Repository for Oil and Gas Energy Research (ROGER)

Abstract:
Regulatory agencies routinely assess the presence of stray gas release from unconventional gas wells by sampling for methane in nearby groundwater after the well is drilled or if citizens complain about methane in their water. We studied whether methane concentrations in groundwater naturally vary through time in a shale gas basin where unconventional development and hydraulic fracturing has not yet occurred, to test the assumption that pre-drilling observations of well water quality can be reliable measures for assessing impacts of later gas drilling. We collected groundwater samples from 11 domestic wells in New York monthly for 13 months for methane and ion concentrations in a highly gas productive part of the Appalachian basin where fracking has been banned. Changing methane concentrations correlated with changes in chloride and bromide, indicating changing mixtures of shallow freshwater and deeper formation brine extracted by the wells through time. The hydrogeologic setting of a water well can cause variability in methane concentrations that may mimic stray gas but cannot be attributable to gas drilling. For this reason, before and after testing has limited utility to distinguish impacts of gas drilling from other causes of changing methane concentrations unless that testing includes sampling a comprehensive set of ions multiple times prior to drilling.

Abstract:
Conflicting evidence exists as to whether or not unconventional oil and gas (UOG) development has enhanced methane transport into groundwater aquifers over the past 15 years. In this study, recent groundwater samples were collected from 90 domestic wells and 4 springs in Northeastern Pennsylvania located above the Marcellus Shale after more than a decade of UOG development. No statistically significant correlations were observed between the groundwater methane level and various UOG geospatial metrics, including proximity to UOG wells and well violations, as well as the number of UOG wells and violations within particular radii. The δ13C and methane-to-higher chain hydrocarbon signatures suggested that the elevated methane levels were not attributable to UOG development nor could they be explained by using simple biogenic–thermogenic end-member mixing models. Instead, groundwater methane levels were significantly correlated with geochemical water type and topographical location. Comparing a subset of contemporary methane measurements to their co-located pre-drilling records (n = 64 at 49 distinct locations) did not indicate systematic increases in methane concentration but did reveal several cases of elevated concentration (n = 12) across a spectrum of topographies. Multiple lines of evidence suggested that the high-concentration groundwater methane could have originated from shallow thermogenic methane that migrated upward into groundwater aquifers with Appalachian Basin brine.

Abstract:
The expansion of petroleum resource development has led to growing concern regarding greenhouse gas emissions from fugitive gas migration, which occurs at some wells due to well integrity failure. In this study, we quantify methane surface expression and emissions resulting from gas migration using a number of complementary techniques, and thereby evaluate surface expression processes as well as the strengths and limitations of the monitoring techniques. Methane emissions were found to be highly localized and variable over time. Injected gas reached the surface via preferential pathways through the soils and also along an installed groundwater monitoring well. Cumulative emissions were estimated from flux chamber measurements to be 3.8–6.5% of the injected gas; whereas eddy covariance (EC) data inferred approximately 26% of the injected gas was released to the atmosphere. Together these methods provide enhanced interpretation of surface expression at the site, advance our understanding on fugitive gas migration from integrity compromised energy wells and provide insights to improve monitoring and detection strategies with a view to reducing future greenhouse gas emissions. Moreover that, up to 75% of fugitive gas released at the site remained in the subsurface, shows that capillary barriers will mitigate greenhouse gas emissions from leaky wells; however, may infer greater potential for impacts on groundwater resources, if present.

Abstract:
Following the large increase in unconventional hydrocarbon production in North America and elsewhere in the last 15 years, many jurisdictions have implemented groundwater monitoring programs to verify whether these subsurface industrial activities impact shallow groundwater quality. The interpretation of groundwater monitoring results typically relies mostly on dissolved alkane chemical and isotopic composition to infer the potential presence of thermogenic hydrocarbons presumed to originate from a deep source, which may indicate contamination. However, ambiguous results are frequently obtained, and post-genetic processes are often suspected to have modified the original gas composition. Here, we present a systematic approach to identify alkane origin with greater certainty, by thoroughly investigating four processes that may affect dissolved hydrocarbon gas: 1) late-stage methanogenesis, 2) oxidation (of methane or higher alkanes), 3) mixing between different gas sources, and 4) secondary methanogenesis. This is achieved by using empirical equations and fractionation factors available in the literature, combined to site-specific isotopic tracers (δ13CCH4, δ2HCH4, δ2HH2O, δ13CDIC) in groundwater samples. This approach is being tested and applied to a study area located in southern New Brunswick, Canada. The area overlies the McCully gas field from which unconventional natural gas is produced since 2003, and the nearby Elgin area, a prospective area for condensates. Results demonstrate that the presence of methane in groundwater is not related to the proximity of gas wells. In a few shallow wells located very close to producing gas wells in the McCully gas field, methane and ethane were detected, and the compositional and isotopic data sometimes seemed to point towards a thermogenic origin. However, consideration of the four processes led to the conclusion that the gas was of microbial origin, and that it had been oxidized to various levels. In contrast, thermogenic gas was detected in groundwater in the Elgin area, where no commercial production has yet taken place. In this area the natural hydrocarbon gas context is more complex, and the gas from some of the wells was affected by mixing, oxidation, and late-stage methanogenesis. Finally, the approach used in this paper has proven capable of disentangling the original isotopic signature from post-genetic modifications and, despite initial ambiguity, has shown no evidence that past hydraulic fracturing in the McCully gas field has affected shallow groundwater quality.

