Repository for Oil and Gas Energy Research (ROGER)

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High-volume, hydraulic fracturing (HVHF) is widely applied for natural gas and oil production from shales, coals or tight sandstone formations in the United States, Canada, and Australia, and is being widely considered by other countries with similar unconventional energy resources. Secure retention of fluids (natural gas, saline formation waters, oil, HVHF fluids) during and after well stimulation is important to prevent unintended environmental contamination, and release of greenhouse gases to the atmosphere. Here, we critically review state-of-the-art techniques and promising new approaches for identifying oil and gas production from unconventional reservoirs to resolve whether they are the source of fugitive methane and associated contaminants into shallow aquifers. We highlight future research needs and propose a phased program, from generic baseline to highly specific analyses, to inform HVHF and unconventional oil and gas production and impact assessment studies. These approaches may also be applied to broader subsurface exploration and development issues (e.g., groundwater resources), or new frontiers of low-carbon energy alternatives (e.g., subsurface H2 storage, nuclear waste isolation, geologic CO2 sequestration).

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Hydraulic fracturing in shale/tight gas reservoirs creates fracture network systems that can intersect pre-existing subsurface flow pathways, e.g. fractures, faults or abandoned wells. This way, hydraulic fracturing operations could possibly pose environmental risks to shallow groundwater systems. This paper explores the long-term (>30 years) flow and transport of fracturing fluids into overburden layers and groundwater aquifers through a leaky abandoned well, using the geological setting of North German Basin as a case study. A three-dimensional model consisting of 15 sedimentary layers with three hydrostratigraphic units representing the hydrocarbon reservoir, overburden, and the aquifer is built. The model considers one perforation location at the first section of the horizontal part of the well, and a discrete hydraulic fracture intersecting an abandoned well. A sensitivity analysis is carried out to quantify and understand the influence of a broad spectrum of field possibilities (reservoir properties, overburden properties, salinity, abandoned well properties and its proximity to hydraulic fractures) on the flow of fracturing fluid to shallower permeable strata. The model results suggest the spatial properties of the abandoned well as well as its distance from the hydraulic fracture are the most important factors influencing the vertical flow of fracturing fluid. It is observed that even for various field settings, only a limited amount fracturing fluid can reach the aquifer in a long-term period.

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In PNAS, Woda et al. (1) present the results of a multidimensional investigation of the impacts of several hydraulically fractured shale gas wells on an aquifer and a hydrologically connected stream in a particular area in central Pennsylvania. The stream, Sugar Run, has been impacted by migration of methane into it. Sugar Run has inflow of groundwater from aquifers overlying the Marcellus Shale, which is relatively close to the land surface in the study area (e.g., one shale gas well of primary focus in the study is reported to intersect the Marcellus Shale at a depth of 997 m). Stream samples and groundwater samples were collected upstream and downstream from a location in Sugar Run where intermittent bubbling and groundwater seepage have been observed for at least 4 y since intensive shale gas development began in the study area in 2008. Samples were analyzed for dissolved methane; Na, Ca, Mg, Fe, Mn, SO42−, Cl−, and other inorganic solutes; carbon and strontium isotopes; and noble gases. The authors also obtained and analyzed regional groundwater-quality data and water-quality data for Sugar Run before shale gas development. Analysis of the water-quality data with consideration of regional characteristics and surface and groundwater characteristics before shale gas development led Woda et al. (1) to conclude from multiple lines of evidence that Sugar Run and the aquifer(s) that provide inflow to the stream have been contaminated by “new methane” mobilized by the shale gas development. They propose a water-quality indicator of the presence of recent methane contamination, namely, high sulfate (>6 mg/L) and iron (>0.3 mg/L) in waters with high methane concentrations. The protocol developed by the authors for use of aqueous geochemical conditions to identify impacts associated with new methane will be useful in the Marcellus region and, perhaps, in … [↵][1]1Email: dzombak{at}cmu.edu. [1]: #xref-corresp-1-1

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Hydraulic fracturing (fracking) is a process used for the stimulation and production of ultra-low permeability shale gas and tight oil resources. Fracking poses two main risks to groundwater quality: (1) stray gas migration and (2) potential contamination from chemical and fluid spills. Risk assessment is complicated by the lack of predrilling baseline measurements, limited access to well sites and industry data, the constant introduction of new chemical additives to frack fluids, and difficulties comparing data sets obtained by different sampling and analytical methods. Specific recommendations to reduce uncertainties and meet science needs for better assessment of groundwater risks include improving data-sharing among researchers, adopting standardized methodologies, collecting predrilling baseline data, installing dedicated monitoring wells, developing shale-specific environmental indicators, and providing greater access to field sites, samples, and industry data to the research community.

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Shale gas development has been heralded as a game changer that has had, and will continue to have, repercussions for energy scenarios around the world, and natural gas has been hailed as the transition fuel to a low carbon future. Shale gas production-made feasible and economical by advances in hydraulic fracturing-offers a solution in the face of increased demand, instability in key producing regions, and societal aversion to the risks of nuclear energy. This "golden future," however, has come into conflict with increasing concerns over water. This paper examines policy and regulatory frameworks around hydraulic fracturing in Texas and Spain in order to consider the trade-offs-particularly at the expense of water security-that may occur as decision-makers pursue improvements in energy security. We compare regulatory, institutional, and cultural contexts in order to understand and evaluate the robustness of these frameworks to prevent the reduction in water security as a consequence of the pursuit of energy security. Paucity of data is discussed. We also consider questions such as disclosure of information to the public about water use or the chemical composition of frac fluids and public opinion about hydraulic fracturing. Lessons are drawn that may assist policymakers who seek to guarantee water security while pursuing energy security.

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Shale gas extraction through hydraulic fracturing and horizontal drilling is increasing in China, particularly in Sichuan Basin. Production of unconventional shale gas with minimal environmental effects requires adequate management of wastewater from flowback and produced water (FP water) that is coextracted with natural gas. Here we present, for the first time, inorganic chemistry and multiple isotope (oxygen, hydrogen, boron, strontium, radium) data for FP water from 13 shale gas wells from the Lower Silurian Longmaxi Formation in the Weiyuan gas field, as well as produced waters from 35 conventional gas wells from underlying (Sinian, Cambrian) and overlying (Permian, Triassic) formations in Sichuan Basin. The chemical and isotope data indicate that the formation waters in Sichuan Basin originated from relics of different stages of evaporated seawater modified by water-rock interactions. The FP water from shale gas wells derives from blending of injected hydraulic fracturing water and entrapped saline (Cl ∼ 50,000 mg/L) formation water. Variations in the chemistry, δ18O, δ11B, and 87Sr/86Sr of FP water over time indicate that the mixing between the two sources varies with time, with a contribution of 75% (first 6 months) to 20% (>year) of the injected hydraulic fracturing water in the blend that compose the FP water. Mass-balance calculation suggests that the returned hydraulic fracturing water consisted of 28-49% of the volume of the injected hydraulic fracturing water, about a year after the initial hydraulic fracturing. We show differential mobilization of Na, B, Sr, and Li from the shale rocks during early stages of operation, which resulted in higher Na/Cl, B/Cl, Li/Cl, and 87Sr/86Sr and lower δ11B of the FP water during early stages of FP water formation relative to the original saline formation water recorded in late stages FP water. This study provides a geochemical framework for characterization of formation waters from different geological strata, and thus the ability to distinguish between different sources of oil and gas wastewater in Sichuan Basin.

