Repository for Oil and Gas Energy Research (ROGER)

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Water and gas samples were collected from (1) nine shallow groundwater aquifers overlying Marcellus Shale in north-central West Virginia before active shale gas drilling, (2) wells producing gas from Upper Devonian sands and Middle Devonian Marcellus Shale in southwestern Pennsylvania, (3) coal-mine water discharges in southwestern Pennsylvania, and (4) streams in southwestern Pennsylvania and north-central West Virginia. Our preliminary results demonstrate that the oxygen and hydrogen isotope composition of water, carbon isotope composition of dissolved inorganic carbon, and carbon and hydrogen isotope compositions of methane in Upper Devonian sands and Marcellus Shale are very different compared with shallow groundwater aquifers, coal-mine waters, and stream waters of the region. Therefore, spatiotemporal stable isotope monitoring of the different sources of water before, during, and after hydraulic fracturing can be used to identify migrations of fluids and gas from deep formations that are coincident with shale gas drilling.

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Advances in drilling technologies and production strategies such as horizontal drilling and hydraulic fracturing have significantly improved the production of natural gas by stimulating fluid flow from wells. Since 2008, these technological developments have spurred exponential growth of gas well drilling across the U.S. While the new drilling for shale gas and hydraulic fracturing technologies have dramatically changed the energy landscape in the U.S., recent scientific findings show evidence for contamination of water resources. This paper provides key observations for the potential risks of shale gas drilling and hydraulic fracturing on the quality of water resources and include: (1) stray gas contamination of shallow groundwater overlying shale gas basins; (2) pathways and hydraulic connectivity between the deep shale gas formations and the overlying shallow drinking water aquifers; and (3) inadequate disposal of produced and flowback waters associated with shale gas exploration that causes contamination of surface waters and long-term ecological effects. By using geochemical (e.g., Br/Cl) integrated with oxygen, hydrogen, strontium, radium, and boron isotopic tracers, we have characterized the geochemical fingerprints of brines from several shale gas basins in the USA, including the Utica and Marcellus brines in the Appalachian Basin and the Fayetteville brines in Arkansas. We use these geochemical fingerprints to delineate the impact of shale gas associated fluids on the environment.

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Structured Abstract Background Natural gas has recently emerged as a relatively clean energy source that offers the opportunity for a number of regions around the world to reduce their reliance on energy imports. It can also serve as a transition fuel that will allow for the shift from coal to renewable energy resources while helping to reduce the emissions of CO2, criteria pollutants, and mercury by the power sector. Horizontal drilling and hydraulic fracturing make the extraction of tightly bound natural gas from shale formations economically feasible. These technologies are not free from environmental risks, however, especially those related to regional water quality, such as gas migration, contaminant transport through induced and natural fractures, wastewater discharge, and accidental spills. The focus of this Review is on the current understanding of these environmental issues. Drilling multiple horizontal wells from a single well pad allows access to as much as 1 square mile of shale that is located more than a mile below. [Image courtesy of Range Resources Appalachia] Advances The most common problem with well construction is a faulty seal that is emplaced to prevent gas migration into shallow groundwater. The incidence rate of seal problems in unconventional gas wells is relatively low (1 to 3%), but there is a substantial controversy whether the methane detected in private groundwater wells in the area where drilling for unconventional gas is ongoing was caused by well drilling or natural processes. It is difficult to resolve this issue because many areas have long had sources of methane unrelated to hydraulic fracturing, and pre-drilling baseline data are often unavailable. Water management for unconventional shale gas extraction is one of the key issues that will dominate environmental debate surrounding the gas industry. Reuse of produced water for hydraulic fracturing is currently addressing the concerns regarding the vast quantities of contaminants that are brought to the surface. As these well fields mature and the opportunities for wastewater reuse diminish, the need to find alternative management strategies for this wastewater will likely intensify. Outlook Improved understanding of the fate and transport of contaminants of concern and increased long-term monitoring and data dissemination will help effectively manage water-quality risks associated with unconventional gas industry today and in the future. Confidentiality requirements dictated by legal investigations combined with the expedited rate of development and the limited funding for research are major impediments to peer-reviewed research into environmental impacts. Now is the time to work on these environmental issues to avoid an adverse environmental legacy similar to that from abandoned coal mine discharges in Pennsylvania. Fracturing Hydrology? Hydraulic fracturing, widely known as "fracking," is a relatively inexpensive way to tap into what were previously inaccessible natural gas resources. Vidic et al. (p. 826) review the current status of shale gas development and discuss the possible threats to water resources. In one of the hotbeds of fracking activity, the Marcellus Shale in the eastern United States, there is little evidence that additives have directly entered groundwater supplies, but the risk remains. Ensuring access to monitoring data is an important first step toward addressing any public and environmental health concerns. Unconventional natural gas resources offer an opportunity to access a relatively clean fossil fuel that could potentially lead to energy independence for some countries. Horizontal drilling and hydraulic fracturing make the extraction of tightly bound natural gas from shale formations economically feasible. These technologies are not free from environmental risks, however, especially those related to regional water quality, such as gas migration, contaminant transport through induced and natural fractures, wastewater discharge, and accidental spills. We review the current understanding of environmental issues associated with unconventional gas extraction. Improved understanding of the fate and transport of contaminants of concern and increased long-term monitoring and data dissemination will help manage these water-quality risks today and in the future.

