13 U.S. states were combined with facility counts obtained from state and national databases in a Monte Carlo simulation to estimate CH4 emissions from U.S. natural gas gathering and processing operations. Total annual CH4 emissions of 2421 (+245/?237) Gg were estimated for all U.S. gathering and processing operations, which represents a CH4 loss rate of 0.47% (±0.05%) when normalized by 2012 CH4 production. Over 90% of those emissions were attributed to normal operation of gathering facilities (1697 +189/?185 Gg) and processing plants (506 +55/-52 Gg), with the balance attributed to gathering pipelines and processing plant routine maintenance and upsets. The median CH4 emissions estimate for processing plants is a factor of 1.7 lower than the 2012 EPA Greenhouse Gas Inventory (GHGI) estimate, with the difference due largely to fewer reciprocating compressors, and a factor of 3.0 higher than that reported under the EPA Greenhouse Gas Reporting Program. Since gathering operations are currently embedded within the production segment of the EPA GHGI, direct comparison to our results is complicated. However, the study results suggest that CH4 emissions from gathering are substantially higher than the current EPA GHGI estimate and are equivalent to 30% of the total net CH4 emissions in the natural gas systems GHGI. Because CH4 emissions from most gathering facilities are not reported under the current rule and not all source categories are reported for processing plants, the total CH4 emissions from gathering and processing reported under the EPA GHGRP (180 Gg) represents only 14% of that tabulated in the EPA GHGI and 7% of that predicted from this study.
New facility-level methane (CH4) emissions measurements obtained from 114 natural gas gathering facilities and 16 processing plants in 13 U.S. states were combined with facility counts obtained from state and national databases in a Monte Carlo simulation to estimate CH4 emissions from U.S. natural gas gathering and processing operations. Total annual CH4 emissions of 2421 (+245/?237) Gg were estimated for all U.S. gathering and processing operations, which represents a CH4 loss rate of 0.47% (±0.05%) when normalized by 2012 CH4 production. Over 90% of those emissions were attributed to normal operation of gathering facilities (1697 +189/?185 Gg) and processing plants (506 +55/-52 Gg), with the balance attributed to gathering pipelines and processing plant routine maintenance and upsets. The median CH4 emissions estimate for processing plants is a factor of 1.7 lower than the 2012 EPA Greenhouse Gas Inventory (GHGI) estimate, with the difference due largely to fewer reciprocating compressors, and a factor of 3.0 higher than that reported under the EPA Greenhouse Gas Reporting Program. Since gathering operations are currently embedded within the production segment of the EPA GHGI, direct comparison to our results is complicated. However, the study results suggest that CH4 emissions from gathering are substantially higher than the current EPA GHGI estimate and are equivalent to 30% of the total net CH4 emissions in the natural gas systems GHGI. Because CH4 emissions from most gathering facilities are not reported under the current rule and not all source categories are reported for processing plants, the total CH4 emissions from gathering and processing reported under the EPA GHGRP (180 Gg) represents only 14% of that tabulated in the EPA GHGI and 7% of that predicted from this study.
Methane Emissions from the Natural Gas Transmission and Storage System in the United States
Zimmerle et al., July 2015
Methane Emissions from the Natural Gas Transmission and Storage System in the United States
Daniel J. Zimmerle, Laurie L. Williams, Timothy L. Vaughn, Casey Quinn, R. Subramanian, Gerald P. Duggan, Bryan Willson, Jean D. Opsomer, Anthony J. Marchese, David M. Martinez, Allen L. Robinson (2015). Environmental Science & Technology, 9374-9383. 10.1021/acs.est.5b01669
Abstract:
The recent growth in production and utilization of natural gas offers potential climate benefits, but those benefits depend on lifecycle emissions of methane, the primary component of natural gas and a potent greenhouse gas. This study estimates methane emissions from the transmission and storage (T&S) sector of the United States natural gas industry using new data collected during 2012, including 2,292 onsite measurements, additional emissions data from 677 facilities and activity data from 922 facilities. The largest emission sources were fugitive emissions from certain compressor-related equipment and ?super-emitter? facilities. We estimate total methane emissions from the T&S sector at 1,503 [1,220 to 1,950] Gg/yr (95% confidence interval) compared to the 2012 Environmental Protection Agency?s Greenhouse Gas Inventory (GHGI) estimate of 2,071 [1,680 to 2,690] Gg/yr. While the overlap in confidence intervals indicates that the difference is not statistically significant, this is the result of several significant, but offsetting, factors. Factors which reduce the study estimate include a lower estimated facility count, a shift away from engines toward lower-emitting turbine and electric compressor drivers, and reductions in the usage of gas-driven pneumatic devices. Factors that increase the study estimate relative to the GHGI include updated emission rates in certain emission categories and explicit treatment of skewed emissions at both component and facility levels. For T&S stations that are required to report to the EPA?s Greenhouse Gas Reporting Program (GHGRP), this study estimates total emissions to be 260% [215% to 330%] of the reportable emissions for these stations, primarily due to the inclusion of emission sources that are not reported under the GHGRP rules, updated emission factors, and super-emitter emissions.
The recent growth in production and utilization of natural gas offers potential climate benefits, but those benefits depend on lifecycle emissions of methane, the primary component of natural gas and a potent greenhouse gas. This study estimates methane emissions from the transmission and storage (T&S) sector of the United States natural gas industry using new data collected during 2012, including 2,292 onsite measurements, additional emissions data from 677 facilities and activity data from 922 facilities. The largest emission sources were fugitive emissions from certain compressor-related equipment and ?super-emitter? facilities. We estimate total methane emissions from the T&S sector at 1,503 [1,220 to 1,950] Gg/yr (95% confidence interval) compared to the 2012 Environmental Protection Agency?s Greenhouse Gas Inventory (GHGI) estimate of 2,071 [1,680 to 2,690] Gg/yr. While the overlap in confidence intervals indicates that the difference is not statistically significant, this is the result of several significant, but offsetting, factors. Factors which reduce the study estimate include a lower estimated facility count, a shift away from engines toward lower-emitting turbine and electric compressor drivers, and reductions in the usage of gas-driven pneumatic devices. Factors that increase the study estimate relative to the GHGI include updated emission rates in certain emission categories and explicit treatment of skewed emissions at both component and facility levels. For T&S stations that are required to report to the EPA?s Greenhouse Gas Reporting Program (GHGRP), this study estimates total emissions to be 260% [215% to 330%] of the reportable emissions for these stations, primarily due to the inclusion of emission sources that are not reported under the GHGRP rules, updated emission factors, and super-emitter emissions.
Aircraft-Based Measurements of Point Source Methane Emissions in the Barnett Shale Basin
Lavoie et al., July 2015
Aircraft-Based Measurements of Point Source Methane Emissions in the Barnett Shale Basin
Tegan N. Lavoie, Paul B. Shepson, Maria O. L. Cambaliza, Brian H. Stirm, Anna Karion, Colm Sweeney, Tara I. Yacovitch, Scott C. Herndon, Xin Lan, David Lyon (2015). Environmental Science & Technology, 7904-7913. 10.1021/acs.est.5b00410
Abstract:
We report measurements of methane (CH4) emission rates observed at eight different high-emitting point sources in the Barnett Shale, Texas, using aircraft-based methods performed as part of the Barnett Coordinated Campaign. We quantified CH4 emission rates from four gas processing plants, one compressor station, and three landfills during five flights conducted in October 2013. Results are compared to other aircraft- and surface-based measurements of the same facilities, and to estimates based on a national study of gathering and processing facilities emissions and 2013 annual average emissions reported to the U.S. EPA Greenhouse Gas Reporting Program (GHGRP). For the eight sources, CH4 emission measurements from the aircraft-based mass balance approach were a factor of 3.2?5.8 greater than the GHGRP-based estimates. Summed emissions totaled 7022 ± 2000 kg hr?1, roughly 9% of the entire basin-wide CH4 emissions estimated from regional mass balance flights during the campaign. Emission measurements from five natural gas management facilities were 1.2?4.6 times larger than emissions based on the national study. Results from this study were used to represent ?super-emitters? in a newly formulated Barnett Shale Inventory, demonstrating the importance of targeted sampling of ?super-emitters? that may be missed by random sampling of a subset of the total.
