Repository for Oil and Gas Energy Research (ROGER)

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Shale gas development (SGD) via horizontal drilling and fracking is touted for economic benefits and spurned for health and environmental impacts. Despite SGD's socioecological salience, few peer-reviewed, empirical studies document the distribution of positive and negative effects. The City of Denton, Texas has ~ 280 active gas wells and over a decade of SGD. Here we use an environmental justice framework to analyze the distribution of SGD's costs and benefits within Denton. Using data on mineral property values from 2002 to 2013 and gas well locations, we ask: who owns Denton's mineral rights (i.e. the greatest financial beneficiaries) and how does this ownership pattern relate to who lives near gas wells (i.e. those who shoulder the nuisances and health impacts)? Our results show that Denton's mineral wealth is widely distributed around the U.S., residents own 1% of the total value extracted, and the city government is a large financial beneficiary. In addition to distributional inequities, our analysis demonstrates that split estate doctrine, legal deference to mineral owners, and SGD's uniqueness in urban centers create disparities in municipal SGD decision-making processes. The environmental justice issues associated with fracking in Denton also provide one possible explanation for residents' November 2014 vote to ban hydraulic fracturing.

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Scenarios for potential shale gas development were modelled for the Baltic Basin in Northern Poland for the period 2015–2030 using the land allocation model EUCS100. The main aims were to assess the associated land use requirements, conflicts with existing land use, and the influence of legislation on the environmental impact. The factors involved in estimating the suitability for placement of shale gas well pads were analysed, as well as the potential land and water requirements to define 2 technology-based scenarios, representing the highest and lowest potential environmental impact. 2 different legislative frameworks (current and restrictive) were also assessed, to give 4 combined scenarios altogether. Land consumption and allocation patterns of well pads varied substantially according to the modelled scenario. Potential landscape fragmentation and conflicts with other land users depended mainly on development rate, well pad density, existing land-use patterns, and geology. Highly complex landscapes presented numerous barriers to drilling activities, restricting the potential development patterns. The land used for shale gas development could represent a significant percentage of overall land take within the shale play. The adoption of appropriate legislation, especially the protection of natural areas and water resources, is therefore essential to minimise the related environmental impact.

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The development of shale gas resources in the United States has been controversial as governments have been tardy in devising sufficient safeguards to protect both people and the environment. Alleged health and environmental damages suggest that other countries around the world that decide to develop their shale gas resources can learn from these problems and take further actions to prevent situations resulting in the release of harmful pollutants. Looking at U.S. federal regulations governing large animal operations under the permitting provisions of the Clean Water Act, the idea of a permitting program is proposed to respond to the risks of pollution by shale gas development activities. Governments can require permits before allowing the drilling of a new gas well. Each permit would include fluids and air emissions reduction plans containing best management practices to minimize risks and releases of pollutants. The public availability of permits and permit applications, as occurs for water pollution under various U.S. permitting programs, would assist governments in protecting public health. The permitting proposals provide governments a means for providing further assurances that shale gas development projects will not adversely affect people and the environment.

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Organic nitrates in both gas and condensed (aerosol) phases were measured during the Uintah Basin Winter Ozone Study from January to February in 2012. A high degree of correlation between total aerosol volume at diameters less than 500 nm and the particulate organic nitrate concentration indicates that organic nitrates are a consistent, if not dominant, fraction of fine aerosol mass. In contrast, a similar correlation with sub-2.5 μm aerosol volume is weaker. The C : N atomic ratio inferred from field measurements of PM2.5 and particulate organic nitrate is 34 : 1. Calculations constrained by the observations indicate that both condensation of gas-phase nitrates and heterogeneous reactions of NO3 / N2O5 are responsible for introducing organic nitrate functionality into the aerosol and that the source molecules are alkanes. Extrapolating the results to urban aerosol suggests organic nitrate production from alkanes may be a major secondary organic aerosol source.

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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.

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Hydraulic fracturing of shale for gas production in Pennsylvania generates large quantities of wastewater, the composition of which has been inadequately characterized. We compiled a unique data set from state-required wastewater generator reports filed in 2009?2011. The resulting data set, comprising 160 samples of flowback, produced water, and drilling wastes, analyzed for 84 different chemicals, is the most comprehensive available to date for Marcellus Shale wastewater. We analyzed the data set using the Kaplan?Meier method to deal with the high prevalence of nondetects for some analytes, and compared wastewater characteristics with permitted effluent limits and ambient monitoring limits and capacity. Major-ion concentrations suggested that most wastewater samples originated from dilution of brines, although some of our samples were more concentrated than any Marcellus brines previously reported. One problematic aspect of this wastewater was the very high concentrations of soluble constituents such as chloride, which are poorly removed by wastewater treatment plants; the vast majority of samples exceeded relevant water quality thresholds, generally by 2?3 orders of magnitude. We also examine the capacity of regional regulatory monitoring to assess and control these risks.

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The vertical portion of a shale gas well, known as the "tophole" is often drilled using an air-hammer bit that may introduce pressures as high as 2400 kPa (350 psi) into groundwater while penetrating shallow aquifers. A 3-D TOUGH2 model was used to simulate the flow of groundwater under the high hydraulic heads that may be imposed by such trapped compressed air, based on an observed case in West Virginia (USA) in 2012. The model realizations show that high-pressure air trapped in aquifers may cause groundwater to surge away from the drill site at observable velocities. If dissolved methane is present within the aquifer, the methane can be entrained and transported to a maximum distance of 10.6 m per day. Results from this study suggest that one cause of the reported increase in methane concentrations in groundwater near shale gas production wells may be the transport of pre-existing methane via groundwater surges induced by air drilling, not necessarily direct natural gas leakage from the unconventional gas reservoir. The primary transport mechanisms are advective transport of dissolved methane with water flow, and diffusive transport of dissolved methane.