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Testing of 1701 water wells in northeastern Pennsylvania shows that methane is ubiquitous in groundwater, with higher concentrations observed in valleys vs. upland areas and in association with calcium-sodium-bicarbonate, sodium-bicarbonate, and sodium-chloride rich waters-indicating that, on a regional scale, methane concentrations are best correlated to topographic and hydrogeologic features, rather than shale-gas extraction. In addition, our assessment of isotopic and molecular analyses of hydrocarbon gases in the Dimock Township suggest that gases present in local water wells are most consistent with Middle and Upper Devonian gases sampled in the annular spaces of local gas wells, as opposed to Marcellus Production gas. Combined, these findings suggest that the methane concentrations in Susquehanna County water wells can be explained without the migration of Marcellus shale gas through fractures, an observation that has important implications for understanding the nature of risks associated with shale-gas extraction.

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Unconventional natural gas development in Pennsylvania has created a new wastewater stream. In an effort to stop the discharge of Marcellus Shale unconventional natural gas development wastewaters into surface waters, on May 19, 2011 the Pennsylvania Department of Environmental Protection (PADEP) requested drilling companies stop disposing their wastewater through wastewater treatment plants (WWTPs). This research includes a chemical analysis of effluents discharged from three WWTPs before and after the aforementioned request. The WWTPs sampled included two municipal, publicly owned treatment works and a commercially operated industrial wastewater treatment plant. Analyte concentrations were quanitified and then compared to water quality criteria, including U.S. Environmental Protection Agency MCLs and "human health criteria." Certain analytes including barium, strontium, bromides, chlorides, total dissolved solids, and benzene were measured in the effluent at concentrations above criteria. Analyte concentrations measured in effluent samples before and after the PADEP's request were compared for each facility. Analyte concentrations in the effluents decreased in the majority of samples after the PADEP's request (p < .05). This research provides preliminary evidence that these and similar WWTPs may not be able to provide sufficient treatment for this wastewater stream, and more thorough monitoring is recommended.

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Concerns have arisen among the public regarding the potentialfor drinking-water contamination from the migration of methane gas and hazardous chemicals associated with hydraulic fracturing and horizontal drilling. However, little attention has been paid to the potentialfor groundwater contamination resulting from surface spills from storage and production facilities at active well sites. We performed a search for publically available data regarding groundwater contamination from spills at ULS. drilling sites. The Colorado Oil and Gas Conservation Commission (COGCC) database was selected for further analysis because it was the most detailed. The majority ofspills were in Weld County, Colorado, which has the highest density of wells that used hydraulic fracturing for completion, many producing both methane gas and crude oil. We analyzed publically available data reported by operators to the COGCC regarding surface spills that impacted groundwater From July 2010 to July 2011, we noted 77 reported surface spills impacting the groundwater in Weld County, which resulted in surface spills associated with less than 0.5% of the active wells. The reported data included groundwater samples that were analyzed for benzene, toluene, ethylbenzene, andxylene (BTEX) components of crude oil. For groundwater samples taken both within the spill excavation area and on the first reported date of sampling, the BTEX measurements exceeded National Drinking Water maximum contaminant levels (MCLs) in 90, 30, 12, and 8% of the samples, respectively. However, actions taken to remediate the spills were effective at reducing BJTEX levels, with at least 84% of the spills reportedly achieving remediation as of May 2012. Our analysis demonstrates that surface spills are an important route of potential groundwater contamination from hydraulic fracturing activities and should be a focus of programs to protect groundwater IMPLICATIONS: While benzene can occur naturally in groundwater sources, spills and migration of chemicals used for hydraulic fracturing activities have recently been thought to be a main source of benzene contamination in groundwater. However, there is little scientific literature to support that claim. Therefore, we accessed a publically available database and tracked the number of reported surface spills with potential groundwater impact over a 1-year period. Although the number of surface spills was minimal, our analysis provides scientific evidence that benzene can contaminate groundwater sources following surface spills at active well sites.