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Extensive development of shale gas has generated some concerns about environmental impacts such as the migration of natural gas into water resources. We studied high gas concentrations in waters at a site near Marcellus Shale gas wells to determine the geological explanations and geochemical implications. The local geology may explain why methane has discharged for 7 years into groundwater, a stream, and the atmosphere. Gas may migrate easily near the gas wells in this location where the Marcellus Shale dips significantly, is shallow (∼1 km), and is more fractured. Methane and ethane concentrations in local water wells increased after gas development compared with predrilling concentrations reported in the region. Noble gas and isotopic evidence are consistent with the upward migration of gas from the Marcellus Formation in a free-gas phase. This upflow results in microbially mediated oxidation near the surface. Iron concentrations also increased following the increase of natural gas concentrations in domestic water wells. After several months, both iron and SO42− concentrations dropped. These observations are attributed to iron and SO42− reduction associated with newly elevated concentrations of methane. These temporal trends, as well as data from other areas with reported leaks, document a way to distinguish newly migrated methane from preexisting sources of gas. This study thus documents both geologically risky areas and geochemical signatures of iron and SO42− that could distinguish newly leaked methane from older methane sources in aquifers.

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Potential impacts of shale gas development on shallow aquifers has raised concerns, especially regarding groundwater contamination. The intermediate zone separating shallow aquifers from shale gas reservoirs plays a critical role in aquifer vulnerability to fluid upflow, but the assessment of such vulnerability is challenging due to the general paucity of data in this intermediate zone. The ultimate goal of the project reported here was to develop a holistic multi-geoscience methodology to assess potential impacts of unconventional hydrocarbon development on fresh-water aquifers related to upward migration through natural pathways. The study area is located in the St. Lawrence Lowlands (southern Quebec, Canada), where limited oil and gas exploration and no shale gas production have taken place. A large set of data was collected over a ∼500 km2 area near a horizontal shale gas exploration well completed and fracked into the Utica Shale at a depth of ≈2 km. To investigate the intermediate zone integrity, this project integrated research results from multiple sources in order to obtain a better understanding of the system hydrodynamics, including geology, hydrogeology, deep and shallow geophysics, soil, rock and groundwater geochemistry, and geomechanics. The combined interpretation of the multi-disciplinary dataset demonstrates that there is no evidence of, and a very limited potential for, upward fluid migration from the Utica Shale reservoir to the shallow aquifer. Microbial and thermogenic methane in groundwater of this region appear to come from the shallow, organic-rich, fractured sedimentary rocks making up the regional aquifer. Nonetheless, diluted brines present in a few shallow wells close to and downstream of a normal fault revealed that some upward groundwater migration occurs, but only over a few hundred meters from the surface based on the isotopic signature of methane. This work should help support regulations related to shale gas development aiming to protect groundwater.

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Hydraulic fracturing (HF) is widely used in shale gas development, which may cause some heavy metals release from shale formations. These contaminants could transport from the fractured shale reservoirs to shallow aquifers. Thus, it is necessary to assess the impact of pollution in shallow aquifers. In this paper, a new analysis model, considering geological distributions, discrete natural fractures (NFs) and faults, is developed to analyze the migration mechanism of contaminants. Furthermore, the alkali erosion of rock caused by high-pH drilling of fluids, is considered in this paper. The numerical results suggest that both NFs and alkali erosion could reduce the time required for contaminants migrating to aquifers. When NFs and alkali erosion are both considered, the migration time will be shortened by 51 years. Alkali erosion makes the impact of NFs, on the contaminant migration, more significant. The migration time decreases with increasing pH values, while the accumulation is on the opposite side. Compared with pH 12.0, the migration time would be increased by 45 years and 29 years for pH 11.0 and 11.5, respectively. However, the migration time for pH 12.5 and 13.0 were found to be decreased by 82 years and 180 years, respectively. Alkali erosion could increase the rock permeability, and the elevated permeability would further enhance the migration velocity of the contaminants, which might play a major role in assessing the potential contamination of shallow aquifers.

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An environmental concern with hydraulic fracturing (fracking) is that injected fluids or formation fluids could migrate upwards along high-permeability faults and contaminate shallow groundwater resources. However, numerical modelling has suggested that compartmentalisation by low-permeability faults may be a greater risk factor to shallow aquifers than high-permeability faults because lateral groundwater flow is reduced and upward flow through strata may be encouraged. Therefore, it is important that compartmentalisation can be adequately identified prior to fracking. As a case study we used historical groundwater quality data and two-dimensional seismic reflection data from the Bowland Basin, northwest England, to investigate if compartmentalisation could be adequately identified in a prospective shale basin. Five groundwater properties were spatially autocorrelated and interpolation suggests a regional trend from recent (<10,000 years old) meteoric groundwater in the upland Forest of Bowland to more brackish groundwater across the Fylde plain. Principal components analysis suggests two end-member brackish groundwater types. These end-members along with seismic interpretation suggest that a fault may structurally compartmentalise the northwest Bowland Basin. Furthermore, the Woodsfold fault structurally compartmentalises the southern Fylde and the Blackpool area provides evidence for stratigraphic compartmentalisation in the Superficial Deposits. However, large areas of the Bowland Basin are not sampled and the influence of known faults on groundwater is therefore difficult to assess. Consequently, the adequate identification of compartmentalisation in prospective basins may require supplementing historic data with dedicated basin-wide groundwater monitoring programmes and the acquisition of new seismic reflection data in areas of poor coverage or quality.

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Effective, considerate shale play water management supports operations and protects the environment. A parameter often overlooked is total dissolved solids (TDS) of produced water from the formation. Knowledge of TDS is important to meet these dual goals. Subsurface TDS typically increases with depth. However, produced-water samples from the Eagle Ford Shale show a strong TDS decrease by a factor of ~10 with increasing well depth (~200,000 ppm at ~2.5 km to 18,000 ppm at ~3.6 km). Water stable isotopes strongly suggest that the low TDS is not due to dilution by meteoric water. Rather, we attribute the change to smectite-to-illite conversion, in which the smectite interlayer water is released into the pore space. Depth, temperature, and other related indicators (source for K, excess silica) support such a mechanism. In addition, water-isotope patterns and 87Sr/86Sr ratios suggest a conversion operating with limited contributions external to the shale. Order-of-magnitude calculations show that the 8% of mixed-layer clay present on average in the Lower Eagle Ford Shale is sufficient to bring formation water TDS to observed levels when some of the resident water is expelled. Understanding that the low salinity is an intrinsic property of the formation water rather than due to short-term mixing allows stakeholders to have a more optimistic outlook on water recycling and on using produced water for other uses (irrigation, municipal).