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We characterize the appropriation of surface water for the extraction of natural gas from Pennsylvania's Marcellus Shale, and we examine the influences of these diversions on stream flows at 300 sites. Our analysis reveals that permitted withdrawals range from 50 m3/d to more than 18,000 m3/d and that water is taken from streams of all sizes, from headwater streams to eighth-order rivers. Flow alteration varies inversely with watershed area and, for larger streams, is compounded by upstream withdrawals. The ratio of daily permitted withdrawal to median stream flow ranges from 0.0001 to unity, although low flows in most, but not all, smaller streams are protected by pass-by flow requirements. Temporal changes in surface water withdrawals track gas well completion activity, rather than changes in operational strategies, and while reuse of wastewater has increased since 2009, freshwater accounted for 75% of water used in hydraulic fracturing through the peak in gas well completion activity.

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Hydraulic fracturing and related ground water issues are growing features in public discourse. Few have given much attention to surface impacts from shale gas development, which result from building necessary surface infrastructure. One way to reduce future impacts from gas surface development without radically changing industry practice is by formulating simple, conservation-oriented planning guidelines. We explore how four such guidelines affect the locations of well pads, access roads, and gathering pipelines on state lands in Pennsylvania. Our four guidelines aim to (1) reduce impacts on water, reduce impacts from (2) gathering pipelines and (3) access roads, and (4) reduce impacts on forests. We assessed whether the use of such guidelines accompanies tradeoffs among impacts, and if any guidelines perform better than others at avoiding impacts. We find that impacts are mostly synergistic, such that avoiding one impact will result in avoiding others. However, we found that avoiding forest fragmentation may result in increased impacts on other environmental features. We also found that single simple planning guidelines can be effective in targeted situations, but no one guideline was universally optimal in avoiding all impacts. As such, we suggest that when multiple environmental features are important in an area, more comprehensive planning strategies and tools should be used.

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Recent large-scale development of oil and gas from low-permeability unconventional formations (e.g., shales, tight sands, coal seams) has raised concern about potential environmental impacts. Legacy oil and gas wells co-located with that new development represent , if left improperly sealed, a potential pathways for unwanted migration of fluids (brine, drilling and stimulation fluids, oil and gas). Uncertainty in the number, location, and abandonment state of legacy wells hinders environmental assessment of exploration and production activity. The objective of this study is to apply publicly available information on Pennsylvania oil and gas wells to better understand their potential to serve as pathways for unwanted fluid migration. This study presents a synthesis of historical reports and digital well records to provide insights into spatial and temporal trends in oil and gas development. Areas with higher density of wells abandoned prior to mid twentieth century, when more modern well sealing requirements took effect in Pennsylvania, and areas where conventional oil and gas production penetrated to or through intervals that may be affected by new Marcellus shale development are identified. This information may help to address questions of environmental risk related to new extraction activities.

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There is much debate about the employment effect of shale gas development, especially as it...

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A constant refrain in both public discourse and academic research on shale gas development has been the necessity for 'sound science' to govern policy decisions. Rare, however, is the recommendation that effective policy on this topic also include 'sound moral thought'. I argue that: (1) philosophy (particularly moral thought and ethical reasoning) and science must work in tandem for making good policy decisions related to shale gas development, and (2) this realisation is essential for policy-makers, journalists, researchers, educators and the public. By examining the range of normative claims offered within academic and public discourse, the variation in claims across contexts and the degree to which the normative arguments are well-supported, I illustrate the important role increased attention to moral thought could play in forwarding policy construction on shale gas development. Finally, I offer recommendations for how policy-makers, journalists, researchers and educators can more actively acknowledge the importance of both science and moral thought in policy-making related to shale gas development.

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Extraction of oil and natural gas (hydrocarbons) from shale is increasing rapidly in North America, with documented impacts to native species and ecosystems. With shale oil and gas resources on nearly every continent, this development is set to become a major driver of global land-use change. It is increasingly critical to quantify spatial habitat loss driven by this development to implement effective mitigation strategies and develop habitat offsets. Habitat selection is a fundamental ecological process, influencing both individual fitness and population-level distribution on the landscape. Examinations of habitat selection provide a natural means for understanding spatial impacts. We examined the impact of natural gas development on habitat selection patterns of mule deer on their winter range in Colorado. We fit resource selection functions in a Bayesian hierarchical framework, with habitat availability defined using a movement-based modeling approach. Energy development drove considerable alterations to deer habitat selection patterns, with the most substantial impacts manifested as avoidance of well pads with active drilling to a distance of at least 800 m. Deer displayed more nuanced responses to other infrastructure, avoiding pads with active production and roads to a greater degree during the day than night. In aggregate, these responses equate to alteration of behavior by human development in over 50% of the critical winter range in our study area during the day and over 25% at night. Compared to other regions, the topographic and vegetative diversity in the study area appear to provide refugia that allow deer to behaviorally mediate some of the impacts of development. This study, and the methods we employed, provides a template for quantifying spatial take by industrial activities in natural areas and the results offer guidance for policy makers, mangers, and industry when attempting to mitigate habitat loss due to energy development.