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Concern has been raised in the scientific literature about the environmental implications of extracting natural gas from deep shale formations, and published studies suggest that shale gas development may affect local groundwater quality. The potential for surface water quality degradation has been discussed in prior work, although no empirical analysis of this issue has been published. The potential for large-scale surface water quality degradation has affected regulatory approaches to shale gas development in some US states, despite the dearth of evidence. This paper conducts a large-scale examination of the extent to which shale gas development activities affect surface water quality. Focusing on the Marcellus Shale in Pennsylvania, we estimate the effect of shale gas wells and the release of treated shale gas waste by permitted treatment facilities on observed downstream concentrations of chloride (Cl(-)) and total suspended solids (TSS), controlling for other factors. Results suggest that (i) the treatment of shale gas waste by treatment plants in a watershed raises downstream Cl(-) concentrations but not TSS concentrations, and (ii) the presence of shale gas wells in a watershed raises downstream TSS concentrations but not Cl(-) concentrations. These results can inform future voluntary measures taken by shale gas operators and policy approaches taken by regulators to protect surface water quality as the scale of this economically important activity increases.

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The risk of contaminating surface and groundwater as a result of shale gas extraction using high-volume horizontal hydraulic fracturing (fracking) has not been assessed using conventional risk assessment methodologies. Baseline (pre-fracking) data on relevant water quality indicators, needed for meaningful risk assessment, are largely lacking. To fill this gap, the nonprofit Community Science Institute (CSI) partners with community volunteers who perform regular sampling of more than 50 streams in the Marcellus and Utica Shale regions of upstate New York; samples are analyzed for parameters associated with HVHHF. Similar baseline data on regional groundwater comes from CSI's testing of private drinking water wells. Analytic results for groundwater (with permission) and surface water are made publicly available in an interactive, searchable database. Baseline concentrations of potential contaminants from shale gas operations are found to be low, suggesting that early community-based monitoring is an effective foundation for assessing later contamination due to fracking.

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The risk of groundwater contamination from shale gas exploration and development is a major societal concern, especially in populated areas where groundwater is an essential source of drinking water and for agricultural or industrial use. Since groundwater decontamination is difficult, or nearly impossible, it is essential to evaluate exploration and production conditions that would prevent or at least minimize risks of groundwater contamination. The current consensus in recent literature is that these risks are primarily related to engineering issues, including casing integrity and surface activities, such as truck traffic (equipment and fluid haulage), waste management (mainly drill cuttings), and water storage and treatment when hydraulic fracturing is utilized. Concerns have also been raised with respect to groundwater contamination that could result from potential fracture or fault interconnections between the shale unit and surficial aquifers, which would allow fracturing fluids and methane to reach the surface away from the wellbore. Despite the fact that groundwater resources are relatively well characterized in some regions, there is currently no recognized method to evaluate the vulnerability or risks to aquifers resulting from hydrocarbon industry operations carried out at great depths. This paper focuses on the Utica Shale of the St. Lawrence Platform (Quebec), where an environmental study aiming to evaluate potential risks for aquifers related to shale gas development has been initiated. To provide the context of these research efforts, this paper describes the regional tectono-stratigraphic evolution and current stress regime of the Cambrian–Ordovician St. Lawrence Platform, as well as the Utica Shale internal stratigraphy, mineralogy and thermal maturation. Then, the hydrogeological context of the St. Lawrence Platform is discussed. Finally, the methodology for this environmental study, based on geological, geophysical, geomechanical, hydrogeological and geochemical data, is presented.