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Site-specific and regional analysis of time-series hydrologic and geochemical data collected from 15 monitoring wells in the Piceance Basin indicated that a leaking gas well contaminated shallow groundwater with thermogenic methane. The gas well was drilled in 1956 and plugged and abandoned in 1990. Chemical and isotopic data showed the thermogenic methane was not from mixing of gas-rich formation water with shallow groundwater or natural migration of a free-gas phase. Water-level and methane-isotopic data, and video logs from a deep monitoring well, indicated that a shale confining layer ~125m below the zone of contamination was an effective barrier to upward migration of water and gas. The gas well, located 27m from the contaminated monitoring well, had ~1000m of uncemented annular space behind production casing that was the likely pathway through which deep gas migrated into the shallow aquifer. Measurements of soil gas near the gas well showed no evidence of methane emissions from the soil to the atmosphere even though methane concentrations in shallow groundwater (16 to 20mg/L) were above air-saturation levels. Methane degassing from the water table was likely oxidized in the relatively thick unsaturated zone (~18m), thus rendering the leak undetectable at land surface. Drilling and plugging records for oil and gas wells in Colorado and proxies for depth to groundwater indicated thousands of oil and gas wells were drilled and plugged in the same timeframe as the implicated gas well, and the majority of those wells were in areas with relatively large depths to groundwater. This study represents one of the few detailed subsurface investigations of methane leakage from a plugged and abandoned gas well. As such, it could provide a useful template for prioritizing and assessing potentially leaking wells, particularly in cases where the leakage does not manifest itself at land surface.

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Model uncertainty analysis can quantify uncertainty both prior to calibration and postcalibration if the calibration dataset appropriately informs parameter estimates and model predictions. In certain cases calibration data (observations or measurements) may not be immediately apparent, but calibration datasets can be developed from related data for model interrogation and quantification and minimization of uncertainty. This study applies a series of techniques to investigate uncertainty in a simple numerical model of upward flow (leakage) through an abandoned oil and gas well converted into a water well in hydraulically fractured shale. Model calibration was achieved by developing a limited calibration dataset from well-specific measurements at a horizontal well in the Eagle Ford Shale play. Uncertainty in the calibrated model was interrogated using sensitivity, linear, and nonlinear analyses available in the PEST suite. Sensitivity analysis suggests that flowback after hydraulic fracturing could be crucial in reducing leakage. Linear analyses indicate horizontal-well production rates and long-term reservoir pressures are valuable measurements to collect when evaluating potential leakage. Nonlinear analyses identify the range in predictive uncertainty of potential leakage. The results underscore the need to evaluate and include additional types of well data in public records, such as flowback and produced water volumes. Overall, the results of this study illustrate the utility of uncertainty analyses with a limited calibration dataset applied to a simple model.

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In recent years, there have been a number of studies assessing water chemistry in private water supply wells in areas of unconventional oil and gas development. Many of the wells in these studies were only sampled once and a question remains as to how representative the results from a single sample are given the potential for temporal variability. To evaluate this issue, the temporal variability of water chemistry from fourteen private water wells in two study areas of southeastern New Brunswick was monitored on a monthly basis over the course of a year. The study areas had been the focus of unconventional natural gas development (the Sussex study area) or exploration (the Kent study area). Temporal data for dissolved methane, ethane and propane concentrations, the stable isotopes of carbon and hydrogen in methane, and inorganic chemistry were collected. In the Kent study area, there was little variation in water chemistry from the six wells studied, with the relative standard deviations (RSD) for methane ranging from 0 to 20%. This indicates that the water from these wells was not affected by seasonal factors such as changing temperature or hydrogeological conditions and that it is possible to acquire reproducible dissolved methane concentrations and water chemistry data from private water supply wells. The drillers’ logs for the Kent wells indicate that the casings were installed to depths that likely isolated the water-producing intervals from near-surface hydrogeochemical variations and that the majority of water drawn from the wells enters from a single, relatively high-yield, water-bearing zone. The temporal variability was higher in the eight wells located in the Sussex study area, with the RSDs for methane ranging from 18 to 141%. There were concurrent variations in inorganic parameters, suggesting that the changes in methane concentrations reflected hydrogeochemical fluctuations in the aquifers as opposed to sampling artifacts. The wells with the most variable water chemistry over time had multiple, often relatively low-yield, water-bearing zones. In those wells, methane was associated with Na-HCO3 water from relatively deep water-bearing zones, while dissolved oxygen (DO) and NO3 were associated with shallower, Ca-HCO3, groundwater. The presence of the redox-controlled species Mn, Fe, SO4 and H2S, did not appear to affect the temporal variability of methane.

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Eleven thousand groundwater samples collected in the 2010s in an area of Marcellus shale-gas development are analyzed to assess spatial and temporal patterns of water quality. Using a new data mining technique, we confirm previous observations that methane concentrations in groundwater tend to be naturally elevated in valleys and near faults, but we also show that methane is also more concentrated near an anticline. Data mining also highlights waters with elevated methane that are not otherwise explained by geologic features. These slightly elevated concentrations occur near 7 out of the 1,385 shale-gas wells and near some conventional gas wells in the study area. For ten analytes for which uncensored data are abundant in this 3,000 km2 rural region, concentrations are unchanged or improved as compared to samples analyzed prior to 1990. Specifically, TDS, Fe, Mn, sulfate, and pH show small but statistically significant improvement, and As, Pb, Ba, Cl, and Na show no change. Evidence from this rural area could document improved groundwater quality caused by decreased acid rain (pH, sulfate) since the imposition of the Clean Air Act or decreased steel production (Fe, Mn). Such improvements have not been reported in groundwater in more developed areas of the U.S.

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Concern persists over the potential for unconventional oil and gas development to contaminate groundwater with methane and other chemicals. These concerns motivated our 2-year prospective study of groundwater quality within the Marcellus Shale. We installed eight multilevel monitoring wells within bedrock aquifers of a 25-km2 area targeted for shale gas development (SGD). Twenty-four isolated intervals within these wells were sampled monthly over 2 years and groundwater pressures were recorded before, during, and after seven shale gas wells were drilled, hydraulically fractured, and placed into production. Perturbations in groundwater pressures were detected at hilltop monitoring wells during drilling of nearby gas wells and during a gas well casing breach. In both instances, pressure changes were ephemeral (<24 hours) and no lasting impact on groundwater quality was observed. Overall, methane concentrations ([CH4]) ranged from detection limit to 70 mg/L, increased with aquifer depth, and, at several sites, exhibited considerable temporal variability. Methane concentrations in valley monitoring wells located above gas well laterals increased in conjunction with SGD, but CH4 isotopic composition and hydrocarbon composition (CH4/C2H6) are inconsistent with Marcellus origins for this gas. Further, salinity increased concurrently with [CH4], which rules out contamination by gas phase migration of fugitive methane from structurally compromised gas wells. Collectively, our observations suggest that SGD was an unlikely source of methane in our valley wells, and that naturally occurring methane in valley settings, where regional flow systems interact with local flow systems, is more variable in concentration and composition both temporally and spatially than previously understood.