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The natural gas extraction method of high-volume hydraulic fracturing (HVHF) has a significant truck transportation component, with estimates ranging from 625 to 1,148 heavy truck trips for equipment, materials, and waste movement for each well drilled in the Marcellus Shale. ArcGIS Network Analyst was used to analyze the environmental impacts of transporting sand and water to, and waste from, Pennsylvania wells from 2011 to 2013. The locations of wells, resource supply areas, and waste disposal facilities served as a series of origin and destination pairings for probable truck routes. Material and waste volumes per well were used to estimate the truck counts assigned to each route, leading to estimates of truck traffic by road segment. Emission loads and energy usage were calculated with the geospatial intermodal freight transport model. Simulation results of 22-ton loads estimated 4.4 million one-way truck trips totaling nearly 86.5 million vehicle miles and producing nearly 19 Mg of particulate matter and 745 Mg of nitrogen oxides, among other pollutants. Maps showing road segments with high truck counts identified areas of potential health and infrastructure impacts. On-site recycling of wastes offset an estimated 842,678 truck trips and associated emissions. Case studies developed during this project pointed to the need for better data collection and data distribution efforts in states extracting gas and those considering whether to allow HVHF operations. The results will help policy analysts and environmental planners to understand and evaluate the environmental, health, and economic impacts (pro and con) associated with the movement of HVHF equipment and materials.

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Hydraulic fracturing, or fracking, involves injecting large amounts of sand, water, and chemicals deep underground at high pressures to extract natural gas from rock formations. At the same time, fracking also generates by-products, such as dust, silica, and other gases. While some groups consider fracking to represent a health risk,1 others suggest that fracking poses little risk to the public.2 To date, most studies have measured emissions from the wells and estimated exposure and its health impact based on the distance from the wells,3,4 but none have addressed potential health effects associated with specific elements impacted by fracking.

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There is at present much interest in unconventional sources of natural gas, especially in shale gas which is obtained by hydraulic fracturing, or ‘fracking’. Boreholes are drilled and then lined with steel tubes so that a mixture of water and sand with small quantities of chemicals – the fracking fluid – can be pumped into them at very high pressure. The sand grains that wedge into the cracks induced in the shale rock by a ‘perforating gun’ then releases gas which returns up the tubes. In the United Kingdom (UK) exploratory drilling is at an early stage, with licences being issued to drill a limited number of test boreholes around the country. But such activities are already meeting community resistance and controversy. Like all energy technologies it exhibits unwanted ‘side-effects’; these simply differ in their level of severity between the various options. Shale gas may make, for example, a contribution to attaining the UK's statutory ‘greenhouse gas’ emissions targets, but only if appropriate and robust regulations are enforced. The benefits and disadvantages of shale gas fracking are therefore discussed in order to illustrate a ‘balance sheet’ approach. It is also argued that it is desirable to bring together experts from a range of disciplines in order to carry out energy technology assessments. That should draw on and interact with national and local stakeholders: ‘actors’ both large and small. Community engagement in a genuinely participative process – where the government is prepared to change course in response to the evidence and public opinion - will consequently be critically important for the adoption of any new energy option that might meet the needs of a low carbon future.

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We present an overview of the current status of unconventional energy development, particularly of shale gas, and underground CO2 storage as a measure to mitigate greenhouse gas increase in the atmosphere. We review their potential to induce seismicity, which has caused debates among related energy enterprises, engineers, researchers, and environmental and public communities regarding their potential hazards. Studies show that fracking can be a problem in that it consumes abundant water, but the seismicity induced by fracking has not yet been observed to induce many felt earthquakes. However, massive wastewater injection, a part of the unconventional energy development process has caused M5.0+ earthquakes in the past as well as several recent and ongoing cases of induced seismicity. Large-scale CO2 injection as a part of carbon sequestration efforts in the near future has a high risk of inducing large earthquakes. Therefore, injection operations related to both unconventional energy development and carbon sequestration should be optimized and managed to mitigate the likelihood of an induced seismic event.

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The introduction of new energy technologies may lead to public resistance and contestation. It is often argued that this phenomenon is caused by an inadequate inclusion of relevant public values in the design of technology. In this paper we examine the applicability of the value sensitive design (VSD) approach. While VSD was primarily introduced for incorporating values in technological design, our focus in this paper is expanded towards the design of the institutions surrounding these technologies, as well as the design of stakeholder participation. One important methodological challenge of VSD is to identify the relevant values related to new technological developments. In this paper, we argue that the public debate can form a rich source from which to retrieve the values at stake. To demonstrate this, we have examined the arguments used in the public debate regarding the exploration and exploitation of shale gas in the Netherlands. We identified two important sets of the underlying values, namely substantive and procedural values. This paper concludes with two key findings. Firstly, contrary to what is often suggested in the literature, both proponents and opponents seem to endorse the same values. Secondly, contestation seems to arise in the precise operationalization of these values among the different stakeholders. In other words, contestation in the Dutch shale gas debate does not arise from inter-value conflict but rather from intra-value conflicts. This multi-interpretability should be incorporated in VSD processes.