We report measurements of methane (CH4) emission rates observed at eight different high-emitting point sources in the Barnett Shale, Texas, using aircraft-based methods performed as part of the Barnett Coordinated Campaign. We quantified CH4 emission rates from four gas processing plants, one compressor station, and three landfills during five flights conducted in October 2013. Results are compared to other aircraft- and surface-based measurements of the same facilities, and to estimates based on a national study of gathering and processing facilities emissions and 2013 annual average emissions reported to the U.S. EPA Greenhouse Gas Reporting Program (GHGRP). For the eight sources, CH4 emission measurements from the aircraft-based mass balance approach were a factor of 3.2?5.8 greater than the GHGRP-based estimates. Summed emissions totaled 7022 ± 2000 kg hr?1, roughly 9% of the entire basin-wide CH4 emissions estimated from regional mass balance flights during the campaign. Emission measurements from five natural gas management facilities were 1.2?4.6 times larger than emissions based on the national study. Results from this study were used to represent ?super-emitters? in a newly formulated Barnett Shale Inventory, demonstrating the importance of targeted sampling of ?super-emitters? that may be missed by random sampling of a subset of the total.
Methane Emissions from Leak and Loss Audits of Natural Gas Compressor Stations and Storage Facilities
Johnson et al., July 2015
Methane Emissions from Leak and Loss Audits of Natural Gas Compressor Stations and Storage Facilities
Derek R. Johnson, April N. Covington, Nigel N. Clark (2015). Environmental Science & Technology, 8132-8138. 10.1021/es506163m
Abstract:
As part of the Environmental Defense Fund?s Barnett Coordinated Campaign, researchers completed leak and loss audits for methane emissions at three natural gas compressor stations and two natural gas storage facilities. Researchers employed microdilution high-volume sampling systems in conjunction with in situ methane analyzers, bag samples, and Fourier transform infrared analyzers for emissions rate quantification. All sites had a combined total methane emissions rate of 94.2 kg/h, yet only 12% of the emissions total resulted from leaks. Methane slip from exhausts represented 44% of the total emissions. Remaining methane emissions were attributed to losses from pneumatic actuators and controls, engine crankcases, compressor packing vents, wet seal vents, and slop tanks. Measured values were compared with those reported in literature. Exhaust methane emissions were lower than emissions factor estimates for engine exhausts, but when combined with crankcase emissions, measured values were 11.4% lower than predicted by AP-42 as applicable to emissions factors for four-stroke, lean-burn engines. Average measured wet seal emissions were 3.5 times higher than GRI values but 14 times lower than those reported by Allen et al. Reciprocating compressor packing vent emissions were 39 times higher than values reported by GRI, but about half of values reported by Allen et al. Though the data set was small, researchers have suggested a method to estimate site-wide emissions factors for those powered by four-stroke, lean-burn engines based on fuel consumption and site throughput.
As part of the Environmental Defense Fund?s Barnett Coordinated Campaign, researchers completed leak and loss audits for methane emissions at three natural gas compressor stations and two natural gas storage facilities. Researchers employed microdilution high-volume sampling systems in conjunction with in situ methane analyzers, bag samples, and Fourier transform infrared analyzers for emissions rate quantification. All sites had a combined total methane emissions rate of 94.2 kg/h, yet only 12% of the emissions total resulted from leaks. Methane slip from exhausts represented 44% of the total emissions. Remaining methane emissions were attributed to losses from pneumatic actuators and controls, engine crankcases, compressor packing vents, wet seal vents, and slop tanks. Measured values were compared with those reported in literature. Exhaust methane emissions were lower than emissions factor estimates for engine exhausts, but when combined with crankcase emissions, measured values were 11.4% lower than predicted by AP-42 as applicable to emissions factors for four-stroke, lean-burn engines. Average measured wet seal emissions were 3.5 times higher than GRI values but 14 times lower than those reported by Allen et al. Reciprocating compressor packing vent emissions were 39 times higher than values reported by GRI, but about half of values reported by Allen et al. Though the data set was small, researchers have suggested a method to estimate site-wide emissions factors for those powered by four-stroke, lean-burn engines based on fuel consumption and site throughput.
Constructing a Spatially Resolved Methane Emission Inventory for the Barnett Shale Region
Lyon et al., July 2015
Constructing a Spatially Resolved Methane Emission Inventory for the Barnett Shale Region
David R. Lyon, Daniel Zavala-Araiza, Ramón A. Alvarez, Robert Harriss, Virginia Palacios, Xin Lan, Robert Talbot, Tegan Lavoie, Paul Shepson, Tara I. Yacovitch, Scott C. Herndon, Anthony J. Marchese, Daniel Zimmerle, Allen L. Robinson, Steven P. Hamburg (2015). Environmental Science & Technology, 8147-8157. 10.1021/es506359c
Abstract:
Methane emissions from the oil and gas industry (O&G) and other sources in the Barnett Shale region were estimated by constructing a spatially resolved emission inventory. Eighteen source categories were estimated using multiple data sets, including new empirical measurements at regional O&G sites and a national study of gathering and processing facilities. Spatially referenced activity data were compiled from federal and state databases and combined with O&G facility emission factors calculated using Monte Carlo simulations that account for high emission sites representing the very upper portion, or fat-tail, in the observed emissions distributions. Total methane emissions in the 25-county Barnett Shale region in October 2013 were estimated to be 72,300 (63,400?82,400) kg CH4 h?1. O&G emissions were estimated to be 46,200 (40,000?54,100) kg CH4 h?1 with 19% of emissions from fat-tail sites representing less than 2% of sites. Our estimate of O&G emissions in the Barnett Shale region was higher than alternative inventories based on the United States Environmental Protection Agency (EPA) Greenhouse Gas Inventory, EPA Greenhouse Gas Reporting Program, and Emissions Database for Global Atmospheric Research by factors of 1.5, 2.7, and 4.3, respectively. Gathering compressor stations, which accounted for 40% of O&G emissions in our inventory, had the largest difference from emission estimates based on EPA data sources. Our inventory?s higher O&G emission estimate was due primarily to its more comprehensive activity factors and inclusion of emissions from fat-tail sites.
Methane emissions from the oil and gas industry (O&G) and other sources in the Barnett Shale region were estimated by constructing a spatially resolved emission inventory. Eighteen source categories were estimated using multiple data sets, including new empirical measurements at regional O&G sites and a national study of gathering and processing facilities. Spatially referenced activity data were compiled from federal and state databases and combined with O&G facility emission factors calculated using Monte Carlo simulations that account for high emission sites representing the very upper portion, or fat-tail, in the observed emissions distributions. Total methane emissions in the 25-county Barnett Shale region in October 2013 were estimated to be 72,300 (63,400?82,400) kg CH4 h?1. O&G emissions were estimated to be 46,200 (40,000?54,100) kg CH4 h?1 with 19% of emissions from fat-tail sites representing less than 2% of sites. Our estimate of O&G emissions in the Barnett Shale region was higher than alternative inventories based on the United States Environmental Protection Agency (EPA) Greenhouse Gas Inventory, EPA Greenhouse Gas Reporting Program, and Emissions Database for Global Atmospheric Research by factors of 1.5, 2.7, and 4.3, respectively. Gathering compressor stations, which accounted for 40% of O&G emissions in our inventory, had the largest difference from emission estimates based on EPA data sources. Our inventory?s higher O&G emission estimate was due primarily to its more comprehensive activity factors and inclusion of emissions from fat-tail sites.