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Salts are frequently a major constituent of waste waters produced during oil and gas production. These produced waters or brines must be treated and/or disposed and provide a daily challenge for operators and resource managers. Some elements of salts are regulated with water quality criteria established for the protection of aquatic wildlife, e.g. chloride (Cl−), which has an acute standard of 860 mg/L and a chronic standard of 230 mg/L. However, data for establishing such standards has only recently been studied for other components of produced water, such as bicarbonate (HCO3−), which has acute median lethal concentrations (LC50s) ranging from 699 to > 8000 mg/L and effects on chronic toxicity from 430 to 657 mg/L. While Cl− is an ion of considerable importance in multiple geographical regions, knowledge about the effects of hardness (calcium and magnesium) on its toxicity and about mechanisms of toxicity is not well understood. A multiple-approach design that combines studies of both individuals and populations, conducted both in the laboratory and the field, was used to study toxic effects of bicarbonate (as NaHCO3). This approach allowed interpretations about mechanisms related to growth effects at the individual level that could affect populations in the wild. However, additional mechanistic data for HCO3−, related to the interactions of calcium (Ca2 +) precipitation at the microenvironment of the gill would dramatically increase the scientific knowledge base about how NaHCO3 might affect aquatic life. Studies of the effects of mixtures of multiple salts present in produced waters and more chronic effect studies would give a better picture of the overall potential toxicity of these ions. Organic constituents in hydraulic fracturing fluids, flowback waters, etc. are a concern because of their carcinogenic properties and this paper is not meant to minimize the importance of maintaining vigilance with respect to potential organic contamination.

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Oil and natural gas have been the main sources of primary energy in the USA, providing 63% of the total energy consumption in 2011. Petroleum production, drilling operations, and improperly sealed abandoned wells have caused significant local groundwater contamination in many states, including at the USGS OSPER sites in Oklahoma. The potential for groundwater contamination is higher when producing natural gas and oil from unconventional sources of energy, including shale and tight sandstones. These reservoirs require horizontally-completed wells and massive hydraulic fracturing that injects large volumes (up to 50,000 m3/well) of high-pressured water with added proppant, and toxic organic and inorganic chemicals. Recent results show that flow back and produced waters from Haynesville (Texas) and Marcellus (Pennsylvania) Shale have high salinities (≥200,000 mg/L TDS) and high NORMs (up to 10,000 picocuries/L) concentrations. A major research effort is needed worldwide to minimize all potential environmental impacts, especially groundwater contamination and induced seismicity, when producing these extremely important new sources of energy.

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Hydraulic fracturing of deep shale beds to develop natural gas has caused concern regarding the potential for various forms of water pollution. Two potential pathways—advective transport through bulk media and preferential flow through fractures—could allow the transport of contaminants from the fractured shale to aquifers. There is substantial geologic evidence that natural vertical flow drives contaminants, mostly brine, to near the surface from deep evaporite sources. Interpretative modeling shows that advective transport could require up to tens of thousands of years to move contaminants to the surface, but also that fracking the shale could reduce that transport time to tens or hundreds of years. Conductive faults or fracture zones, as found throughout the Marcellus shale region, could reduce the travel time further. Injection of up to 15,000,000 L of fluid into the shale generates high pressure at the well, which decreases with distance from the well and with time after injection as the fluid advects through the shale. The advection displaces native fluids, mostly brine, and fractures the bulk media widening existing fractures. Simulated pressure returns to pre-injection levels in about 300 d. The overall system requires from 3 to 6 years to reach a new equilibrium reflecting the significant changes caused by fracking the shale, which could allow advective transport to aquifers in less than 10 years. The rapid expansion of hydraulic fracturing requires that monitoring systems be employed to track the movement of contaminants and that gas wells have a reasonable offset from faults.

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The maximum reported height of an upward propagating hydraulic fracture from several thousand fracturing operations in the Marcellus, Barnett, Woodford, Eagle Ford and Niobrara shale (USA) is ∼588 m. Of the 1170 natural hydraulic fracture pipes imaged with three-dimensional seismic data offshore of West Africa and mid-Norway it is ∼1106 m. Based on these empirical data, the probability of a stimulated and natural hydraulic fracture extending vertically >350 m is ∼1% and ∼33% respectively. Constraining the probability of stimulating unusually tall hydraulic fractures in sedimentary rocks is extremely important as an evidence base for decisions on the safe vertical separation between the depth of stimulation and rock strata not intended for penetration.