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Degradation of groundwater quality is a primary public concern in rural hydraulic fracturing areas. Previous studies have shown that natural gas methane (CH4) is present in groundwater near shale gas wells in the Marcellus Shale of Pennsylvania, but did not have pre-drilling baseline measurements. Here, we present the results of a free public water testing program in the Utica Shale of Ohio, where we measured CH4 concentration, CH4 stable isotopic composition, and pH and conductivity along temporal and spatial gradients of hydraulic fracturing activity. Dissolved CH4 ranged from 0.2 μg/L to 25 mg/L, and stable isotopic measurements indicated a predominantly biogenic carbonate reduction CH4 source. Radiocarbon dating of CH4 in combination with stable isotopic analysis of CH4 in three samples indicated that fossil C substrates are the source of CH4 in groundwater, with one 14C date indicative of modern biogenic carbonate reduction. We found no relationship between CH4 concentration or source in groundwater and proximity to active gas well sites. No significant changes in CH4 concentration, CH4 isotopic composition, pH, or conductivity in water wells were observed during the study period. These data indicate that high levels of biogenic CH4 can be present in groundwater wells independent of hydraulic fracturing activity and affirm the need for isotopic or other fingerprinting techniques for CH4 source identification. Continued monitoring of private drinking water wells is critical to ensure that groundwater quality is not altered as hydraulic fracturing activity continues in the region. Open image in new window Graphical abstract A shale gas well in rural Appalachian Ohio. Photo credit: Claire Botner.

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Freshwater shortages in the United States have led to increased use of treated brackish groundwater for domestic, agricultural, and municipal uses. This increased use highlights the need for protecting groundwater resources, especially during unconventional oil and gas development. We analyzed the criteria that define protected groundwater in 17 oil- and natural-gas-producing states. In general, we find that these criteria are ambiguous and do not protect brackish groundwater to criteria established for Underground Sources of Drinking Water (USDWs) in the United States Environmental Protection Agency's Underground Injection Control Program. This lack of consistent protection, and continuing unconventional oil and gas development in formations containing USDWs, highlights the need for all states to protect groundwater to the same federally defined standard for USDWs to safeguard fresh and brackish groundwater for present and future use.

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Skip to Next Section The Eastern Cape Karoo region is water stressed and will become increasingly so with further climate change. Effective and reliable groundwater management is crucial for a development such as the proposed hydraulic fracturing for shale gas. This is especially critical across this region of agriculture and protected ecosystem services. The research, as part of baseline data gathering, aims to characterize the hydrochemistry for both the shallow groundwater (<500 m) and saline groundwater closer to the c. 2–5 km deep shale gas. The classification will be used to determine possible vertical hydraulic connectivity between the shallow and deep aquifers, prior to anticipated hydraulic fracturing. This paper reports on the baseline framework that includes the sampling design and a hydrocensus with field-recorded parameters shown as interpolated maps. This includes electrical conductivity, groundwater level and borehole yield. Together with completed sampling results, these data provide a record against which the environmental impact of hydraulic fracturing and the reinjection of production water can be determined. The research is a critical first step towards the successful governance of groundwater in light of proposed shale gas development in the Karoo. In its absence, effective regulation of the sector will not be effective.

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Unconventional oil and natural gas (UOG) operations couple horizontal drilling with hydraulic fracturing to access previously inaccessible fossil fuel deposits. Hydraulic fracturing, a common form of...

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Bacterial communities in groundwater are very important as they maintain a balanced biogeochemical environment. When subjected to stressful environments, for example, due to anthropogenic contamination, bacterial communities and their dynamics change. Studying the responses of the groundwater microbiome in the face of environmental changes can add to our growing knowledge of microbial ecology, which can be utilized for the development of novel bioremediation strategies. High-throughput and simpler techniques that allow the real-time study of different microbiomes and their dynamics are necessary, especially when examining larger data sets. Matrix-assisted laser desorption-ionization (MALDI) time-of-flight mass spectrometry (TOF-MS) is a workhorse for the high-throughput identification of bacteria. In this work, groundwater samples were collected from a rural area in southern Texas, where agricultural activities and unconventional oil and gas development are the most prevalent anthropogenic activities. Bacterial communities were assessed using MALDI-TOF MS, with bacterial diversity and abundance being analyzed with the contexts of numerous organic and inorganic groundwater constituents. Mainly denitrifying and heterotrophic bacteria from the Phylum Proteobacteria were isolated. These microorganisms are able to either transform nitrate into gaseous forms of nitrogen or degrade organic compounds such as hydrocarbons. Overall, the bacterial communities varied significantly with respect to the compositional differences that were observed from the collected groundwater samples. Collectively, these data provide a baseline measurement of bacterial diversity in groundwater located near anthropogenic surface and subsurface activities.

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Methane leakage due to compromised hydrocarbon well integrity can lead to impaired groundwater quality. Here, we use a three‐dimensional, multiphase (vapor and aqueous), multicomponent (methane, water,...Methane leakage from oil and gas wellbores below freshwater aquifers impacts groundwater quality. The scope of the problem is such that millions of kilograms of methane could reach groundwater in the case...

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Concern that hydraulic fracturing and natural gas production contaminates groundwater requires techniques to attribute and estimate methane flux. Although dissolved alkane and noble gas chemistry may distinguish thermogenic and microbial methane, low solubility and concentration of methane in atmosphere-equilibrated groundwater precludes the use of methane to differentiate locations affected by high and low flux of stray methane. We present a method to estimate stray gas infiltration into groundwater using dissolved nitrogen. Due to the high concentration of nitrogen in atmospheric-recharged groundwater and low concentration in natural gas, dissolved nitrogen in groundwater is much less sensitive to change than dissolved methane and may differentiate groundwater affected high and low flux of stray natural gas. We report alkane and nitrogen chemistry from shallow groundwater wells and eight natural gas production wells in the Barnett Shale footprint to attribute methane and estimate mixing ratios of thermogenic natural gas to groundwater. Most groundwater wells have trace to nondetect concentrations of methane. A cluster of groundwater wells have greater than 10 mg/L dissolved methane concentrations with alkane chemistries similar to natural gas from the Barnett Shale and/or shallower Strawn Group suggesting that localized migration of natural gas occurred. Two-component mixing models constructed with dissolved nitrogen concentrations and isotope values identify three wells that were likely affected by a large influx of natural gas with gas:water mixing ratios approaching 1:5. Most groundwater wells, even those with greater than 10-mg/L methane, have dissolved nitrogen chemistry typical of atmosphere-equilibrated groundwater suggesting natural gas:water mixing ratios smaller than 1:20.