Characterizing Fugitive Methane Emissions in the Barnett Shale Area Using a Mobile Laboratory
Lan et al., July 2015
Characterizing Fugitive Methane Emissions in the Barnett Shale Area Using a Mobile Laboratory
Xin Lan, Robert Talbot, Patrick Laine, Azucena Torres (2015). Environmental Science & Technology, 8139-8146. 10.1021/es5063055
Abstract:
Atmospheric methane (CH4) was measured using a mobile laboratory to quantify fugitive CH4 emissions from Oil and Natural Gas (ONG) operations in the Barnett Shale area. During this Barnett Coordinated Campaign we sampled more than 152 facilities, including well pads, compressor stations, gas processing plants, and landfills. Emission rates from several ONG facilities and landfills were estimated using an Inverse Gaussian Dispersion Model and the Environmental Protection Agency (EPA) Model AERMOD. Model results show that well pads emissions rates had a fat-tailed distribution, with the emissions linearly correlated with gas production. Using this correlation, we estimated a total well pad emission rate of 1.5 ? 105 kg/h in the Barnett Shale area. It was found that CH4 emissions from compressor stations and gas processing plants were substantially higher, with some ?super emitters? having emission rates up to 3447 kg/h, more then 36,000-fold higher than reported by the Environmental Protection Agency (EPA) Greenhouse Gas Reporting Program (GHGRP). Landfills are also a significant source of CH4 in the Barnett Shale area, and they should be accounted for in the regional budget of CH4.
Atmospheric methane (CH4) was measured using a mobile laboratory to quantify fugitive CH4 emissions from Oil and Natural Gas (ONG) operations in the Barnett Shale area. During this Barnett Coordinated Campaign we sampled more than 152 facilities, including well pads, compressor stations, gas processing plants, and landfills. Emission rates from several ONG facilities and landfills were estimated using an Inverse Gaussian Dispersion Model and the Environmental Protection Agency (EPA) Model AERMOD. Model results show that well pads emissions rates had a fat-tailed distribution, with the emissions linearly correlated with gas production. Using this correlation, we estimated a total well pad emission rate of 1.5 ? 105 kg/h in the Barnett Shale area. It was found that CH4 emissions from compressor stations and gas processing plants were substantially higher, with some ?super emitters? having emission rates up to 3447 kg/h, more then 36,000-fold higher than reported by the Environmental Protection Agency (EPA) Greenhouse Gas Reporting Program (GHGRP). Landfills are also a significant source of CH4 in the Barnett Shale area, and they should be accounted for in the regional budget of CH4.
Air Contaminants Associated with Potential Respiratory Effects from Unconventional Resource Development Activities
Michael McCawley, June 2015
Air Contaminants Associated with Potential Respiratory Effects from Unconventional Resource Development Activities
Michael McCawley (2015). Seminars in Respiratory and Critical Care Medicine, 379-387. 10.1055/s-0035-1549453
Abstract:
Unconventional natural gas development uses horizontal drilling in conjunction with hydraulic fracturing to gain access to natural gas deposits which may be tightly held in shale deposits and unavailable to conventional vertical drilling operations. The intensive work required to extract this source of energy results in higher than usual numbers of vehicles involved, potential release of emissions from those vehicles in congested zones surrounding the drill site, and release of other contaminants from materials drawn back out of the borehole after fracturing of the shale. Typical contaminants would be diesel exhaust particulate and gases, volatile organic compounds and other hydrocarbons both from diesels and the drilling process, crystalline silica, used as part of the hydraulic fracturing process in kiloton quantities, and methane escaping from the borehole and piping. A rise in respiratory disease with proximity to the process has been reported in nearby communities and both silica and diesel exposures at the worksite are recognized respiratory hazards. Because of the relatively short time this process has been used to the extent it is currently being used, it is not possible to draw detailed conclusions about the respiratory hazards that may be posed. However, based on the traffic volume associated with each drill site and the number of drill sites in any locale, it is possible at least to compare the effects to that of large traffic volume highways which are known to produce some respiratory effects in surrounding areas.
Unconventional natural gas development uses horizontal drilling in conjunction with hydraulic fracturing to gain access to natural gas deposits which may be tightly held in shale deposits and unavailable to conventional vertical drilling operations. The intensive work required to extract this source of energy results in higher than usual numbers of vehicles involved, potential release of emissions from those vehicles in congested zones surrounding the drill site, and release of other contaminants from materials drawn back out of the borehole after fracturing of the shale. Typical contaminants would be diesel exhaust particulate and gases, volatile organic compounds and other hydrocarbons both from diesels and the drilling process, crystalline silica, used as part of the hydraulic fracturing process in kiloton quantities, and methane escaping from the borehole and piping. A rise in respiratory disease with proximity to the process has been reported in nearby communities and both silica and diesel exposures at the worksite are recognized respiratory hazards. Because of the relatively short time this process has been used to the extent it is currently being used, it is not possible to draw detailed conclusions about the respiratory hazards that may be posed. However, based on the traffic volume associated with each drill site and the number of drill sites in any locale, it is possible at least to compare the effects to that of large traffic volume highways which are known to produce some respiratory effects in surrounding areas.
Near-Field Characterization of Methane Emission Variability from a Compressor Station Using a Model Aircraft
Nathan et al., May 2015
Near-Field Characterization of Methane Emission Variability from a Compressor Station Using a Model Aircraft
Brian J. Nathan, Levi M. Golston, Anthony S. O'Brien, Kevin Ross, William A. Harrison, Lei Tao, David J. Lary, Derek R. Johnson, April N. Covington, Nigel N. Clark, Mark A. Zondlo (2015). Environmental Science & Technology, 7896-7903. 10.1021/acs.est.5b00705
Abstract:
A model aircraft equipped with a custom laser-based, open-path methane sensor was deployed around a natural gas compressor station to quantify the methane leak rate and its variability at a compressor station in the Barnett Shale. The open-path, laser-based sensor provides fast (10 Hz) and precise (0.1 ppmv) measurements of methane in a compact package while the remote control aircraft provides nimble and safe operation around a local source. Emission rates were measured from 22 flights over a one-week period. Mean emission rates of 14 ± 8 g CH4 s(-1) (7.4 ± 4.2 g CH4 s(-1) median) from the station were observed or approximately 0.02% of the station throughput. Significant variability in emission rates (0.3-73 g CH4 s(-1) range) was observed on time scales of hours to days, and plumes showed high spatial variability in the horizontal and vertical dimensions. Given the high spatiotemporal variability of emissions, individual measurements taken over short durations and from ground-based platforms should be used with caution when examining compressor station emissions. More generally, our results demonstrate the unique advantages and challenges of platforms like small unmanned aerial vehicles for quantifying local emission sources to the atmosphere.