Abstract:
Extensive development of horizontal drilling and hydraulic fracturing enhanced energy production but raised concerns about drinking-water quality in areas of shale-gas development. One particularly controversial case that has received significant public and scientific attention involves possible contamination of groundwater in the Trinity Aquifer in Parker County, Texas. Despite extensive work, the origin of natural gas in the Trinity Aquifer within this study area is an ongoing debate. Here, we present a comprehensive geochemical dataset collected across three sampling campaigns along with integration of previously published data. Data include major and trace ions, molecular gas compositions, compound-specific stable isotopes of hydrocarbons (δ13C-CH4, δ13C-C2H6, δ2H-CH4), dissolved inorganic carbon (δ13C-DIC), nitrogen (δ15N-N2), water (δ18O, δ2H, 3H), noble gases (He, Ne, Ar), boron (δ11B) and strontium (87Sr/86Sr) isotopic compositions of water samples from 20 drinking-water wells completed in the Trinity Aquifer. The compendium of data confirms mixing between a deep, naturally occurring salt- (Cl >250 mg/L) and hydrocarbon-rich groundwater with a low-salinity, shallower, and younger groundwater. Hydrocarbon gases display strong evidence for sulfate reduction-paired oxidation, in some cases followed by secondary methanogenesis. A subset of drinking-water wells contains elevated levels of hydrocarbons and depleted atmospherically-derived gas tracers, which is consistent with the introduction of fugitive thermogenic gas. We suggest that gas originating from the intermediate-depth Strawn Group (“Strawn”) is flowing within the annulus of a Barnett Shale gas well, and is subsequently entering the shallow aquifer system. This interpretation is supported by the expansion in the number of affected drinking-water wells during our study period and the persistence of hydrocarbon levels over time. Our data suggest post-genetic secondary water quality changes occur following fugitive gas contamination, including sulfate reduction paired with hydrocarbon oxidation and secondary methanogenesis. Importantly, no evidence for upward migration of brine or natural gas associated with the Barnett Shale was identified.

Abstract:
The presence of methane and other hydrocarbons in domestic-use groundwater aquifers poses significant environmental and human health concerns. Isotopic measurements are often relied upon as indicators of groundwater aquifer contamination with methane. While these parameters are used to infer microbial metabolisms, there is growing evidence that isotopes present an incomplete picture of subsurface microbial processes. This study examined the relationships between microbiology and chemistry in groundwater wells located in the Denver-Julesburg Basin of Colorado, a rapidly urbanizing area with active oil and gas development. A primary goal was to determine if microbial data can reliably indicate the quantities and sources of groundwater methane. Comprehensive chemical and molecular analyses were performed on 39 groundwater well samples from five aquifers. Elevated methane concentrations were found in only one aquifer, and both isotopic and microbial data support a microbial origin. Microbial parameters had similar explanatory power as chemical parameters for predicting sample methane concentrations. Furthermore, a subset of samples with unique microbiology corresponded with unique chemical signatures that may be useful indicators of methane gas migration, potentially from nearby coal seams interacting with the aquifer. Microbial data may allow for more accurate determination of groundwater contamination and improved long-term water quality monitoring compared solely to isotopic and chemical data in areas with microbial methane.