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To assess radium (226Ra) as a potential indicator of impact in well waters, we investigated its behavior under natural conditions using a case study approach. 226Ra geochemistry was investigated in 67 private wells of southeastern New Brunswick, Canada, a region targeted for potential shale gas exploitation. Objectives were to i) establish 226Ra baseline in groundwater; ii) characterize 226Ra spatial distribution and temporal variability; iii) characterize 226Ra partitioning between dissolved phase and particulate forms in well waters; and iv) understand the mechanisms controlling 226Ra mobility under natural environmental settings. 226Ra levels were generally low (median = 0.061 pg L−1, or 2.2 mBq L−1), stable over time, and randomly distributed. A principal component analysis revealed that concentrations of 226Ra were controlled by key water geochemistry factors: the highest levels were observed in waters with high hardness, and/or high concentrations of individual alkaline earth elements (i.e. Mg, Ca, Sr, Ba), high concentrations of Mn and Fe, and low pH. As for partitioning, 226Ra was essentially observed in the dissolved phase (106 ± 19%) suggesting that the geochemical conditions of groundwater in the studied regions are prone to limit 226Ra sorption, enhancing its mobility. Overall, this study provided comprehensive knowledge on 226Ra background distribution at local and regional scales. Moreover, it provided a framework to establish 226Ra baselines and determine which geochemical conditions to monitor in well waters in order to use this radionuclide as an indicator of environmental impact caused by anthropogenic activities (e.g. unconventional shale gas exploitation, uranium mining, or nuclear generating power plants).

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Gas production from unconventional reservoirs has led to widespread environmental concerns. Despite several excellent reviews of various potential impacts to water resources from unconventional gas production, no study has systematically and quantitatively assessed the potential for these impacts to occur. We use empirical evidence and numerical and analytical models to quantify the likelihood of surface water and groundwater contamination, and shallow aquifer depletion from unconventional gas developments. These likelihoods are not intended to be exact. They provide a starting point for comparing the probabilities of adverse impacts between types of water resources and pathways. This analysis provides much needed insight into what are ‘probable’ rather than simply ‘possible’ impacts. The results suggest that the most likely water resource impacts are surface water and groundwater contamination from spills at the well pad, which can be as high as 1 in 10 and 1 in 100 for each gas well, respectively. For wells that are hydraulically fractured, the likelihood of contamination due to inter-aquifer leakage is 1 in 106 or lower (dependent on the separation distance between the production formation and the aquifer). For gas-bearing formations that were initially over-pressurized, the potential for contamination from inter-aquifer leakage after production ceases could be as high as 1 in 400 where the separation between gas formation and shallow aquifer is 500 m, but will be much lower for greater separation distances (more characteristic of shale gas). This article is protected by copyright. All rights reserved.

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Currently, only a few states in the U.S. (e.g. Colorado and Ohio) require mandatory baseline groundwater sampling from nearby groundwater wells prior to drilling a new oil or gas well. Colorado is the first state to regulate groundwater testing before and after drilling, requiring one pre-drilling sample and two additional post-drilling samples within 6 - 12 months and 5 - 6 years of drilling, respectively. However, the monitoring method is limited to ex-situ sampling, which offers only a snapshot in time. To overcome the limitations and increase monitoring effectiveness, a new groundwater monitoring system, Colorado Water Watch (CWW), was introduced as a decision-making tool to support the state’s regulatory agency and also to provide real-time groundwater quality data to both industry and the public. The CWW uses simple in-situ water quality sensors based on surrogate sensing technology that employs an event detection system to screen the incoming data in near real-time. This objective of this study was to improve the understanding of groundwater quality in Wattenberg field and assess event detection methods. The data obtained from 5 sites (the earliest monitoring sites in the CWW network) for 3 years of the regional monitoring network in Wattenberg field is used to illustrate the background information about groundwater quality and its changing trend, and make comparisons between two outlier detection methods, CANARY and simple moving median.

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Hydraulic fracturing operations are generating considerable discussion about their potential to contaminate aquifers tapped by domestic groundwater wells. Groundwater wells located closer to hydraulically fractured wells are more likely to be exposed to contaminants derived from on-site spills and well-bore failures, should they occur. Nevertheless, the proximity of hydraulic fracturing operations to domestic groundwater wells is unknown. Here, we analyze the distance between domestic groundwater wells (public and self-supply) constructed between 2000 and 2014 and hydraulically fractured wells stimulated in 2014 in 14 states. We show that 37% of all recorded hydraulically fractured wells stimulated during 2014 exist within 2 km of at least one recently constructed (2000–2014) domestic groundwater well. Furthermore, we identify 11 counties where most (>>>50%) recorded domestic groundwater wells exist within 2 km of one or more hydraulically fractured wells stimulated during 2014. Our findings suggest that understanding how frequently hydraulic fracturing operations impact groundwater quality is of widespread importance to drinking water safety in many areas where hydraulic fracturing is common. We also identify 236 counties where most recorded domestic groundwater wells exist within 2 km of one or more recorded oil and gas wells producing during 2014. Our analysis identifies hotspots where both conventional and unconventional oil and gas wells frequently exist near recorded domestic groundwater wells that may be targeted for further water-quality monitoring.

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The Shale Network is a group of stakeholders collating, publishing, and conducting research on water quality data collected in the northeastern United States experiencing natural gas extraction from shale using hydraulic fracturing. In developing the Shale Network, we have experienced reluctance to share data from all participating sectors. This paper explores this reluctance, identifying barriers to greater collaboration among multiple stakeholders in natural resource management projects. Findings are derived from participant observation of the Shale Network team, surveys conducted during Shale Network workshops, interviews with water quality stakeholders, and participant observation of water quality monitoring training sessions. The barriers identified include perceptions about data problems and quality, technical capacity, regulatory and legal limitations, competition for resources, and resource allocation decisions. This paper identifies strategies the Shale Network has used to overcome data-sharing barriers to expand a culture of data sharing that supports enhanced nature resource management and citizen engagement.

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Interest in dissolved methane (CH4) concentrations in aquifers in England, Scotland and Wales ('Great Britain' or GB) has grown concurrently with interest in the exploitation of unconventional gas sources (UGS). Experience, mainly from North America, has shown the importance of a pre-production baseline against which changes possibly due to UGS extraction can be compared. The British Geological Survey, aided by water utilities, private users and regulators, has compiled a unique dataset for CH4 in groundwaters of GB. This focuses principally on areas where UGS exploration is considered more likely, as indicated by the underlying geology. All the main water supply aquifers (Principal aquifers) were targeted, plus Secondary aquifers where locally important. The average dissolved CH4 concentration across GB in the aquifers sampled was 45 mu g/l. Out of a total of 343 sites, 96% showed dissolved CH4 concentrations <100 mu g/l, 80% <10 mu g/l, and 43% < 1 mu g/l. No site had a CH4 concentration above the US Department of the Interior suggested risk action level of 10,000 mu g/l. While most sites were sampled only once, a subset was monitored quarterly to determine the magnitude of seasonal or other variations. Generally these variations were minor, with 84% of sites showing variations within the range 0.5-37 mu g/l, but some aquifers where the porosity was primarily fracture-related showed larger changes (0.5-264 mu g/l). This may have been due to the nature of sampling at these sites which, unlike the others, did not have installed pumps. Since the regulatory compliance monitoring attending UGS operations will include the measurement of parameters such as dissolved CH4, it is essential that sampling methods are tested to ensure that reliable and comparable datasets can be obtained. (C) 2017 BGS ? NERC, British Geological Survey, a component Institute of NERC. Published by Elsevier B.V.