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For the purpose of generating electricity, what leakage rate renders the greenhouse gas (GHG) footprint of natural gas equivalent to that of coal? This paper answers this question using a simple model, which assumes that the comprehensive GHG footprint is the sum of the carbon dioxide-equivalent emissions resulting from (1) electricity generation and (2) natural gas leakage. The emissions resulting from electricity generation are taken from published life-cycle assessments (LCAs), whereas the emissions from natural gas leakage are estimated assuming that natural gas is 80 % methane, whose global warming potential (GWP) is calculated using equations provided by the Intergovernmental Panel on Climate Change (IPCC). Results, presented on a straightforward plot of GHG footprint versus time horizon, show that natural gas leakage of 2.0 % or 4.8 % eliminates half of natural gas’s GHG footprint advantage over coal at 20- or 100-year time horizons, respectively. Leakage of 3.9 % or 9.1 % completely eliminates the GHG footprint advantage at 20- and 100-year time horizons, respectively. A two-parameter power law approximation of the IPCC’s equation for GWP is utilized and gives equivalent results. Results indicate that leakage control is essential for natural gas to deliver a smaller GHG footprint than coal.

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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.

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Reports highlight the safety of hydraulic fracturing for drinking water if it occurs ?many hundreds of meters to kilometers underground?. To our knowledge, however, no comprehensive analysis of hydraulic fracturing depths exists. Based on fracturing depths and water use for ?44?000 wells reported between 2010 and 2013, the average fracturing depth across the United States was 8300 ft (?2500 m). Many wells (6900; 16%) were fractured less than a mile from the surface, and 2600 wells (6%) were fractured above 3000 ft (900 m), particularly in Texas (850 wells), California (720), Arkansas (310), and Wyoming (300). Average water use per well nationally was 2?400?000 gallons (9?200?000 L), led by Arkansas (5?200?000 gallons), Louisiana (5?100?000 gallons), West Virginia (5?000?000 gallons), and Pennsylvania (4?500?000 gallons). Two thousand wells (?5%) shallower than one mile and 350 wells (?1%) shallower than 3000 ft were hydraulically fractured with >1 million gallons of water, particularly in Arkansas, New Mexico, Texas, Pennsylvania, and California. Because hydraulic fractures can propagate 2000 ft upward, shallow wells may warrant special safeguards, including a mandatory registry of locations, full chemical disclosure, and, where horizontal drilling is used, predrilling water testing to a radius 1000 ft beyond the greatest lateral extent.

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Volumes of natural gas extraction-derived wastewaters have increased sharply over the past decade, but the ultimate fate of those waste streams is poorly characterized. Here, we sought to (a) quantify natural gas residual fluid sources and endpoints to bound the scope of potential waste stream impacts and (b) describe the organic pollutants discharged to surface waters following treatment, a route of likely ecological exposure. Our findings indicate that centralized waste treatment facilities (CWTF) received 9.5% (8.5 ? 108 L) of natural gas residual fluids in 2013, with some facilities discharging all effluent to surface waters. In dry months, discharged water volumes were on the order of the receiving body flows for some plants, indicating that surface waters can become waste-dominated in summer. As disclosed organic compounds used in high volume hydraulic fracturing (HVHF) vary greatly in physicochemical properties, we deployed a suite of analytical techniques to characterize CWTF effluents, covering 90.5% of disclosed compounds. Results revealed that, of nearly 1000 disclosed organic compounds used in HVHF, only petroleum distillates and alcohol polyethoxylates were present. Few analytes targeted by regulatory agencies (e.g., benzene or toluene) were observed, highlighting the need for expanded and improved monitoring efforts at CWTFs.

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Enormous global reserves of unconventional heavy oil make it a significant resource for economic growth and energy security; however, its extraction faces many challenges especially on greenhouse gas (GHG) emissions, water consumption, and recently, social acceptability. Here, we question whether it makes sense to extract and use unconventional heavy oil in spite of these externalities. We place unconventional oils (oil sands and oil shale) alongside shale gas, coal, lignite, wood and conventional oil and gas, and compare their energy intensities and life cycle GHG emissions. Our results reveal that oil shale is the most energy intensive fuel among upgraded primary fossil fuel options followed by in situ-produced bitumen from oil sands. Lignite is the most GHG intensive primary fuel followed by oil shale. Based on future world energy demand projections, we estimate that if growth of unconventional heavy oil production continues unabated, the incremental GHG emissions that results from replacing conventional oil with heavy oil would amount to 4?21 Gt-CO2eq GtCO2eq over four decades (2010 by 2050). However, prevailing socio-economic, regional and global energy politics, environmental and technological challenges may limit growth of heavy oil production and thus its GHG emissions contributions to global fossil fuel emissions may be smaller.

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Over the past ten years, unconventional gas and oil drilling (UGOD) has markedly expanded in the United States. Despite substantial increases in well drilling, the health consequences of UGOD toxicant exposure remain unclear. This study examines an association between wells and healthcare use by zip code from 2007 to 2011 in Pennsylvania. Inpatient discharge databases from the Pennsylvania Healthcare Cost Containment Council were correlated with active wells by zip code in three counties in Pennsylvania. For overall inpatient prevalence rates and 25 specific medical categories, the association of inpatient prevalence rates with number of wells per zip code and, separately, with wells per km2 (separated into quantiles and defined as well density) were estimated using fixed-effects Poisson models. To account for multiple comparisons, a Bonferroni correction with associations of p<0.00096 was considered statistically significant. Cardiology inpatient prevalence rates were significantly associated with number of wells per zip code (p<0.00096) and wells per km2 (p<0.00096) while neurology inpatient prevalence rates were significantly associated with wells per km2 (p<0.00096). Furthermore, evidence also supported an association between well density and inpatient prevalence rates for the medical categories of dermatology, neurology, oncology, and urology. These data suggest that UGOD wells, which dramatically increased in the past decade, were associated with increased inpatient prevalence rates within specific medical categories in Pennsylvania. Further studies are necessary to address healthcare costs of UGOD and determine whether specific toxicants or combinations are associated with organ-specific responses.