Abstract:
The expansion of unconventional oil and gas development (UOGD) by means of horizontal drilling and high-volume hydraulic fracturing has been accompanied by concerns regarding the potential impacts to water resources and public health. The ban on UOGD in New York State (NYS) allows natural processes that control groundwater chemistry and dissolved methane to be evaluated without complications that could arise in regions impacted by prior unconventional shale gas development. We evaluated the controls on the occurrence and spatial variability of methane, chloride, bromine, and iodine, covering much of NYS and encompassing a range of underlying bedrock geologies. Groundwater samples were collected from 108 domestic and public supply wells. Methane concentrations in groundwater ranged from <0.001-84.6 mg/L. The variables most consistently associated with methane occurrence in groundwater include: 1) bedrock geology penetrated by wells; 2) groundwater chemical composition; 3) and confinement characterization of the well. The geochemical parameters iodine, chloride, and sodium/calcium suggest that elevated concentrations of methane are likely associated with deep brines. Higher methane concentrations are frequently accompanied by both high bromine and iodine concentrations in this study, indicating that the potential of halogens as tracers for dissolved methane need to be further investigated.

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

Abstract:
More than 1 million wells may have been completed using hydraulic fracturing techniques in the USA alone; however, there have been few case studies exploring the impacts on water resources due to methane migration. This study evaluated the results of three investigations initiated by the US Environmental Protection Agency, that were subsequently described in published studies at Dimock in Pennsylvania, Parker-Hood County in Texas, and Pavillion in Wyoming, as well as another study completed at Sugar Run in northeast Pennsylvania. In addition, earlier investigations at Shaws Corner in Pennsylvania, Jackson County in West Virginia, Garfield County in Colorado, and Bainbridge in Ohio are summarized. The most common cause of incidents was the presence of uncemented sections of production casings in wells that allowed gas migration from intermediate depths to shallow freshwater aquifers. In three cases, an inadequate depth of the primary top of cement (TOC) also contributed to impacts. Sources of methane were best identified through analyses of isotopes on samples from production casings, annular spaces, and water wells. In Dimock, some isotope signatures changed with time, after the completion of remedial actions. In Parker-Hood County, where impacts were not related to gas well activity, noble gas analyses were also needed to determine the source of gas. At Pavillion, where maximum methane concentrations in water wells were <1 mg/L, no significant impacts were documented. For all the sites, most or all of the fugitive gas incidents may have been prevented by fully cementing production casings to the land surface.

Abstract:
Methane (CH4) enters waters in hydrocarbon-rich basins because of natural processes and problems related to oil and gas wells. As a redox-active greenhouse gas, CH4 degrades water or emits to the atmosphere and contributes to climate change. To detect if methane migrated from hydrocarbon wells (i.e., anomalous methane), we examined 20 751 methane-containing groundwaters from the Upper Appalachian Basin (AB). We looked for concentrations (mg/L) that indicated AB brine salts (chloride concentrations ([Cl]) > 30; [Ca]/[Na] < 0.52) to detect natural methane, and we looked for concentrations of redox-active species ([SO4] ≥ 6; [Fe] ≥ 0.3) to detect anomalous methane. These indicators highlight natural contamination by methane-containing brines or recent onset of microbial oxidation of methane coupled to iron- or sulfate-reduction. We hypothesized that only waters recently contaminated by methane still exhibit high iron and sulfate concentrations. Of the AB samples, 17 (0.08%) from 12 sites indicated potential contamination. All were located in areas with high densities of shale-gas or conventional oil/gas wells. In contrast, in southwestern Pennsylvania where brines are shallow and coal, oil, and gas all have been extracted extensively, no sites of recent methane migration were detectable. Such indicators may help screen for contamination in some areas even without predrill measurements.

Abstract:
Concerns over possible impacts from the rapid expansion of unconventional oil and natural gas (ONG) resource development prompted a regional domestic well sampling program focusing on the Carboniferous Maritimes Basin bedrock in southeastern New Brunswick, Canada. This work applies recent developments in robust multivariate statistical methods to overcome issues with highly non-Gaussian data and support the development of a conceptual model for the regional groundwater chemistry and the occurrence of methane. Principal component analysis reveals that the redox-sensitive species, DO, NO3, Fe, Mn, methane, As and U are the most important parameters that differentiate the samples. Permutation-based MANOVA and ANOVA testing revealed that geology was more important than geographic location and topography in influencing groundwater composition. The statistical inferences are supported by chemistry trends observed in relation to road de-icing salt and other saline sources. However, source differentiation between Carboniferous brines, entrapped post-glacial marine water and modern seawater cannot be made. Furthermore, Cl:Br ratios lower than those of seawater or regional brines suggest an origin related to the diagenesis of organic-rich sediment and that the groundwater may be influenced by local low permeability units. Combined spatial, statistical and chemical analysis shows that, while trace or low levels of methane, <1 mg/L, are found ubiquitously throughout the Maritimes Basin, elevated concentrations, >1 mg/L, are associated with the Horton Group, consistent with it being the host and inferred source of ONG resources in the province. The highest methane concentrations (14–29 mg/L) were detected in the region with a complex history of cycles of uplift and erosion which, in some locations, resulted in the juxtaposition at the surface of the Horton Group with several other groups of the Maritimes Basin. It is thought that proximity to the Horton Group can lead to naturally high methane concentrations in non-ONG-bearing units.