Abstract:
Shale gas development has been heralded as a game changer that has had, and will continue to have, repercussions for energy scenarios around the world, and natural gas has been hailed as the transition fuel to a low carbon future. Shale gas production—made feasible and economical by advances in hydraulic fracturing—offers a solution in the face of increased demand, instability in key producing regions, and societal aversion to the risks of nuclear energy. This “golden future,” however, has come into conflict with increasing concerns over water. This paper examines policy and regulatory frameworks around hydraulic fracturing in Texas and Spain in order to consider the trade-offs—particularly at the expense of water security—that may occur as decision-makers pursue improvements in energy security. We compare regulatory, institutional, and cultural contexts in order to understand and evaluate the robustness of these frameworks to prevent the reduction in water security as a consequence of the pursuit of energy security. Paucity of data is discussed. We also consider questions such as disclosure of information to the public about water use or the chemical composition of frac fluids and public opinion about hydraulic fracturing. Lessons are drawn that may assist policymakers who seek to guarantee water security while pursuing energy security.

Abstract:
Natural gas development using hydraulic fracturing has many potential environmental impacts, but among the most certain is the land disturbance required to build the well pads and other infrastructure required to drill and extract the gas. We used the Soil and Water Assessment Tool (SWAT) model to investigate how natural gas development could impact streamflow and sediment, total nitrogen (TN), and total phosphorous (TP) loadings in the upper Delaware River Basin (DRB), a relatively undeveloped watershed of 7,950km(2) that lies above the Marcellus Shale formation. If gas development was permitted, our projections show the DRB could experience development of over 600 well pads to extract natural gas at build out, which, with supporting infrastructure (roads, gathering pipelines), could convert over 5,000ha from existing land uses in the study area. In subbasins with development activity we found sediment, TN, and TP yields could increase by an average of 15, 0.08, and 0.03kg/ha/yr, respectively (an increase of 2, 3, and 15%, respectively) for each one percent of subbasin land area converted into natural gas infrastructure. At the study area outlet on the Delaware River at Port Jervis, New York, we found increases in the annual average streamflow and sediment, nitrogen, and phosphorus loads of up to 0.01, 0.2, 0.2, and 1%, respectively, for a rapid development year, and 0.08, 1.3, 2.0, and 11%, respectively, for the full development scenario. Editor's note: This paper is part of the featured series on SWAT Applications for Emerging Hydrologic and Water Quality Challenges. See the February 2017 issue for the introduction and background to the series.

Abstract:
The widespread use of unconventional drilling involving hydraulic fracturing (“fracking”) has allowed for increased oil-and-gas extraction, produced water generation, and subsequent spills of produced water in Colorado and elsewhere. Produced water contains BTEX (benzene, toluene, ethylbenzene, xylene) and naphthalene, all of which are known to induce varying levels of toxicity upon exposure. When spilled, these contaminants can migrate through the soil and contaminant groundwater. This research modeled the solute transport of BTEX and naphthalene for a range of spill sizes on contrasting soils overlying groundwater at different depths. The results showed that benzene and toluene were expected to reach human health relevant concentration in groundwater because of their high concentrations in produced water, relatively low solid/liquid partition coefficient and low EPA drinking water limits for these contaminants. Peak groundwater concentrations were higher and were reached more rapidly in coarser textured soil. Risk categories of “low,” “medium,” and “high” were established by dividing the EPA drinking water limit for each contaminant into sequential thirds and modeled scenarios were classified into such categories. A quick reference guide was created that allows the user to input specific variables about an area of interest to evaluate that site’s risk of groundwater contamination in the event of a produced water spill. A large fraction of produced water spills occur at hydraulic-fracturing well pads; thus, the results of this research suggest that the surface area selected for a hydraulic-fracturing site should exclude or require extra precaution when considering areas with shallow aquifers and coarsely textured soils.

Abstract:
Approximately 81% of the nation's energy demands are supported by hydrocarbons, largely in part to the relatively recent exploration of oil and gas from unconventional shale energy reserves. The extraction of shale energy requires technological ingenuity, such as hydraulic fracturing and horizontal drilling, and significant freshwater resources to successfully recover the previously sequestered hydrocarbons from low porosity formations. As unconventional oil and gas development continues to expand to meet the growing energy demands, it becomes increasingly more important to understand the potential environmental implications and to practice proper environmental stewardship. For example, concerns over water usage and the related consequences have dramatically increased due to the demand for water used in hydraulic fracturing, the increased volumes of wastewater being produced, and the need to dispose of or reuse the wastewater without compromising the surface and subsurface environments. As such, this chapter will cover the life cycle of water in oil and gas development (conventional and unconventional), including water use and waste production in the drilling, stimulation, and production phases; the current waste management strategies and challenges within the various treatment modalities; and the widespread implications of the varying forms of waste management.

Abstract:
Groundwater is a major source for drinking water in the United States, and therefore, its quality and quantity is of extreme importance. One major concern that has emerged is the possible contamination of groundwater due to the unconventional oil and gas extraction activities. As such, the impacts of exogenous contaminants on microbial ecology is an area to be explored to understand what are the chemical and physical conditions that allow the proliferation of pathogenic bacteria and to find alternatives for water treatment by identifying organic-degrading bacteria. In this work, we assess the interplay between groundwater quality and the microbiome in contaminated groundwaters rich in hydrocarbon gases, volatile organic and inorganic compounds, and various metals. Opportunistic pathogenic bacteria, such as Aeromonas hydrophila, Bacillus cereus, Pseudomonas aeruginosa, and Stenotrophomonas maltophilia, were identified, increasing the risk for consumption of and exposure to these contaminated groundwaters. Additionally, antimicrobial tests revealed that many of the identified bacteria were resistant to different antibiotics. The MALDI-TOF MS results were successfully confirmed with 16S rRNA gene sequencing, proving the accuracy of this high-throughput method. Collectively, these data provide a seminal understanding of the microbial populations in contaminated groundwater overlying anthropogenic activities like unconventional oil and gas development.

Abstract:
Linking areas of high unconventional oil and gas development (UD) activity to groundwater quality is statistically challenging. As contaminant pathways reflect spatial processes, their elucidation requires spatially explicit analyses. Here, we consider complications in the statistical evaluation of suites of chemical constituents, review basics of spatial analysis, and illustrate geographically weighted regression (GWR) and Hot Spot Analysis (spatial clustering) using eight indicator variables from groundwater samples collected from the Trinity and Woodbine aquifers overlying the Barnett Shale in northern Texas, a region of high UD activity. GWR indicated that moderate variation in some variables (e.g., total dissolved solids) but zero variance in others (e.g., methanol) is explained by kernel density of UD wells. Hot Spot Analysis complemented GWR analyses and indicated several subregions of elevated concentrations for most variables. With the exception of a single area of extreme contamination straddling the Parker–Hood County line, hot spots showed little to moderate spatial congruence across variables. Collectively, our results suggest that while some groundwater contamination has resulted from UD activity, overall groundwater contamination is multifactorial, and contamination related to UD activity is likely stochastic rather than systematic.