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Silurian and Devonian natural gas reservoirs present within New York state represent an example of unconventional gas accumulations within the northern Appalachian Basin. These unconventional energy resources, previously thought to be noneconomically viable, have come into play following advances in drilling (i.e., horizontal drilling) and extraction (i.e., hydraulic fracturing) capabilities. Therefore, efforts to understand these and other domestic and global natural gas reserves have recently increased. The suspicion of fugitive mass migration issues within current Appalachian production fields has catalyzed the need to develop a greater understanding of the genetic grouping (source) and migrational history of natural gases in this area. We introduce new noble gas data in the context of published hydrocarbon carbon (C1,C2+) (delta13C) data to explore the genesis of thermogenic gases in the Appalachian Basin. This study includes natural gases from two distinct genetic groups: group 1, Upper Devonian (Marcellus shale and Canadaway Group) gases generated in situ, characterized by early mature (Delta13C[C1 minus C2][delta13C1minusdelta13C2]: lt–9permil), isotopically light methane, with low (4He) (average, 1 times 10minus3 cc/cc) elevated 4He/40Arast and 21Neast/40Arast (where the asterisk denotes excess radiogenic or nucleogenic production beyond the atmospheric ratio), and a variable, atmospherically (air-saturated–water) derived noble gas component; and group 2, a migratory natural gas that emanated from Lower Ordovician source rocks (i.e., most likely, Middle Ordovician Trenton or Black River group) that is currently hosted primarily in Lower Silurian sands (i.e., Medina or Clinton group) characterized by isotopically heavy, mature methane (Delta13C[C1 – C2] [delta13C1minusdelta13C2]: gt3permil), with high (4He) (average, 1.85 times 10minus3 cc/cc) 4He/40Arast and 21Neast/40Arast near crustal production levels and elevated crustal noble gas content (enriched 4He, 21Neast, 40Arast). Because the release of each crustal noble gas (i.e., He, Ne, Ar) from mineral grains in the shale matrix is regulated by temperature, natural gases obtain and retain a record of the thermal conditions of the source rock. Therefore, noble gases constitute a valuable technique for distinguishing the genetic source and post-genetic processes of natural gases.

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In recent years, shale gas formations have become economically viable through the use of horizontal drilling and hydraulic fracturing. These techniques carry potential environmental risk due to their high water use and substantial risk for water pollution. Using probability bounds analysis, we assessed the likelihood of water contamination from natural gas extraction in the Marcellus Shale. Probability bounds analysis is well suited when data are sparse and parameters highly uncertain. The study model identified five pathways of water contamination: transportation spills, well casing leaks, leaks through fractured rock, drilling site discharge, and wastewater disposal. Probability boxes were generated for each pathway. The potential contamination risk and epistemic uncertainty associated with hydraulic fracturing wastewater disposal was several orders of magnitude larger than the other pathways. Even in a best-case scenario, it was very likely that an individual well would release at least 200 m³ of contaminated fluids. Because the total number of wells in the Marcellus Shale region could range into the tens of thousands, this substantial potential risk suggested that additional steps be taken to reduce the potential for contaminated fluid leaks. To reduce the considerable epistemic uncertainty, more data should be collected on the ability of industrial and municipal wastewater treatment facilities to remove contaminants from used hydraulic fracturing fluid.

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The debate surrounding the safety of shale gas development in the Appalachian Basin has generated increased awareness of drinking water quality in rural communities. Concerns include the potential for migration of stray gas, metal-rich formation brines, and hydraulic fracturing and/or flowback fluids to drinking water aquifers. A critical question common to these environmental risks is the hydraulic connectivity between the shale gas formations and the overlying shallow drinking water aquifers. We present geochemical evidence from northeastern Pennsylvania showing that pathways, unrelated to recent drilling activities, exist in some locations between deep underlying formations and shallow drinking water aquifers. Integration of chemical data (Br, Cl, Na, Ba, Sr, and Li) and isotopic ratios (87Sr/86Sr, 2H/H, 18O/16O, and 228Ra/226Ra) from this and previous studies in 426 shallow groundwater samples and 83 northern Appalachian brine samples suggest that mixing relationships between shallow ground water and a deep formation brine causes groundwater salinization in some locations. The strong geochemical fingerprint in the salinized (Cl > 20 mg/L) groundwater sampled from the Alluvium, Catskill, and Lock Haven aquifers suggests possible migration of Marcellus brine through naturally occurring pathways. The occurrences of saline water do not correlate with the location of shale-gas wells and are consistent with reported data before rapid shale-gas development in the region; however, the presence of these fluids suggests conductive pathways and specific geostructural and/or hydrodynamic regimes in northeastern Pennsylvania that are at increased risk for contamination of shallow drinking water resources, particularly by fugitive gases, because of natural hydraulic connections to deeper formations.