A model aircraft equipped with a custom laser-based, open-path methane sensor was deployed around a natural gas compressor station to quantify the methane leak rate and its variability at a compressor station in the Barnett Shale. The open-path, laser-based sensor provides fast (10 Hz) and precise (0.1 ppmv) measurements of methane in a compact package while the remote control aircraft provides nimble and safe operation around a local source. Emission rates were measured from 22 flights over a one-week period. Mean emission rates of 14 ± 8 g CH4 s(-1) (7.4 ± 4.2 g CH4 s(-1) median) from the station were observed or approximately 0.02% of the station throughput. Significant variability in emission rates (0.3-73 g CH4 s(-1) range) was observed on time scales of hours to days, and plumes showed high spatial variability in the horizontal and vertical dimensions. Given the high spatiotemporal variability of emissions, individual measurements taken over short durations and from ground-based platforms should be used with caution when examining compressor station emissions. More generally, our results demonstrate the unique advantages and challenges of platforms like small unmanned aerial vehicles for quantifying local emission sources to the atmosphere.
Impacts from Above-Ground Activities in the Eagle Ford Shale Play on Landscapes and Hydrologic Flows, La Salle County, Texas
Pierre et al., May 2015
Impacts from Above-Ground Activities in the Eagle Ford Shale Play on Landscapes and Hydrologic Flows, La Salle County, Texas
Jon Paul Pierre, Charles J. Abolt, Michael H. Young (2015). Environmental Management, 1262-1275. 10.1007/s00267-015-0492-2
Abstract:
We assess the spatial and geomorphic fragmentation from the recent Eagle Ford Shale play in La Salle County, Texas, USA. Wells and pipelines were overlaid onto base maps of land cover, soil properties, vegetation assemblages, and hydrologic units. Changes to continuity of different ecoregions and supporting landscapes were assessed using the Landscape Fragmentation Tool (a third-party ArcGIS extension) as quantified by land area and continuity of core landscape areas (i.e., those degraded by “edge effects”). Results show decreases in core areas (8.7 %; ~33,290 ha) and increases in landscape patches (0.2 %; ~640 ha), edges (1.8 %; ~6940 ha), and perforated areas (4.2 %; ~16230 ha). Pipeline construction dominates landscape disturbance, followed by drilling and injection pads (85, 15, and 0.03 % of disturbed area, respectively). An increased potential for soil loss is indicated, with 51 % (~5790 ha) of all disturbance regimes occurring on soils with low water-transmission rates (depth to impermeable layer less than 50 cm) and a high surface runoff potential (hydrologic soil group D). Additionally, 88 % (~10,020 ha) of all disturbances occurred on soils with a wind erodibility index of approximately 19 kt/km2/year (0.19 kt/ha/year) or higher, resulting in an estimated potential of 2 million tons of soil loss per year. Results demonstrate that infrastructure placement is occurring on soils susceptible to erosion while reducing and splitting core areas potentially vital to ecosystem services.
We assess the spatial and geomorphic fragmentation from the recent Eagle Ford Shale play in La Salle County, Texas, USA. Wells and pipelines were overlaid onto base maps of land cover, soil properties, vegetation assemblages, and hydrologic units. Changes to continuity of different ecoregions and supporting landscapes were assessed using the Landscape Fragmentation Tool (a third-party ArcGIS extension) as quantified by land area and continuity of core landscape areas (i.e., those degraded by “edge effects”). Results show decreases in core areas (8.7 %; ~33,290 ha) and increases in landscape patches (0.2 %; ~640 ha), edges (1.8 %; ~6940 ha), and perforated areas (4.2 %; ~16230 ha). Pipeline construction dominates landscape disturbance, followed by drilling and injection pads (85, 15, and 0.03 % of disturbed area, respectively). An increased potential for soil loss is indicated, with 51 % (~5790 ha) of all disturbance regimes occurring on soils with low water-transmission rates (depth to impermeable layer less than 50 cm) and a high surface runoff potential (hydrologic soil group D). Additionally, 88 % (~10,020 ha) of all disturbances occurred on soils with a wind erodibility index of approximately 19 kt/km2/year (0.19 kt/ha/year) or higher, resulting in an estimated potential of 2 million tons of soil loss per year. Results demonstrate that infrastructure placement is occurring on soils susceptible to erosion while reducing and splitting core areas potentially vital to ecosystem services.
Oil and Gas Wells and Pipelines on U.S. Wildlife Refuges: Challenges for Managers
Pedro , Jr. Ramirez and Sherri Baker Mosley, April 2015
Oil and Gas Wells and Pipelines on U.S. Wildlife Refuges: Challenges for Managers
Pedro , Jr. Ramirez and Sherri Baker Mosley (2015). PLoS ONE, e0124085. 10.1371/journal.pone.0124085
Abstract:
The increased demand for oil and gas places a burden on lands set aside for natural resource conservation. Oil and gas development alters the environment locally and on a much broader spatial scale depending on the intensity and extent of mineral resource extraction. The current increase in oil and gas exploration and production in the United States prompted an update of the number of pipelines and wells associated with oil and gas production on National Wildlife Refuge System (NWRS) lands. We obtained geospatial data on the location of oil and gas wells and pipelines within and close to the boundaries of NWRS lands (units) acquired as fee simple (i.e. absolute title to the surface land) by the U.S. Fish and Wildlife Service. We found that 5,002 wells are located in 107 NWRS units and 595 pipelines transect 149 of the 599 NWRS units. Almost half of the wells (2,196) were inactive, one-third (1,665) were active, and the remainder of the wells were either plugged and abandoned or the status was unknown. Pipelines crossed a total of 2,155 kilometers (1,339 miles) of NWRS fee simple lands. The high level of oil and gas activity warrants follow up assessments for wells lacking information on production type or well status with emphasis on verifying the well status and identifying abandoned and unplugged wells. NWRS fee simple lands should also be assessed for impacts from brine, oil and other hydrocarbon spills, as well as habitat alteration associated with oil and gas, including the identification of abandoned oil and gas facilities requiring equipment removal and site restoration.
The increased demand for oil and gas places a burden on lands set aside for natural resource conservation. Oil and gas development alters the environment locally and on a much broader spatial scale depending on the intensity and extent of mineral resource extraction. The current increase in oil and gas exploration and production in the United States prompted an update of the number of pipelines and wells associated with oil and gas production on National Wildlife Refuge System (NWRS) lands. We obtained geospatial data on the location of oil and gas wells and pipelines within and close to the boundaries of NWRS lands (units) acquired as fee simple (i.e. absolute title to the surface land) by the U.S. Fish and Wildlife Service. We found that 5,002 wells are located in 107 NWRS units and 595 pipelines transect 149 of the 599 NWRS units. Almost half of the wells (2,196) were inactive, one-third (1,665) were active, and the remainder of the wells were either plugged and abandoned or the status was unknown. Pipelines crossed a total of 2,155 kilometers (1,339 miles) of NWRS fee simple lands. The high level of oil and gas activity warrants follow up assessments for wells lacking information on production type or well status with emphasis on verifying the well status and identifying abandoned and unplugged wells. NWRS fee simple lands should also be assessed for impacts from brine, oil and other hydrocarbon spills, as well as habitat alteration associated with oil and gas, including the identification of abandoned oil and gas facilities requiring equipment removal and site restoration.