Abstract:
Exploitation of shale gas by hydraulic fracturing (fracking) is highly controversial and concerns have been raised regarding induced risks from this technique. As part of the EU-funded SHEER Project, a shallow aquifer used for drinking water, overlying a zone of active shale-gas fracking, has been monitored for more than a year. Early results reveal the functioning of the shallow aquifer and hydrochemistry, focusing on the identification of potential impacts from the shale gas operation. This stage is an essential precursor to modeling impact scenarios of contamination and to predict changes in the aquifer.

Abstract:
Some of the most important issues surrounding unconventional oil and gas (UOG) extraction are the possible impacts of this activity on potable groundwater resources and how to minimise and mitigate such impacts. A groundwater vulnerability map for UOG extraction has been developed as part of an interactive vulnerability map for South Africa in an effort to address such concerns and minimize possible future impacts linked to UOG extraction. This article describes the development of the groundwater theme of the interactive vulnerability map and highlights important aspects that were considered during the development of this map, which would also be of concern to other countries that may plan to embark on UOG extraction. The policy implications of the groundwater vulnerability map for managing UOG extraction impacts is also highlighted in this article.

Abstract:
The expanding use of horizontal drilling and hydraulic fracturing technology to produce oil and gas from tight rock formations has increased public concern about potential impacts on the environment, especially on shallow drinking water aquifers. In eastern Kentucky, horizontal drilling and hydraulic fracturing have been used to develop the Berea Sandstone and the Rogersville Shale. To assess baseline groundwater chemistry and evaluate methane detected in groundwater overlying the Berea and Rogersville plays, we sampled 51 water wells and analyzed the samples for concentrations of major cations and anions, metals, dissolved methane, and other light hydrocarbon gases. In addition, the stable carbon and hydrogen isotopic composition of methane (δ13C-CH4 and δ2H-CH4) was analyzed for samples with methane concentration exceeding 1 mg/L. Our study indicates that methane is a relatively common constituent in shallow groundwater in eastern Kentucky, where methane was detected in 78% of the sampled wells (40 of 51 wells) with 51% of wells (26 of 51 wells) exhibiting methane concentrations above 1 mg/L. The δ13C-CH4 and δ2H-CH4 ranged from −84.0‰ to −58.3‰ and from −246.5‰ to −146.0‰, respectively. Isotopic analysis indicated that dissolved methane was primarily microbial in origin formed through CO2 reduction pathway. Results from this study provide a first assessment of methane in the shallow aquifers in the Berea and Rogersville play areas and can be used as a reference to evaluate potential impacts of future horizontal drilling and hydraulic fracturing activities on groundwater quality in the region.

Abstract:
Natural gas extraction from unconventional shale gas reservoirs is the subject of considerable public debate, with a key concern being the impact of leaking fugitive natural gases on shallow potable groundwater resources. Baseline data regarding the distribution, fate, and transport of these gases and their isotopes through natural formations prior to development are lacking. Here, we define the migration and fate of CH4 and delta(13\)wC-CH4 from an early-generation bacterial gas play in the Cretaceous of the Williston Basin, Canada to the water table. Our results show the CH4 is generated at depth and diffuses as a conservative species through the overlying shale. We also show that the diffusive fractionation of delta C-13-CH4 (following glaciation) can complicate fugitive gas interpretations. The sensitivity of the delta C-13-CH4 profile to glacial timing suggests it may be a valuable tracer for characterizing the timing of geologic changes that control transport of CH4 (and other solutes) and distinguishing between CH4 that rapidly migrates upward through a well annulus or other conduit and CH4 that diffuses upwards naturally. Results of this study were used to provide recommendations for designing baseline investigations.

Abstract:
Most of the shale gas production in northwest China is from continental shale. Identifying hydrogeochemical and isotopic indicators of toxic hydraulic fracturing flowback fluids (HFFF) has great significance in assessing the safety of drinking water from shallow groundwater and stream water. Hydrogeochemical and isotopic data for HFFF from the Dameigou shale formations (Cl/Br ratio (1.81X10(-4)-6.52X10(-4)), Ba/Sr (>0.2), delta B-11 (-10-1) and epsilon(SW)(Sr) (56-65, where epsilon(SW)(Sr) is the deviation of the Sr-87/Sr-86 ratio from that of seawater in parts per 10(4))) were distinct from data for the background saline shallow groundwater and stream water before fracturing. Mixing models indicated that inorganic elemental signatures (Br/Cl, Ba/Sr) and isotopic fingerprints (delta B-11, epsilon(SW)(Sr)) can be used to distinguish between HFFF and conventional oil-field brine in shallow groundwater and stream water. These diagnostic indicators were applied to identify potential releases of HFFF into shallow groundwater and stream water prior to fracturing and flowback. The monitored time series data for shallow groundwater and stream water exhibit no clear trends along mixing curves towards the HFFF end member, indicating that there is no detectable release occurring at present.

Abstract:
Leakage of natural gas (mainly methane) along oil and gas wells contributes to fugitive greenhouse gas emissions. Natural gas leakage occurring outside the well casing and cement sheath and reaching the surface, hence the atmosphere, is known as Gas Migration (GM). In this paper an analysis of the occurrence of gas (methane) migration along wellbores in Alberta, Canada, is presented based on data obtained from the Alberta Energy Regulator. Gas migration (GM) has been reported in 3276 wells, i.e., in 0.73% of all the wells in the province. Most of these wells (2745) are located in the eastern, shallower part of the province, particularly in the Lloydminster – Cold Lake area. The wells are mostly shallow, with 2800 wells being shallower than 1000 m depth. About half of the wells are cemented to the top, showing that lack of cementing to the top or at least above the surface casing shoe is not a major factor in the occurrence of GM. Similarly, well orientation is not a strong indicator of GM potential or occurrence A slight majority (54.1%) of the wells with GM are conventional wells, with the balance (45.9%) being thermal wells, of which the great majority is in the Cold Lake oil sands area where cyclic steam injection is used for bitumen production. The analysis indicates that the production type, conventional for oil and gas, or thermal for heavy oil and bitumen, is a strong indicator of the potential for, or occurrence for GM. The depth of the gas source is provided in the database for 559 wells. When related to the well depth, the relative depth of the gas source has an average of 0.42, indicating that the origin of the gas source is, by and large, above the producing reservoirs. Isotopic studies of reservoir and migrating gas in Alberta, reviewed in this paper, indicate that in the great majority of cases the migrating gas is immature thermogenic gas originating in overlying shales, as well as coal gas originating from the various overlying coal beds. In a number of cases the migrating gas is of shallow, biogenic origin, likely sourced from shallow groundwater aquifers. Biogenic methanogenesis is enhanced by the high temperatures associated with thermal wells, which may explain the large number of GM cases associated with thermal wells.