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Identifying the source of stray gas in drinking water supplies principally relies on comparing the gas composition in affected water supplies with gas samples collected in shows while drilling, produced gases, casing head gases, pipeline gases, and other potential point sources. However, transport dynamics of free and dissolved gas migration in groundwater aquifers can modify both the concentration and the composition of point source stray gases flowing to aquifers and occurring in the groundwater environment. Accordingly, baseline and forensic investigations related to stray gas sources need to address the effects of mixing, dilution, and oxidation reactions in the context of regional and local hydrology. Understanding and interpreting such effects are best addressed by collecting and analyzing multiple samples from baseline groundwater investigations, potential point sources, and impacted water resources. Several case studies presented here illustrate examples of the natural variability in gas composition and concentration data evident when multiple samples are collected from produced gases, casing head gases, and baseline groundwater investigations. Results show that analyses of single samples from either potential contaminant point sources or groundwater and surface water resources may not always be sufficient to document site-specific baseline conditions. Results also demonstrate the need to consistently sample and analyze a variety of baseline groundwater and gas composition screening parameters. A multidisciplinary approach is the best practice for differentiating among the effects of fluid and gas mixing, dilution, and natural attenuation.

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Shale gas resources are relatively plentiful in the United States and in many countries and regions around the world. Development of these resources is moving ahead amidst concerns regarding environmental risks, especially to water resources. The complex nature of this distributed extractive industry, combined with limited impact data, makes establishing possible effects and designing appropriate regulatory responses challenging. Here we move beyond the project level impact assessment approach to use regional collective impact analysis in order to assess a subset of potential water management policy options. Specifically, we examine hypothetical water withdrawals for hydraulic fracturing and the subsequent treatment of wastewater that could be returned or produced from future active shale gas wells in the currently undeveloped Susquehanna River Basin region of New York. Our results indicate that proposed water withdrawal management strategies may not provide greater environmental protection than simpler approaches. We suggest a strategy that maximizes protectiveness while reducing regulatory complexity. For wastewater treatment, we show that the Susquehanna River Basin region of New York State has limited capacity to treat wastewater using extant municipal infrastructure. We suggest that modest private investment in industrial treatment facilities can achieve treatment goals without putting public systems at risk. We conclude that regulation of deterministic water resource impacts of shale gas extraction should be approached on a regional, collective basis, and suggest that water resource management objectives can be met by balancing the need for development with environmental considerations and regulatory constraints.

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An overview is given of the mechanisms and processes (viscous flow, diffusion, sorption, desorption) affecting transport in unconventional reservoir rocks. Processes are described, terms and definitions are given, and selected literature data are presented to document the state of knowledge and the data situation on gas, water and two-phase flow in low-permeable lithotypes. Gas transport in the matrix of shales and coals is controlled by and may be restricted to diffusion. Depending on the gas type (e.g. methane or carbon dioxide), transport may be strongly affected by sorption. In many instances, high capillary threshold pressures prevent gas from moving as a continuous phase through the conducting pore network. In contrast, tight sandstone reservoir rocks allow for capillary-controlled viscous flow of a gas phase. Because in these rocks the determination of the water saturation at the prevailing flow conditions is difficult or impossible, we propose to directly use the relationship between effective gas permeability and capillary pressure for the description of two-phase (gas/water) flow in these rocks. In ongoing studies this relationship is being studied systematically for both, steady state and non-steady state saturation conditions.