Atmospheric Emission Characterization of Marcellus Shale Natural Gas Development Sites
Goetz et al., April 2015
Atmospheric Emission Characterization of Marcellus Shale Natural Gas Development Sites
J. Douglass Goetz, Cody Floerchinger, Edward Charles Fortner, Joda Wormhoudt, Paola Massoli, W. Berk Knighton, Scott C. Herndon, Charles E. Kolb, Eladio Knipping, Stephanie Shaw, Peter DeCarlo (2015). Environmental Science & Technology, 7012-7020. 10.1021/acs.est.5b00452
Abstract:
Shale gas extraction, processing, and transmission processes are known to have many sources of atmospheric emissions that may impact local and regional air quality, as well as enhance climate forcing. Limited direct measurements of criteria pollutants emissions and precursors, as well as natural gas constituents, from Marcellus shale gas development activities contribute to uncertainty about their atmospheric impact. Online real-time mobile measurements were made with the Aerodyne Research Inc. Mobile Laboratory to characterize emission rates of atmospheric pollutants from several sources associated with Marcellus Shale development. Sites investigated include in production well pads, a drill rig, a well completion, and compressor stations. Tracer release ratio methods were used to estimate emission rates. An empirical first-order correction factor was developed to account for errors introduced by fenceline tracer release. In contrast to observations from other shale plays, elevated volatile organic compounds, including light aromatic species and natural gas constituents other than CH4 and C2H6, were generally not observed at the investigated sites. Elevated submicron particle mass concentrations were also generally not observed. Compressor stations were observed to have the largest emission rates of combustion related species ranging from 0.006 to 0.162 tons per day (tpd) for NOx, 0.029 to 0.426 tpd for CO, and 67.9 to 371 tpd for CO2. Natural gas constituents including CH4 and C2H6 were observed to have emission rates ranging from 0.411 to 4.936 tpd and 0.023 to 0.062 tpd, respectively. Although limited in sample size, this study provides emission rate estimates for some processes in a newly developed natural gas resource and contributes valuable comparisons to other shale gas studies. In contrast to observations from other shale plays, volatile organic compounds, including light aromatic species and natural gas constituents other than CH4 and C2H6, were generally not observed at the investigated sites. Elevated submicron particle mass concentrations were also generally not observed. Compressor stations were observed to have the largest emission rates of combustion related species ranging from 0.006 to 0.162 tons per day (tpd) for NOx, 0.029 to 0.426 tpd for CO, and 67.9 to 371 tpd for CO2. Natural gas constituents including CH4 and C2H6 were observed to have emission rates ranging from 0.411 to 4.936 tpd and 0.023 to 0.062 tpd, respectively. In production well sites were observed to have the lowest emission rates.
Shale gas extraction, processing, and transmission processes are known to have many sources of atmospheric emissions that may impact local and regional air quality, as well as enhance climate forcing. Limited direct measurements of criteria pollutants emissions and precursors, as well as natural gas constituents, from Marcellus shale gas development activities contribute to uncertainty about their atmospheric impact. Online real-time mobile measurements were made with the Aerodyne Research Inc. Mobile Laboratory to characterize emission rates of atmospheric pollutants from several sources associated with Marcellus Shale development. Sites investigated include in production well pads, a drill rig, a well completion, and compressor stations. Tracer release ratio methods were used to estimate emission rates. An empirical first-order correction factor was developed to account for errors introduced by fenceline tracer release. In contrast to observations from other shale plays, elevated volatile organic compounds, including light aromatic species and natural gas constituents other than CH4 and C2H6, were generally not observed at the investigated sites. Elevated submicron particle mass concentrations were also generally not observed. Compressor stations were observed to have the largest emission rates of combustion related species ranging from 0.006 to 0.162 tons per day (tpd) for NOx, 0.029 to 0.426 tpd for CO, and 67.9 to 371 tpd for CO2. Natural gas constituents including CH4 and C2H6 were observed to have emission rates ranging from 0.411 to 4.936 tpd and 0.023 to 0.062 tpd, respectively. Although limited in sample size, this study provides emission rate estimates for some processes in a newly developed natural gas resource and contributes valuable comparisons to other shale gas studies. In contrast to observations from other shale plays, volatile organic compounds, including light aromatic species and natural gas constituents other than CH4 and C2H6, were generally not observed at the investigated sites. Elevated submicron particle mass concentrations were also generally not observed. Compressor stations were observed to have the largest emission rates of combustion related species ranging from 0.006 to 0.162 tons per day (tpd) for NOx, 0.029 to 0.426 tpd for CO, and 67.9 to 371 tpd for CO2. Natural gas constituents including CH4 and C2H6 were observed to have emission rates ranging from 0.411 to 4.936 tpd and 0.023 to 0.062 tpd, respectively. In production well sites were observed to have the lowest emission rates.
Methane emissions from natural gas infrastructure and use in the urban region of Boston, Massachusetts
McKain et al., January 2015
Methane emissions from natural gas infrastructure and use in the urban region of Boston, Massachusetts
Kathryn McKain, Adrian Down, Steve M. Raciti, John Budney, Lucy R. Hutyra, Cody Floerchinger, Scott C. Herndon, Thomas Nehrkorn, Mark S. Zahniser, Robert B. Jackson, Nathan Phillips, Steven C. Wofsy (2015). Proceedings of the National Academy of Sciences, 1941-1946. 10.1073/pnas.1416261112
Abstract:
Methane emissions from natural gas delivery and end use must be quantified to evaluate the environmental impacts of natural gas and to develop and assess the efficacy of emission reduction strategies. We report natural gas emission rates for 1 y in the urban region of Boston, using a comprehensive atmospheric measurement and modeling framework. Continuous methane observations from four stations are combined with a high-resolution transport model to quantify the regional average emission flux, 18.5 ± 3.7 (95% confidence interval) g CH4⋅m−2⋅y−1. Simultaneous observations of atmospheric ethane, compared with the ethane-to-methane ratio in the pipeline gas delivered to the region, demonstrate that natural gas accounted for ∼60–100% of methane emissions, depending on season. Using government statistics and geospatial data on natural gas use, we find the average fractional loss rate to the atmosphere from all downstream components of the natural gas system, including transmission, distribution, and end use, was 2.7 ± 0.6% in the Boston urban region, with little seasonal variability. This fraction is notably higher than the 1.1% implied by the most closely comparable emission inventory.
Methane emissions from natural gas delivery and end use must be quantified to evaluate the environmental impacts of natural gas and to develop and assess the efficacy of emission reduction strategies. We report natural gas emission rates for 1 y in the urban region of Boston, using a comprehensive atmospheric measurement and modeling framework. Continuous methane observations from four stations are combined with a high-resolution transport model to quantify the regional average emission flux, 18.5 ± 3.7 (95% confidence interval) g CH4⋅m−2⋅y−1. Simultaneous observations of atmospheric ethane, compared with the ethane-to-methane ratio in the pipeline gas delivered to the region, demonstrate that natural gas accounted for ∼60–100% of methane emissions, depending on season. Using government statistics and geospatial data on natural gas use, we find the average fractional loss rate to the atmosphere from all downstream components of the natural gas system, including transmission, distribution, and end use, was 2.7 ± 0.6% in the Boston urban region, with little seasonal variability. This fraction is notably higher than the 1.1% implied by the most closely comparable emission inventory.
Impact of emissions from natural gas production facilities on ambient air quality in the Barnett Shale area: a pilot study
Zielinska et al., December 2014
Impact of emissions from natural gas production facilities on ambient air quality in the Barnett Shale area: a pilot study
Barbara Zielinska, Dave Campbell, Vera Samburova (2014). Journal of the Air & Waste Management Association (1995), 1369-1383. 10.1073/pnas.1416261112
Abstract:
Rapid and extensive development of shale gas resources in the Barnett Shale region of Texas in recent years has created concerns about potential environmental impacts on water and air quality. The purpose of this study was to provide a better understanding of the potential contributions of emissions from gas production operations to population exposure to air toxics in the Barnett Shale region. This goal was approached using a combination of chemical characterization of the volatile organic compound (VOC) emissions from active wells, saturation monitoring for gaseous and particulate pollutants in a residential community located near active gas/oil extraction and processing facilities, source apportionment of VOCs measured in the community using the Chemical Mass Balance (CMB) receptor model, and direct measurements of the pollutant gradient downwind of a gas well with high VOC emissions. Overall, the study results indicate that air quality impacts due to individual gas wells and compressor stations are not likely to be discernible beyond a distance of approximately 100 m in the downwind direction. However, source apportionment results indicate a significant contribution to regional VOCs from gas production sources, particularly for lower-molecular-weight alkanes (< C6). Although measured ambient VOC concentrations were well below health-based safe exposure levels, the existence of urban-level mean concentrations of benzene and other mobile source air toxics combined with soot to total carbon ratios that were high for an area with little residential or commercial development may be indicative of the impact of increased heavy-duty vehicle traffic related to gas production. Implications: Rapid and extensive development of shale gas resources in recent years has created concerns about potential environmental impacts on water and air quality. This study focused on directly measuring the ambient air pollutant levels occurring at residential properties located near natural gas extraction and processing facilities, and estimating the relative contributions from gas production and motor vehicle emissions to ambient VOC concentrations. Although only a small-scale case study, the results may be useful for guidance in planning future ambient air quality studies and human exposure estimates in areas of intensive shale gas production.