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The prospect of fracking in the United Kingdom has been accompanied by significant public unease. We outline how the policy debate is being framed by UK institutional actors, finding evidence of a dominant discourse in which the policy approach is defined through a deficit model of public understanding of science and in which a technical approach to feasibility and safety is deemed as sufficient grounds for good policymaking. Deploying a deliberative focus group methodology with lay publics across different sites in the north of England, we find that these institutional framings are poorly aligned with participants’ responses. We find that unease regularly overflows the focus on safety and feasibility and cannot be satisfactorily explained by a lack of understanding on the part of participants. We find that scholarship from science and technology studies productively elucidates our participants’ largely sceptical positions, and orientates strategies for responding to them more effectively.

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Due to the rapid expansion in hydraulic fracturing (fracking), there is a need for robust, portable and specific water analysis techniques. Early detection of contamination is crucial for the prevention of lasting environmental damage. Bromide can potentially function as an early indicator of water contamination by fracking waste, because there is a high concentration of bromide ions in fracking wastewaters. To facilitate this, a microfluidic paper-based analytical device (μPAD) has been developed and optimized for the quantitative colorimetric detection of bromide in water using a smartphone. A paper microfluidic platform offers the advantages of inexpensive fabrication, elimination of unstable wet reagents, portability and high adaptability for widespread distribution. These features make this assay an attractive option for a new field test for on-site determination of bromide.

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Natural gas extraction from Marcellus Shale generates large quantities of flowback water that contain high levels of salinity, heavy metals, and Naturally Occurring Radioactive Material (NORM). This water is typically stored in centralized storage impoundments or tanks prior to reuse, treatment or disposal. The fate of Ra-226, which is the dominant NORM component in flowback water, in three centralized storage impoundments in southwestern Pennsylvania was investigated during a 2.5-year period. Field sampling revealed that Ra-226 concentration in these storage facilities depends on the management strategy but is generally increasing during the reuse of flowback water for hydraulic fracturing. In addition, Ra-226 is enriched in the bottom solids (e.g., impoundment sludge) where it increased from less than 10 pCi/g for fresh sludge to several hundred pCi/g for aged sludge. A combination of sequential extraction procedure (SEP) and chemical composition analysis of impoundment sludge revealed that barite is the main carrier of Ra-226 in the sludge. Toxicity characteristic leaching procedure (TCLP) (EPA Method 1311) was used to assess the leaching behavior of Ra-226 in the impoundment sludge and its implications for waste management strategies for this low-level radioactive solid waste. Radiation exposure for on-site workers calculated using the RESRAD model showed that the radiation dose equivalent for the baseline conditions was well below the NRC limit for the general public.

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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.

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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.

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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.

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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.

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A growing dependence on natural gas for energy may exacerbate emissions of the greenhouse gas methane (CH4). Identifying fingerprints of these emissions is critical to our understanding of potential impacts. Here, we compare stable isotopic and alkane ratio tracers of natural gas, agricultural, and urban CH4 sources in the Barnett Shale hydraulic fracturing region near Fort Worth, Texas. Thermogenic and biogenic sources were compositionally distinct, and emissions from oil wells were enriched in alkanes and isotopically depleted relative to natural gas wells. Emissions from natural gas production varied in δ13C and alkane ratio composition, with δD-CH4 representing the most consistent tracer of natural gas sources. We integrated our data into a bottom-up inventory of CH4 for the region, resulting in an inventory of ethane (C2H6) sources for comparison to top-down estimates of CH4 and C2H6 emissions. Methane emissions in the Barnett are a complex mixture of urban, agricultural, and fossil fuel sources, which makes source apportionment challenging. For example, spatial heterogeneity in gas composition and high C2H6/CH4 ratios in emissions from conventional oil production add uncertainty to top-down models of source apportionment. Future top-down studies may benefit from the addition of δD-CH4 to distinguish thermogenic and biogenic sources.

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We present estimates of regional methane (CH4) emissions from oil and natural gas operations in the Barnett Shale, Texas, using airborne atmospheric measurements. Using a mass balance approach on eight different flight days in March and October 2013, the total CH4 emissions for the region are estimated to be 76 ± 13 ? 103 kg hr?1 (equivalent to 0.66 ± 0.11 Tg CH4 yr?1; 95% confidence interval (CI)). We estimate that 60 ± 11 ? 103 kg CH4 hr?1 (95% CI) are emitted by natural gas and oil operations, including production, processing, and distribution in the urban areas of Dallas and Fort Worth. This estimate agrees with the U.S. Environmental Protection Agency (EPA) estimate for nationwide CH4 emissions from the natural gas sector when scaled by natural gas production, but it is higher than emissions reported by the EDGAR inventory or by industry to EPA?s Greenhouse Gas Reporting Program. This study is the first to show consistency between mass balance results on so many different days and in two different seasons, enabling better quantification of the related uncertainty. The Barnett is one of the largest production basins in the United States, with 8% of total U.S. natural gas production, and thus, our results represent a crucial step toward determining the greenhouse gas footprint of U.S. onshore natural gas production.