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Directional drilling and hydraulic-fracturing technologies are dramatically increasing natural-gas extraction. In aquifers overlying the Marcellus and Utica shale formations of northeastern Pennsylvania and upstate New York, we document systematic evidence for methane contamination of drinking water associated with shale-gas extraction. In active gas-extraction areas (one or more gas wells within 1 km), average and maximum methane concentrations in drinking-water wells increased with proximity to the nearest gas well and were 19.2 and 64 mg CH4 L-1 (n = 26), a potential explosion hazard; in contrast, dissolved methane samples in neighboring nonextraction sites (no gas wells within 1 km) within similar geologic formations and hydrogeologic regimes averaged only 1.1 mg L-1 (P < 0.05; n = 34). Average δ13C-CH4 values of dissolved methane in shallow groundwater were significantly less negative for active than for nonactive sites (-37 ± 7‰ and -54 ± 11‰, respectively; P < 0.0001). These δ13C-CH4 data, coupled with the ratios of methane-to-higher-chain hydrocarbons, and δ2H-CH4 values, are consistent with deeper thermogenic methane sources such as the Marcellus and Utica shales at the active sites and matched gas geochemistry from gas wells nearby. In contrast, lower-concentration samples from shallow groundwater at nonactive sites had isotopic signatures reflecting a more biogenic or mixed biogenic/thermogenic methane source. We found no evidence for contamination of drinking-water samples with deep saline brines or fracturing fluids. We conclude that greater stewardship, data, and—possibly—regulation are needed to ensure the sustainable future of shale-gas extraction and to improve public confidence in its use.

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The origin of the combustible gases in groundwater from glacial-outwash and fractured-bedrock aquifers was investigated in northern Tioga County, Pennsylvania. Thermogenic methane (CH4) and ethane (C2H6) and microbial CH4 were found. Microbial CH4 is from natural in situ processes in the shale bedrock and occurs chiefly in the bedrock aquifer. The δ13C values of CH4 and C2H6 for the majority of thermogenic gases from water wells either matched or were between values for the samples of non-native storage-field gas from injection wells and the samples of gas from storage-field observation wells. Traces of C2H6 with microbial CH4 and a range of C and H isotopic compositions of CH4 indicate gases of different origins are mixing in sub-surface pathways; gas mixtures are present in groundwater. Pathways for gas migration and a specific source of the gases were not identified. Processes responsible for the presence of microbial gases in groundwater could be elucidated with further geochemical study.

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In this study, the geochemistry and origin of natural gas and formation waters in Devonian age organic-rich shales and reservoir sandstones across the northern Appalachian Basin margin (western New York, eastern Ohio, northwestern Pennsylvania, and eastern Kentucky) were investigated. Additional samples were collected from Mississippian Berea Sandstone, Silurian Medina Sandstone and Ordovician Trenton/Black River Group oil and gas wells for comparison. Dissolved gases in shallow groundwaters in Devonian organic-rich shales along Lake Erie contain detectable CH4 (0.01–50.55 mol%) with low δ13C–CH4 values (−74.68 to −57.86‰) and no higher chain hydrocarbons, characteristics typical of microbial gas. Nevertheless, these groundwaters have only moderate alkalinity (1.14–8.72 meq/kg) and relatively low δ13C values of dissolved inorganic C (DIC) (−24.8 to −0.6‰), suggesting that microbial methanogenesis is limited. The majority of natural gases in Devonian organic-rich shales and sandstones at depth (>168 m) in the northern Appalachian Basin have a low CH4 to ethane and propane ratios (3–35 mol%; C1/C2 + C3) and high δ13C and δD values of CH4 (−53.35 to −40.24‰, and −315.0 to −174.6‰, respectively), which increase in depth, reservoir age and thermal maturity; the molecular and isotopic signature of these gases show that CH4 was generated via thermogenic processes. Despite this, the geochemistry of co-produced brines shows evidence for microbial activity. High δ13C values of DIC (>+10‰), slightly elevated alkalinity (up to 12.01 meq/kg) and low SO4 values (<1 mmole/L) in select Devonian organic-rich shale and sandstone formation water samples suggest the presence of methanogenesis, while low δ13C–DIC values (<−22‰) and relatively high SO4 concentrations (up to 12.31 mmole/L) in many brine samples point to SO4 reduction, which likely limits microbial CH4 generation in the Appalachian Basin. Together the formation water and gas results suggest that the vast majority of CH4 in the Devonian organic-rich shales and sandstones across the northern Appalachian Basin margin is thermogenic in origin. Small accumulations of microbial CH4 are present at shallow depths along Lake Erie and in western NY.