Rapid and extensive development of shale gas resources in the Barnett Shale region of Texas in recent years has created concerns about potential environmental impacts on water and air quality. The purpose of this study was to provide a better understanding of the potential contributions of emissions from gas production operations to population exposure to air toxics in the Barnett Shale region. This goal was approached using a combination of chemical characterization of the volatile organic compound (VOC) emissions from active wells, saturation monitoring for gaseous and particulate pollutants in a residential community located near active gas/oil extraction and processing facilities, source apportionment of VOCs measured in the community using the Chemical Mass Balance (CMB) receptor model, and direct measurements of the pollutant gradient downwind of a gas well with high VOC emissions. Overall, the study results indicate that air quality impacts due to individual gas wells and compressor stations are not likely to be discernible beyond a distance of approximately 100 m in the downwind direction. However, source apportionment results indicate a significant contribution to regional VOCs from gas production sources, particularly for lower-molecular-weight alkanes (< C6). Although measured ambient VOC concentrations were well below health-based safe exposure levels, the existence of urban-level mean concentrations of benzene and other mobile source air toxics combined with soot to total carbon ratios that were high for an area with little residential or commercial development may be indicative of the impact of increased heavy-duty vehicle traffic related to gas production. Implications: Rapid and extensive development of shale gas resources in recent years has created concerns about potential environmental impacts on water and air quality. This study focused on directly measuring the ambient air pollutant levels occurring at residential properties located near natural gas extraction and processing facilities, and estimating the relative contributions from gas production and motor vehicle emissions to ambient VOC concentrations. Although only a small-scale case study, the results may be useful for guidance in planning future ambient air quality studies and human exposure estimates in areas of intensive shale gas production.
Air concentrations of volatile compounds near oil and gas production: a community-based exploratory study
Macey et al., October 2014
Air concentrations of volatile compounds near oil and gas production: a community-based exploratory study
Gregg P. Macey, Ruth Breech, Mark Chernaik, Caroline Cox, Denny Larson, Deb Thomas, David O. Carpenter (2014). Environmental Health, 82. 10.1186/1476-069X-13-82
Abstract:
Horizontal drilling, hydraulic fracturing, and other drilling and well stimulation technologies are now used widely in the United States and increasingly in other countries. They enable increases in oil and gas production, but there has been inadequate attention to human health impacts. Air quality near oil and gas operations is an underexplored human health concern for five reasons: (1) prior focus on threats to water quality; (2) an evolving understanding of contributions of certain oil and gas production processes to air quality; (3) limited state air quality monitoring networks; (4) significant variability in air emissions and concentrations; and (5) air quality research that misses impacts important to residents. Preliminary research suggests that volatile compounds, including hazardous air pollutants, are of potential concern. This study differs from prior research in its use of a community-based process to identify sampling locations. Through this approach, we determine concentrations of volatile compounds in air near operations that reflect community concerns and point to the need for more fine-grained and frequent monitoring at points along the production life cycle.
Horizontal drilling, hydraulic fracturing, and other drilling and well stimulation technologies are now used widely in the United States and increasingly in other countries. They enable increases in oil and gas production, but there has been inadequate attention to human health impacts. Air quality near oil and gas operations is an underexplored human health concern for five reasons: (1) prior focus on threats to water quality; (2) an evolving understanding of contributions of certain oil and gas production processes to air quality; (3) limited state air quality monitoring networks; (4) significant variability in air emissions and concentrations; and (5) air quality research that misses impacts important to residents. Preliminary research suggests that volatile compounds, including hazardous air pollutants, are of potential concern. This study differs from prior research in its use of a community-based process to identify sampling locations. Through this approach, we determine concentrations of volatile compounds in air near operations that reflect community concerns and point to the need for more fine-grained and frequent monitoring at points along the production life cycle.
Volatile organic compound emissions from the oil and natural gas industry in the Uinta Basin, Utah: point sources compared to ambient air composition
Warneke et al., May 2014
Volatile organic compound emissions from the oil and natural gas industry in the Uinta Basin, Utah: point sources compared to ambient air composition
C. Warneke, F. Geiger, P. M. Edwards, W. Dube, G. Pétron, J. Kofler, A. Zahn, S. S. Brown, M. Graus, J. Gilman, B. Lerner, J. Peischl, T. B. Ryerson, J. A. de Gouw, J. M. Roberts (2014). Atmos. Chem. Phys. Discuss., 11895-11927. 10.5194/acpd-14-11895-2014
Abstract:
The emissions of volatile organic compounds (VOCs) associated with oil and natural gas production in the Uinta Basin, Utah were measured at a ground site in Horse Pool and from a NOAA mobile laboratory with PTR-MS instruments. The VOC compositions in the vicinity of individual gas and oil wells and other point sources such as evaporation ponds, compressor stations and injection wells are compared to the measurements at Horse Pool. High mixing ratios of aromatics, alkanes, cycloalkanes and methanol were observed for extended periods of time and short-term spikes caused by local point sources. The mixing ratios during the time the mobile laboratory spent on the well pads were averaged. High mixing ratios were found close to all point sources, but gas wells using dry-gas collection, which means dehydration happens at the well, were clearly associated with higher mixing ratios than other wells. Another large source was the flowback pond near a recently hydraulically re-fractured gas well. The comparison of the VOC composition of the emissions from the oil and natural gas wells showed that wet gas collection wells compared well with the majority of the data at Horse Pool and that oil wells compared well with the rest of the ground site data. Oil wells on average emit heavier compounds than gas wells. The mobile laboratory measurements confirm the results from an emissions inventory: the main VOC source categories from individual point sources are dehydrators, oil and condensate tank flashing and pneumatic devices and pumps. Raw natural gas is emitted from the pneumatic devices and pumps and heavier VOC mixes from the tank flashings.
The emissions of volatile organic compounds (VOCs) associated with oil and natural gas production in the Uinta Basin, Utah were measured at a ground site in Horse Pool and from a NOAA mobile laboratory with PTR-MS instruments. The VOC compositions in the vicinity of individual gas and oil wells and other point sources such as evaporation ponds, compressor stations and injection wells are compared to the measurements at Horse Pool. High mixing ratios of aromatics, alkanes, cycloalkanes and methanol were observed for extended periods of time and short-term spikes caused by local point sources. The mixing ratios during the time the mobile laboratory spent on the well pads were averaged. High mixing ratios were found close to all point sources, but gas wells using dry-gas collection, which means dehydration happens at the well, were clearly associated with higher mixing ratios than other wells. Another large source was the flowback pond near a recently hydraulically re-fractured gas well. The comparison of the VOC composition of the emissions from the oil and natural gas wells showed that wet gas collection wells compared well with the majority of the data at Horse Pool and that oil wells compared well with the rest of the ground site data. Oil wells on average emit heavier compounds than gas wells. The mobile laboratory measurements confirm the results from an emissions inventory: the main VOC source categories from individual point sources are dehydrators, oil and condensate tank flashing and pneumatic devices and pumps. Raw natural gas is emitted from the pneumatic devices and pumps and heavier VOC mixes from the tank flashings.