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Emissions from natural gas production sites are characterized by skewed distributions, where a small percentage of sites?commonly labeled super-emitters?account for a majority of emissions. A better characterization of super-emitters is needed to operationalize ways to identify them and reduce emissions. We designed a conceptual framework that functionally defines superemitting sites as those with the highest proportional loss rates (methane emitted relative to methane produced). Using this concept, we estimated total methane emissions from natural gas production sites in the Barnett Shale; functionally superemitting sites accounted for roughly three-fourths of total emissions. We discuss the potential to reduce emissions from these sites, under the assumption that sites with high proportional loss rates have excess emissions resulting from abnormal or otherwise avoidable operating conditions, such as malfunctioning equipment. Because the population of functionally superemitting sites is not expected to be static over time, continuous monitoring will likely be necessary to identify them and improve their operation. This work suggests that achieving and maintaining uniformly low emissions across the entire population of production sites will require mitigation steps at a large fraction of sites.

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The development of horizontal hydraulic fracture drilling or “fracking” has allowed for the extraction of deep, unconventional shale gas deposits in various shale seams throughout the USA. One such shale seam, the Marcellus shale, extends through New York State, Pennsylvania, and West Virginia, where shale gas development has rapidly increased within the last decade. This has created a boom of economic activity surrounding the energy industry. However, this bounty comes with risks to environmental and public health and has led to divisive community polarization over the issue in the Marcellus shale region. In the face of potential environmental and social disruption, and a great deal of controversy surrounding “fracking” the oil and gas industry has had to undertake a myriad of public relations initiatives to legitimize their extraction efforts in the Marcellus shale region, and to frame the shale gas boom in a positive light to stakeholders. This article investigates one such public relations initiative, the Energy in Depth (EID) Northeast Marcellus Initiative. Through qualitative content analysis of EID's online web material, this article examines the ways in which the industry presents and frames natural gas development to the general public. Through appeals to patriotism, the use of environmental imagery, and a claimed commitment to scientific reason, the oil and gas industry uses EID to frame the shale gas extraction process in a positive light, all the while framing those who question or oppose the processes of shale gas extraction as irrational obstructionists.

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Shifting markets can cause unexpected, stochastic changes in rural landscapes that may take local communities by surprise. Preferential siting of new industrial facilities in poor areas or in areas with few regulatory restrictions can have implications for environmental sustainability, human health, and social justice. This study focuses on frac sand mining—the mining of high-quality silica sand used in hydraulic fracturing processes for gas and oil extraction. Frac sand mining gained prominence in the 2000s in the upper midwestern United States where nonmetallic mining is regulated primarily by local zoning. I asked whether frac sand mines were more commonly sited in rural townships without formal zoning regulations or planning processes than in those that undertook zoning and planning before the frac sand boom. I also asked if mine prevalence was correlated with socioeconomic differences across townships. After creating a probability surface to map areas most suitable for frac sand mine occurrence, I developed neutral landscape models from which to compare actual mine distributions in zoned and unzoned areas at three different spatial extents. Mines were significantly clustered in unzoned jurisdictions at the statewide level and in 7 of the 8 counties with at least three frac sand mines and some unzoned land. Subsequent regression analyses showed mine prevalence to be uncorrelated with land value, tax rate, or per capita income, but correlated with remoteness and zoning. The predicted mine count in unzoned townships was over two times higher than that in zoned townships. However, the county with the most mines by far was under a county zoning ordinance, perhaps indicating industry preferences for locations with clear, homogenous rules over patchwork regulation. Rural communities can use the case of frac sand mining as motivation to discuss and plan for sudden land-use predicaments, rather than wait to grapple with unfamiliar legal processes during a period of intense conflict.

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Development associated with natural gas extraction may have negative effects on wildlife. Here we assessed the effects of natural gas development on the distributions of three sagebrush-obligate birds (Brewer's Sparrow, Spizella breweri; Sagebrush Sparrow, Amphispiza belli; and Sage Thrasher, Oreoscoptes montanus) at a natural gas extraction site in Wyoming, USA. Two drivers of habitat disturbance were investigated: natural gas well pads and roadways. Disturbances were quantified on a small scale (minimum distance to a disturbance) and a large scale (landscape density of a disturbance). Their effects on the study species' distributions were assessed using a multi-scale occupancy model. Minimum distances to wells and roadways were found to not have significant impacts on small-scale occupancy. However, roadway and well density at the landscape-scale significantly impacted the large-scale occupancy of Sagebrush Sparrows and Sage Thrashers. The results confirmed our hypotheses that increasing road density negatively affects the landscape-scale occupancy rates of Sagebrush Sparrow and Sage Thrasher, but did not confirm our hypothesis that increasing well density would negatively impact large-scale occupancy. We therefore suggest that linear features that affect patch size may be more important than point features in determining sagebrush-obligate songbird occupancy when compared to structural effects such as habitat fragmentation and increased predation. We recommend that future well construction be focused along existing roadways, that horizontal drilling be used to reduce the need for additional roads, and that deactivation and restoration of roadways be implemented upon the deactivation of wells, we also recommend a possible mitigation strategy when new roads are to be built.