Abstract:
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

Abstract:
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.

Abstract:
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.

Abstract:
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.

Abstract:
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.

Abstract:
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.

Abstract:
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...

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:
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:
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:
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:
Understanding the source of dissolved methane in drinking-water aquifers is critical for assessing potential contributions from hydraulic fracturing in shale plays. Shallow groundwater in the Texas portion of the Haynesville Shale area (13,000 km2) was sampled (70 samples) for methane and other dissolved light alkanes. Most samples were derived from the fresh water bearing Wilcox formations and show little methane except in a localized cluster of 12 water wells (17% of total) in a approximately 30 × 30 km2 area in Southern Panola County with dissolved methane concentrations less than 10 mg/L. This zone of elevated methane is spatially associated with the termination of an active fault system affecting the entire sedimentary section, including the Haynesville Shale at a depth more than 3.5 km, and with shallow lignite seams of Lower Wilcox age at a depth of 100 to 230 m. The lignite spatial extension overlaps with the cluster. Gas wetness and methane isotope compositions suggest a mixed microbial and thermogenic origin with contribution from lignite beds and from deep thermogenic reservoirs that produce condensate in most of the cluster area. The pathway for methane from the lignite and deeper reservoirs is then provided by the fault system.

Abstract:
Since naturally occurring methane and saline groundwater are nearly ubiquitous in many sedimentary basins, delineating the effects of anthropogenic contamination sources is a major challenge for evaluating the impact of unconventional shale gas development on water quality. This study investigates the geochemical variations of groundwater and surface water before, during, and after hydraulic fracturing and in relation to various geospatial parameters in an area of shale gas development in northwestern West Virginia, United States. To our knowledge, we are the first to report a broadly integrated study of various geochemical techniques designed to apportion natural and anthropogenic sources of natural gas and salt contaminants both before and after drilling. These measurements include inorganic geochemistry (major cations and anions), stable isotopes of select inorganic constituents including strontium (87Sr/86Sr), boron (δ11B), lithium (δ7Li), and carbon (δ13C-DIC), select hydrocarbon molecular (methane, ethane, propane, butane, and pentane) and isotopic tracers (δ13C-CH4, δ13C-C2H6), tritium (3H), and noble gas elemental and isotopic composition (He, Ne, Ar) in 112 drinking-water wells, with repeat testing in 33 of the wells (total samples=145). In a subset of wells (n=20), we investigated the variations in water quality before and after the installation of nearby (<1 km) shale-gas wells. Methane occurred above 1 ccSTP/L in 37% of the groundwater samples and in 79% of the samples with elevated salinity (chloride >50 mg/L). The integrated geochemical data indicate that the saline groundwater originated via naturally occurring processes, presumably from the migration of deeper methane-rich brines that have interacted extensively with coal lithologies. These observations were consistent with the lack of changes in water quality observed in drinking-water wells following the installation of nearby shale-gas wells. In contrast to groundwater samples that showed no evidence of anthropogenic contamination, the chemistry and isotope ratios of surface waters near known spills or leaks occurring at disposal sites (n=8) mimicked the composition of the Marcellus flowback fluids, and show direct evidence for impact on surface water by fluids accidentally released from nearby shale-gas well pads and oil and gas wastewater disposal sites. Overall this study presents a comprehensive geochemical framework that can be used as a template for assessing the sources of elevated hydrocarbons and salts to water resources in areas potentially impacted by oil and gas development.