Natural Gas Pipeline Leaks Across Washington, DC
Jackson et al., February 2014
Natural Gas Pipeline Leaks Across Washington, DC
Robert B. Jackson, Adrian Down, Nathan G. Phillips, Robert C. Ackley, Charles W. Cook, Desiree L. Plata, Kaiguang Zhao (2014). Environmental Science & Technology, 2051-2058. 10.1021/es404474x
Abstract:
Pipeline safety in the United States has increased in recent decades, but incidents involving natural gas pipelines still cause an average of 17 fatalities and $133 M in property damage annually. Natural gas leaks are also the largest anthropogenic source of the greenhouse gas methane (CH4) in the U.S. To reduce pipeline leakage and increase consumer safety, we deployed a Picarro G2301 Cavity Ring-Down Spectrometer in a car, mapping 5893 natural gas leaks (2.5 to 88.6 ppm CH4) across 1500 road miles of Washington, DC. The δ13C-isotopic signatures of the methane (?38.2? ± 3.9? s.d.) and ethane (?36.5 ± 1.1 s.d.) and the CH4:C2H6 ratios (25.5 ± 8.9 s.d.) closely matched the pipeline gas (?39.0? and ?36.2? for methane and ethane; 19.0 for CH4/C2H6). Emissions from four street leaks ranged from 9200 to 38?200 L CH4 day?1 each, comparable to natural gas used by 1.7 to 7.0 homes, respectively. At 19 tested locations, 12 potentially explosive (Grade 1) methane concentrations of 50?000 to 500?000 ppm were detected in manholes. Financial incentives and targeted programs among companies, public utility commissions, and scientists to reduce leaks and replace old cast-iron pipes will improve consumer safety and air quality, save money, and lower greenhouse gas emissions.
Pipeline safety in the United States has increased in recent decades, but incidents involving natural gas pipelines still cause an average of 17 fatalities and $133 M in property damage annually. Natural gas leaks are also the largest anthropogenic source of the greenhouse gas methane (CH4) in the U.S. To reduce pipeline leakage and increase consumer safety, we deployed a Picarro G2301 Cavity Ring-Down Spectrometer in a car, mapping 5893 natural gas leaks (2.5 to 88.6 ppm CH4) across 1500 road miles of Washington, DC. The δ13C-isotopic signatures of the methane (?38.2? ± 3.9? s.d.) and ethane (?36.5 ± 1.1 s.d.) and the CH4:C2H6 ratios (25.5 ± 8.9 s.d.) closely matched the pipeline gas (?39.0? and ?36.2? for methane and ethane; 19.0 for CH4/C2H6). Emissions from four street leaks ranged from 9200 to 38?200 L CH4 day?1 each, comparable to natural gas used by 1.7 to 7.0 homes, respectively. At 19 tested locations, 12 potentially explosive (Grade 1) methane concentrations of 50?000 to 500?000 ppm were detected in manholes. Financial incentives and targeted programs among companies, public utility commissions, and scientists to reduce leaks and replace old cast-iron pipes will improve consumer safety and air quality, save money, and lower greenhouse gas emissions.
Air pollutant emissions from the development, production, and processing of Marcellus Shale natural gas
Roy et al., January 2014
Air pollutant emissions from the development, production, and processing of Marcellus Shale natural gas
Anirban A. Roy, Peter J. Adams, Allen L. Robinson (2014). Journal of the Air & Waste Management Association, 19-37. 10.1080/10962247.2013.826151
Abstract:
The Marcellus Shale is one of the largest natural gas reserves in the United States; it has recently been the focus of intense drilling and leasing activity. This paper describes an air emissions inventory for the development, production, and processing of natural gas in the Marcellus Shale region for 2009 and 2020. It includes estimates of the emissions of oxides of nitrogen (NOx), volatile organic compounds (VOCs), and primary fine particulate matter (≤2.5 µm aerodynamic diameter; PM2.5) from major activities such as drilling, hydraulic fracturing, compressor stations, and completion venting. The inventory is constructed using a process-level approach; a Monte Carlo analysis is used to explicitly account for the uncertainty. Emissions were estimated for 2009 and projected to 2020, accounting for the effects of existing and potential additional regulations. In 2020, Marcellus activities are predicted to contribute 6–18% (95% confidence interval) of the NOx emissions in the Marcellus region, with an average contribution of 12% (129 tons/day). In 2020, the predicted contribution of Marcellus activities to the regional anthropogenic VOC emissions ranged between 7% and 28% (95% confidence interval), with an average contribution of 12% (100 tons/day). These estimates account for the implementation of recently promulgated regulations such as the Tier 4 off-road diesel engine regulation and the U.S. Environmental Protection Agency's (EPA) Oil and Gas Rule. These regulations significantly reduce the Marcellus VOC and NOx emissions, but there are significant opportunities for further reduction in these emissions using existing technologies. Implications: The Marcellus Shale is one of the largest natural gas reserves in United States. The development and production of this gas may emit substantial amounts of oxides of nitrogen and volatile organic compounds. These emissions may have special significance because Marcellus development is occurring close to areas that have been designated nonattainment for the ozone standard. Control technologies exist to substantially reduce these impacts. PM2.5 emissions are predicted to be negligible in a regional context, but elemental carbon emissions from diesel powered equipment may be important.
The Marcellus Shale is one of the largest natural gas reserves in the United States; it has recently been the focus of intense drilling and leasing activity. This paper describes an air emissions inventory for the development, production, and processing of natural gas in the Marcellus Shale region for 2009 and 2020. It includes estimates of the emissions of oxides of nitrogen (NOx), volatile organic compounds (VOCs), and primary fine particulate matter (≤2.5 µm aerodynamic diameter; PM2.5) from major activities such as drilling, hydraulic fracturing, compressor stations, and completion venting. The inventory is constructed using a process-level approach; a Monte Carlo analysis is used to explicitly account for the uncertainty. Emissions were estimated for 2009 and projected to 2020, accounting for the effects of existing and potential additional regulations. In 2020, Marcellus activities are predicted to contribute 6–18% (95% confidence interval) of the NOx emissions in the Marcellus region, with an average contribution of 12% (129 tons/day). In 2020, the predicted contribution of Marcellus activities to the regional anthropogenic VOC emissions ranged between 7% and 28% (95% confidence interval), with an average contribution of 12% (100 tons/day). These estimates account for the implementation of recently promulgated regulations such as the Tier 4 off-road diesel engine regulation and the U.S. Environmental Protection Agency's (EPA) Oil and Gas Rule. These regulations significantly reduce the Marcellus VOC and NOx emissions, but there are significant opportunities for further reduction in these emissions using existing technologies. Implications: The Marcellus Shale is one of the largest natural gas reserves in United States. The development and production of this gas may emit substantial amounts of oxides of nitrogen and volatile organic compounds. These emissions may have special significance because Marcellus development is occurring close to areas that have been designated nonattainment for the ozone standard. Control technologies exist to substantially reduce these impacts. PM2.5 emissions are predicted to be negligible in a regional context, but elemental carbon emissions from diesel powered equipment may be important.