Abstract:
Water wells (n = 116) overlying the Eagle Ford, Fayetteville, and Haynesville Shale hydrocarbon production areas were sampled for chemical, isotopic, and groundwater-age tracers to investigate the occurrence and sources of selected hydrocarbons in groundwater. Methane isotopes and hydrocarbon gas compositions indicate most of the methane in the wells was biogenic and produced by the CO2 reduction pathway, not from thermogenic shale gas. Two samples contained methane from the fermentation pathway that could be associated with hydrocarbon degradation based on their co-occurrence with hydrocarbons such as ethylbenzene and butane. Benzene was detected at low concentrations (<0.15 μg/L), but relatively high frequencies (2.4–13.3% of samples), in the study areas. Eight of nine samples containing benzene had groundwater ages >2500 years, indicating the benzene was from subsurface sources such as natural hydrocarbon migration or leaking hydrocarbon wells. One sample contained benzene that could be from a surface release associated with hydrocarbon production activities based on its age (10 ± 2.4 years) and proximity to hydrocarbon wells. Groundwater travel times inferred from the age-data indicate decades or longer may be needed to fully assess the effects of potential subsurface and surface releases of hydrocarbons on the wells.

Abstract:
The Fayetteville Shale within north central Arkansas is an area of extensive unconventional natural gas (UNG) production. Recently, the Scott Henderson Gulf Mountain Wildlife Management Area (GMWMA) was leased from the state of Arkansas for NG exploration, raising concerns about potential impacts on water resources. From November 2010 through November 2014, we monitored four reaches of the South Fork Little Red River (SFLRR), within the GMWMA, establishing baseline physico-chemical characteristics prior to UNG development and assessing trends in parameters during and after UNG development. Water samples were collected monthly during baseflow conditions and analyzed for conductivity, turbidity, ions, total organic carbon (TOC), and metals. All parameters were flow-adjusted and evaluated for monotonic changes over time. The concentrations of all constituents measured in the SFLRR were generally low (e.g., nitrate ranged from <0.005 to 0.268 mg/l across all sites and sample periods), suggesting the SFLRR is of high water quality. Flow-adjusted conductivity measurements and sodium concentrations increased at site 1, while magnesium decreased across all four sites, TOC decreased at sites 1 and 3, and iron decreased at site 1 over the duration of the study. With the exception of conductivity and sodium, the physico-chemical parameters either decreased or did not change over the 4-year duration, indicating that UNG activities within the GMWMA have had minimal or no detectable impact on water quality within the SFLRR. Our study provides essential baseline information that can be used to evaluate water quality within the SFLRR in the future should UNG activity within the GMWMA expand.

Abstract:
Expansion of shale gas extraction has fuelled global concern about the potential impact of fugitive methane on groundwater and climate. Although methane leakage from wells is well documented, the consequences on groundwater remain sparsely studied and are thought by some to be minor. Here we present the results of a 72-day methane gas injection experiment into a shallow, flat-lying sand aquifer. In our experiment, although a significant fraction of methane vented to the atmosphere, an equal portion remained in the groundwater. We find that methane migration in the aquifer was governed by subtle grain-scale bedding that impeded buoyant free-phase gas flow and led to episodic releases of free-phase gas. The result was lateral migration of gas beyond that expected by groundwater advection alone. Methane persisted in the groundwater zone despite active growth of methanotrophic bacteria, although much of the methane that vented into the vadose zone was oxidized. Our findings demonstrate that even small-volume releases of methane gas can cause extensive and persistent free phase and solute plumes emanating from leaks that are detectable only by contaminant hydrogeology monitoring at high resolution.

Abstract:
The risk of environmental contamination by oil and gas wells depends strongly on the frequency with which they lose integrity. Wells with compromised integrity typically exhibit pressure in their outermost annulus (surface casing pressure, SfCP) due to gas accumulation. SfCP is an easily measured but poorly documented gauge of well integrity. Here, we analyze SfCP data from the Colorado Oil and Gas Conservation Commission database to evaluate the frequency of well integrity loss in the Wattenberg Test Zone (WTZ), within the Wattenberg Field, Colorado. Deviated and horizontal wells were found to exhibit SfCP more frequently than vertical wells. We propose a physically meaningful well-specific critical SfCP criterion, which indicates the potential for a well to induce stray gas migration. We show that 270 of 3923 wells tested for SfCP in the WTZ exceeded critical SfCP. Critical SfCP is strongly controlled by the depth of the surface casing. Newer horizontal wells, drilled during the unconventional drilling boom, exhibited critical SfCP less frequently than other wells because they were predominantly constructed with deeper surface casings. Thus, they pose a lower risk for inducing stray gas migration than legacy vertical or deviated wells with surface casings shorter than modern standards.

Abstract:
Clusters of elevated methane concentrations in aquifers overlying the Barnett Shale play have been the focus of recent national attention as they relate to impacts of hydraulic fracturing. The objective of this study was to assess the spatial extent of high dissolved methane previously observed on the western edge of the play (Parker County) and to evaluate its most likely source. A total of 509 well water samples from 12 counties (14,500 km(2) ) were analyzed for methane, major ions, and carbon isotopes. Most samples were collected from the regional Trinity Aquifer and show only low levels of dissolved methane (85% of 457 unique locations <0.1 mg/L). Methane, when present is primarily thermogenic (δ(13) C 10th and 90th percentiles of -57.54 and -39.00‰ and C1/C2+C3 ratio 10th, 50th, and 90th percentiles of 5, 15, and 42). High methane concentrations (>20 mg/L) are limited to a few spatial clusters. The Parker County cluster area includes historical vertical oil and gas wells producing from relatively shallow formations and recent horizontal wells producing from the Barnett Shale (depth of ∼1500 m). Lack of correlation with distance to Barnett Shale horizontal wells, with distance to conventional wells, and with well density suggests a natural origin of the dissolved methane. Known commercial very shallow gas accumulations (<200 m in places) and historical instances of water wells reaching gas pockets point to the underlying Strawn Group of Paleozoic age as the main natural source of the dissolved gas.

Abstract:
A holistic risk assessment of surface water (SW) contamination due to lead-210 (Pb-210) in oil produced water (PW) from the Bakken Shale in North Dakota (ND) was conducted. Pb-210 is a relatively long-lived radionuclide and very mobile in water. Because of limited data on Pb-210, a simulation model was developed to determine its concentration based on its parent radium-226 and historical total dissolved solids levels in PW. Scenarios where PW spills could reach SW were analyzed by applying the four steps of the risk assessment process. These scenarios are: (1) storage tank overflow, (2) leakage in equipment, and (3) spills related to trucks used to transport PW. Furthermore, a survey was conducted in ND to quantify the risk perception of PW from different stakeholders. Findings from the study include a low probability of a PW spill reaching SW and simulated concentration of Pb-210 in drinking water higher than the recommended value established by the World Health Organization. Also, after including the results from the risk perception survey, the assessment indicates that the risk of contamination of the three scenarios evaluated is between medium-high to high.