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Until now, up-to-date, comprehensive, spatial, national-scale data on hydraulic fracturing water volumes have been lacking. Water volumes used (injected) to hydraulically fracture over 263,859 oil and gas wells drilled between 2000 and 2014 were compiled and used to create the first U.S. map of hydraulic fracturing water use. Although median annual volumes of 15,275 m3 and 19,425 m3 of water per well was used to hydraulically fracture individual horizontal oil and gas wells, respectively, in 2014, about 42% of wells were actually either vertical or directional, which required less than 2600 m3 water per well. The highest average hydraulic fracturing water usage (10,000−36,620 m3 per well) in watersheds across the United States generally correlated with shale-gas areas (versus coalbed methane, tight oil, or tight gas) where the greatest proportion of hydraulically fractured wells were horizontally drilled, reflecting that the natural reservoir properties influence water use. This analysis also demonstrates that many oil and gas resources within a given basin are developed using a mix of horizontal, vertical, and some directional wells, explaining why large volume hydraulic fracturing water usage is not widespread. This spatial variability in hydraulic fracturing water use relates to the potential for environmental impacts such as water availability, water quality, wastewater disposal, and possible wastewater injection-induced earthquakes.

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In this work, the life cycle economic and environmental optimization of shale gas supply chain network design and operations is addressed. The proposed model covers the well-to-wire life cycle of electricity generated from shale gas, consisting of a number of stages including freshwater acquisition, shale well drilling, hydraulic fracturing and completion, shale gas production, wastewater management, shale gas processing, electricity generation as well as transportation and storage. A functional-unit based life cycle optimization problem for a cooperative shale gas supply chain is formulated as a multiobjective nonconvex mixed-integer nonlinear programming (MINLP) problem. The resulting Pareto-optimal frontier reveals the trade-off between the economic and environmental objectives. A case study based on Marcellus shale play shows that the greenhouse gas emission of electricity generated from shale gas ranges from 433 to 499 kg CO(2)e/MWh, and the levelized cost of electricity ranges from $69 to $91/MWh. A global optimization algorithm is also presented to improve computational efficiency.

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Development of shale gas entails environmental risk, particularly with respect to water resources, and stakeholders are keen to assess such risks before making development decisions. We focus on Pennsylvania, USA and the Marcellus Shale, the most productive shale play in the country. We examine compliance data recorded by the state regulatory agency in order to assess environmental risks and their trends and drivers over time. Overall, we track 3267 shale gas violations, noting that environmental violation rates increase from 2007 to 2009, remain high through 2010, and then drop in 2011 and thereafter. Violations related to spills and erosion were most commonly issued. A single change in policy resulted in a 45% decrease in environmental violation rates. Furthermore, for every 1% increase in wells drilled per inspections conducted, there was a 0.56% decrease in environmental violation rates. Similar effects were not found for administrative violations. Operator identity, price of gas, and other major policies were not significantly correlated with violation rates. In comparing conventional and shale gas extraction compliance we found that shale gas development entails more risk related to spills and solid waste management, while conventional development entails more risk associated with cementing and casing issues, and site restoration.

Abstract:
An improved spectroscopy is used to implement and optimize the retrieval strategy of ethane (C2H6) from ground-based Fourier Transform Infrared (FTIR) solar spectra recorded at the high-altitude station of Jungfraujoch (Swiss Alps, 46.5°N, 8.0°E, 3580 m a.s.l.). The improved spectroscopic parameters include C2H6 pseudo-lines in the 2720–3100 cm−1 range and updated line parameters for methyl chloride and ozone. These improved spectroscopic parameters allow for substantial reduction of the fitting residuals as well as enhanced information content. They also contribute to limiting oscillations responsible for ungeophysical negative mixing ratio profiles. This strategy has been successfully applied to the Jungfraujoch solar spectra available from 1994 onwards. The resulting time series is compared with C2H6 total columns simulated by the state-of-the-art chemical transport model GEOS-Chem. Despite very consistent seasonal cycles between both data sets, a negative systematic bias relative to the FTIR observations suggests that C2H6 emissions are underestimated in the current inventories implemented in GEOS-Chem. Finally, C2H6 trends are derived from the FTIR time series, revealing a statistically-significant sharp increase of the C2H6 burden in the remote atmosphere above Jungfraujoch since 2009. Evaluating cause of this change in the C2H6 burden, which may be related to the recent massive growth of shale gas exploitation in North America, is of primary importance for atmospheric composition and air quality in the Northern Hemisphere.

Abstract:
Development of shale gas resources using hydraulic fracturing has dramatically increased U.S. gas production, but also created new needs for risk analysis and governance. Risk analysis for an emerging technology has traditionally relied on experts with knowledge of the technology and its anticipated impacts. But today it is accepted that input from non-expert interested and affected parties (IAPs) is also essential. We present a novel method to elicit concerns from IAPs about the development of shale gas resources. We used an Internet-based snowball sample to identify IAPs and an open-ended prompt to gather their concerns. Reported concerns included potential consequences for environmental, social, and health systems, as well as hazards, hazardous events, precursors to hazards, risk amplifiers, and issues concerning the effective and fair governance of the risks. Some concerns raised have not been addressed in expert-led analyses of shale gas risks. Long-term consequences such as disruptions to economic activities, and governance issues such as regulatory capacity, were more prominent in the responses than in expert analyses. These findings show how engagement with interested and affected parties can elucidate key issues for risk governance in shale gas development. The method can also be applied to other emerging energy development issues.