An exploratory study of air emissions associated with shale gas development and production in the Barnett Shale
Rich et al., October 2024
An exploratory study of air emissions associated with shale gas development and production in the Barnett Shale
Alisa Rich, James P. Grover, Melanie L. Sattler (2024). Journal of the Air & Waste Management Association, 61-72. 10.1080/10962247.2013.832713
Abstract:
Information regarding air emissions from shale gas extraction and production is critically important given production is occurring in highly urbanized areas across the United States. Objectives of this exploratory study were to collect ambient air samples in residential areas within 61 m (200 feet) of shale gas extraction/production and determine whether a “fingerprint” of chemicals can be associated with shale gas activity. Statistical analyses correlating fingerprint chemicals with methane, equipment, and processes of extraction/production were performed. Ambient air sampling in residential areas of shale gas extraction and production was conducted at six counties in the Dallas/Fort Worth (DFW) Metroplex from 2008 to 2010. The 39 locations tested were identified by clients that requested monitoring. Seven sites were sampled on 2 days (typically months later in another season), and two sites were sampled on 3 days, resulting in 50 sets of monitoring data. Twenty-four-hour passive samples were collected using summa canisters. Gas chromatography/mass spectrometer analysis was used to identify organic compounds present. Methane was present in concentrations above laboratory detection limits in 49 out of 50 sampling data sets. Most of the areas investigated had atmospheric methane concentrations considerably higher than reported urban background concentrations (1.8–2.0 ppmv). Other chemical constituents were found to be correlated with presence of methane. A principal components analysis (PCA) identified multivariate patterns of concentrations that potentially constitute signatures of emissions from different phases of operation at natural gas sites. The first factor identified through the PCA proved most informative. Extreme negative values were strongly and statistically associated with the presence of compressors at sample sites. The seven chemicals strongly associated with this factor (o-xylene, ethylbenzene, 1,2,4-trimethylbenzene, m- and p-xylene, 1,3,5-trimethylbenzene, toluene, and benzene) thus constitute a potential fingerprint of emissions associated with compression. Implications: Information regarding air emissions from shale gas development and production is critically important given production is now occurring in highly urbanized areas across the United States. Methane, the primary shale gas constituent, contributes substantially to climate change; other natural gas constituents are known to have adverse health effects. This study goes beyond previous Barnett Shale field studies by encompassing a wider variety of production equipment (wells, tanks, compressors, and separators) and a wider geographical region. The principal components analysis, unique to this study, provides valuable information regarding the ability to anticipate associated shale gas chemical constituents.
Information regarding air emissions from shale gas extraction and production is critically important given production is occurring in highly urbanized areas across the United States. Objectives of this exploratory study were to collect ambient air samples in residential areas within 61 m (200 feet) of shale gas extraction/production and determine whether a “fingerprint” of chemicals can be associated with shale gas activity. Statistical analyses correlating fingerprint chemicals with methane, equipment, and processes of extraction/production were performed. Ambient air sampling in residential areas of shale gas extraction and production was conducted at six counties in the Dallas/Fort Worth (DFW) Metroplex from 2008 to 2010. The 39 locations tested were identified by clients that requested monitoring. Seven sites were sampled on 2 days (typically months later in another season), and two sites were sampled on 3 days, resulting in 50 sets of monitoring data. Twenty-four-hour passive samples were collected using summa canisters. Gas chromatography/mass spectrometer analysis was used to identify organic compounds present. Methane was present in concentrations above laboratory detection limits in 49 out of 50 sampling data sets. Most of the areas investigated had atmospheric methane concentrations considerably higher than reported urban background concentrations (1.8–2.0 ppmv). Other chemical constituents were found to be correlated with presence of methane. A principal components analysis (PCA) identified multivariate patterns of concentrations that potentially constitute signatures of emissions from different phases of operation at natural gas sites. The first factor identified through the PCA proved most informative. Extreme negative values were strongly and statistically associated with the presence of compressors at sample sites. The seven chemicals strongly associated with this factor (o-xylene, ethylbenzene, 1,2,4-trimethylbenzene, m- and p-xylene, 1,3,5-trimethylbenzene, toluene, and benzene) thus constitute a potential fingerprint of emissions associated with compression. Implications: Information regarding air emissions from shale gas development and production is critically important given production is now occurring in highly urbanized areas across the United States. Methane, the primary shale gas constituent, contributes substantially to climate change; other natural gas constituents are known to have adverse health effects. This study goes beyond previous Barnett Shale field studies by encompassing a wider variety of production equipment (wells, tanks, compressors, and separators) and a wider geographical region. The principal components analysis, unique to this study, provides valuable information regarding the ability to anticipate associated shale gas chemical constituents.
The potential near-source ozone impacts of upstream oil and gas industry emissions
Eduardo P Olaguer, August 2012
The potential near-source ozone impacts of upstream oil and gas industry emissions
Eduardo P Olaguer (2012). Journal of the Air & Waste Management Association (1995), 966-977. 10.1080/10962247.2013.832713
Abstract:
Increased drilling in urban areas overlying shale formations and its potential impact on human health through decreased air quality make it important to estimate the contribution of oil and gas activities to photochemical smog. Flares and compressor engines used in natural gas operations, for example, are large sources not only of NOx but also offormaldehyde, a hazardous air pollutant and powerful ozone precursor We used a neighborhood scale (200 m horizontal resolution) three-dimensional (3D) air dispersion model with an appropriate chemical mechanism to simulate ozone formation in the vicinity ofa hypothetical natural gas processing facility, based on accepted estimates of both regular and nonroutine emissions. The model predicts that, under average midday conditions in June, regular emissions mostly associated with compressor engines may increase ambient ozone in the Barnett Shale by more than 3 ppb beginning at about 2 km downwind of the facility, assuming there are no other major sources of ozone precursors. Flare volumes of 100,000 cubic meters per hour ofnatural gas over a period of 2 hr can also add over 3 ppb to peak 1-hr ozone somewhatfurther (>8 km) downwind, once dilution overcomes ozone titration and inhibition by large flare emissions of NOx. The additional peak ozone from the hypothetical flare can briefly exceed 10 ppb about 16 km downwind. The enhancements of ambient ozone predicted by the model are significant, given that ozone control strategy widths are of the order of a few parts per billion. Degrading the horizontal resolution of the model to 1 km spuriously enhances the simulated ozone increases by reducing the effectiveness of ozone inhibition and titration due to artificial plume dilution.
Increased drilling in urban areas overlying shale formations and its potential impact on human health through decreased air quality make it important to estimate the contribution of oil and gas activities to photochemical smog. Flares and compressor engines used in natural gas operations, for example, are large sources not only of NOx but also offormaldehyde, a hazardous air pollutant and powerful ozone precursor We used a neighborhood scale (200 m horizontal resolution) three-dimensional (3D) air dispersion model with an appropriate chemical mechanism to simulate ozone formation in the vicinity ofa hypothetical natural gas processing facility, based on accepted estimates of both regular and nonroutine emissions. The model predicts that, under average midday conditions in June, regular emissions mostly associated with compressor engines may increase ambient ozone in the Barnett Shale by more than 3 ppb beginning at about 2 km downwind of the facility, assuming there are no other major sources of ozone precursors. Flare volumes of 100,000 cubic meters per hour ofnatural gas over a period of 2 hr can also add over 3 ppb to peak 1-hr ozone somewhatfurther (>8 km) downwind, once dilution overcomes ozone titration and inhibition by large flare emissions of NOx. The additional peak ozone from the hypothetical flare can briefly exceed 10 ppb about 16 km downwind. The enhancements of ambient ozone predicted by the model are significant, given that ozone control strategy widths are of the order of a few parts per billion. Degrading the horizontal resolution of the model to 1 km spuriously enhances the simulated ozone increases by reducing the effectiveness of ozone inhibition and titration due to artificial plume dilution.