Abstract:
Emissions of methane (CH4) and volatile organic compounds (VOCs) from oil and gas production may have large impacts on air quality and climate change. Methane and VOCs were measured over the Haynesville and Marcellus shale gas plays on board the National Center for Atmospheric Research C-130 and NOAA WP-3D research aircraft in June–July of 2013. We used an eddy covariance technique to measure in situ fluxes of CH4 and benzene from both C-130 flights with high-resolution data (10 Hz) and WP-3D flights with low-resolution data (1 Hz). Correlation (R = 0.65) between CH4 and benzene fluxes was observed when flying over shale gas operations, and the enhancement ratio of fluxes was consistent with the corresponding concentration observations. Fluxes calculated by the eddy covariance method show agreement with a mass balance approach within their combined uncertainties. In general, CH4 fluxes in the shale gas regions follow a lognormal distribution, with some deviations for relatively large fluxes (>10 µg m−2 s−1). Statistical analysis of the fluxes shows that a small number of facilities (i.e., ~10%) are responsible for up to ~40% of the total CH4 emissions in the two regions. We show that the airborne eddy covariance method can also be applied in some circumstances when meteorological conditions do not favor application of the mass balance method. We suggest that the airborne eddy covariance method is a reliable alternative and complementary analysis method to estimate emissions from oil and gas extraction.

Abstract:
An unprecedented increase in earthquakes in the U.S. mid-continent began in 2009. Many of these earthquakes have been documented as induced by wastewater injection. We examine the relationship between wastewater injection and U.S. mid-continent seismicity using a newly assembled injection well database for the central and eastern United States. We find that the entire increase in earthquake rate is associated with fluid injection wells. High-rate injection wells (>300,000 barrels per month) are much more likely to be associated with earthquakes than lower-rate wells. At the scale of our study, a well’s cumulative injected volume, monthly wellhead pressure, depth, and proximity to crystalline basement do not strongly correlate with earthquake association. Managing injection rates may be a useful tool to minimize the likelihood of induced earthquakes. Making quakes depends on injection rates Wastewater injection wells induce earthquakes that garner much attention, especially in tectonically inactive regions. Weingarten et al. combined information from public injection-well databases from the eastern and central United States with the best earthquake catalog available over the past 30 years. The rate of fluid injection into a well appeared to be the most likely decisive triggering factor in regions prone to induced earthquakes. Along these lines, Walsh III and Zoback found a clear correlation between areas in Oklahoma where waste saltwater is being injected on a large scale and areas experiencing increased earthquake activity. Science, this issue p. 1336; Sci. Adv. 10.1126/sciadv.1500195 (2015).

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Over the past 5 years, parts of Oklahoma have experienced marked increases in the number of small- to moderate-sized earthquakes. In three study areas that encompass the vast majority of the recent seismicity, we show that the increases in seismicity follow 5- to 10-fold increases in the rates of saltwater disposal. Adjacent areas where there has been relatively little saltwater disposal have had comparatively few recent earthquakes. In the areas of seismic activity, the saltwater disposal principally comes from “produced” water, saline pore water that is coproduced with oil and then injected into deeper sedimentary formations. These formations appear to be in hydraulic communication with potentially active faults in crystalline basement, where nearly all the earthquakes are occurring. Although most of the recent earthquakes have posed little danger to the public, the possibility of triggering damaging earthquakes on potentially active basement faults cannot be discounted. Increasingly frequent earthquakes in Oklahoma are linked to saltwater disposal. Increasingly frequent earthquakes in Oklahoma are linked to saltwater disposal.

Abstract:
The exploration of unconventional shale energy reserves and the extensive use of hydraulic fracturing during well stimulation have raised concerns about the potential effects of unconventional oil and gas extraction (UOG) on the environment. Most accounts of groundwater contamination have focused primarily on the compositional analysis of dissolved gases to address whether UOG activities have had deleterious effects on overlying aquifers. Here, we present an analysis of 550 groundwater samples collected from private and public supply water wells drawing from aquifers overlying the Barnett shale formation of Texas. We detected multiple volatile organic carbon compounds throughout the region, including various alcohols, the BTEX family of compounds, and several chlorinated compounds. These data do not necessarily identify UOG activities as the source of contamination; however, they do provide a strong impetus for further monitoring and analysis of groundwater quality in this region as many of the compounds we detected are known to be associated with UOG techniques.

Abstract:
China has the world's largest shale gas reserves, which might enable it to pursue a new pathway for electricity generation. This study employed hybrid LCI (life cycle inventory) models to quantify the ETW (extraction-to-wire) GHG (greenhouse gas) emissions and water consumption per kWh of coal- and shale gas-fired electricity in China. Results suggest that a coal-to-shale gas shift and upgrading coal-fired power generation technologies could provide pathways to less GHG and water intensive power in China. Compared to different coal-fired generation technologies, the ETW GHG emissions intensity of gas-fired CC (combined cycle) technology is 530 g CO2e/kWh, which is 38–45% less than China's present coal-fired electricity. Gas-fired CT (combustion turbine) technology has the lowest ETW water consumption intensity at 960 g/kWh, which is 34–60% lower than China's present coal-fired electricity. The GHG-water tradeoff of the two gas-fired power generation technologies suggests that gas-fired power generation technologies should be selected based on regional-specific water resource availabilities and electricity demand fluctuations in China. However, the low price of coal-fired electricity, high cost of shale gas production, insufficient pipeline infrastructures, and multiple consumers of shale gas resources may serve as barriers to a coal-to-shale gas shift in China's power sector in the near term.