Abstract:
Since the 1800s, natural gas has been extracted from wells drilled into conventional reservoirs. Today, gas is also extracted from shale using high-volume hydraulic fracturing (HVHF). These wells sometimes leak methane and must be re-sealed with cement. Some researchers argue that methane concentrations, C, increase in groundwater near shale-gas wells and that “fracked” wells leak more than conventional wells. We developed techniques to mine datasets of groundwater chemistry in Pennsylvania townships where contamination had been reported. Values of C measured in shallow private water wells were discovered to increase with proximity to faults and to conventional, but not shale-gas, wells in the entire area. However, in small subareas, C increased with proximity to some shale-gas wells. Data mining was used to map a few hotspots where C significantly correlates with distance to faults and gas wells. Near the hotspots, 3 out of 132 shale-gas wells (~ 2%) and 4 out of 15 conventional wells (27%) intersect faults at depths where they are reported to be uncased or uncemented. These results demonstrate that even though these data techniques do not establish causation, they can elucidate the controls on natural methane emission along faults and may have implications for gas well construction.

Abstract:
As shale and tight gas basins are increasingly used to extract natural gas, understanding how gas migrates is important. Wood and Sanei find that secondary migration in a tight-gas basin leads to up-dip transmission of enriched methane into surficial strata which may leak into groundwater and the atmosphere.

Abstract:
This study places constraints on the source and transport mechanisms of methane found in groundwater within the Barnett Shale footprint in Texas using dissolved noble gases, with particular emphasis on 84Kr and 132Xe. Dissolved methane concentrations are positively correlated with crustal 4He, 21Ne and 40Ar and suggest that noble gases and methane originate from common sedimentary strata, likely the Strawn Group. In contrast to most samples, four water wells with the highest dissolved methane concentrations unequivocally show strong depletion of all atmospheric noble gases (20Ne, 36Ar, 84Kr, 132Xe) with respect to air-saturated water (ASW). This is consistent with predicted noble gas concentrations in a water phase in contact with a gas phase with initial ASW composition at 18°C-25°C and it suggests an in-situ, highly localized gas source. All of these four wells tap into the Strawn Group and it is likely that small gas accumulations known to be present in the shallow subsurface were reached. Additionally, lack of correlation of 84Kr/36Ar and 132Xe/36Ar fractionation levels along with 4He/20Ne with distance to the nearest gas production wells does not support the notion that methane present in these groundwaters migrated from nearby production wells either conventional or using hydraulic fracturing techniques.

Abstract:
The recent boom in shale gas development in the Marcellus Shale has increased interest in the methods to distinguish between naturally occurring methane in groundwater and stray methane associated with drilling and production operations. This study evaluates the relationship between natural methane occurrence and three principal environmental factors (groundwater redox state, water type, and topography) using two pre-drill datasets of 132 samples from western Pennsylvania, Ohio, and West Virginia and 1417 samples from northeastern Pennsylvania. Higher natural methane concentrations in residential wells are strongly associated with reducing conditions characterized by low nitrate and low sulfate ([NO3−] < 0.5 mg/L; [SO42−] < 2.5 mg/L). However, no significant relationship exists between methane and iron [Fe(II)], which is traditionally considered an indicator of conditions that have progressed through iron reduction. As shown in previous studies, water type is significantly correlated with natural methane concentrations, where sodium (Na) -rich waters exhibit significantly higher (p<0.001) natural methane concentrations than calcium (Ca)-rich waters. For water wells exhibiting Na-rich waters and/or low nitrate and low sulfate conditions, valley locations are associated with higher methane concentrations than upland topography. Consequently, we identify three factors (“Low NO3− & SO42−” redox condition, Na-rich water type, and valley location), which, in combination, offer strong predictive power regarding the natural occurrence of high methane concentrations. Samples exhibiting these three factors have a median methane concentration of 10,000 µg/L. These heuristic relationships may facilitate the design of pre-drill monitoring programs and the subsequent evaluation of post-drill monitoring results to help distinguish between naturally occurring methane and methane originating from anthropogenic sources or migration pathways.

Abstract:
Recent expansion of shale and coal seam gas production worldwide has increased the need for geochemical studies in aquifers near gas deposits, to determine processes impacting groundwater quality and better understand the origins and behavior of dissolved hydrocarbons. We determined dissolved methane concentrations (n = 36) and δ(13)C and δ(2)H values (n = 31) in methane and groundwater from the 46,000-km(2) Gippsland Basin in southeast Australia. The basin contains important water supply aquifers and is a potential target for future unconventional gas development. Dissolved methane concentrations ranged from 0.0035 to 30 mg/L (median = 8.3 mg/L) and were significantly higher in the deep Lower Tertiary Aquifer (median = 19 mg/L) than the shallower Upper Tertiary Aquifer (median = 3.45 mg/L). Groundwater δ(13)CDIC values ranged from -26.4 to -0.4 ‰ and were generally higher in groundwater with high methane concentrations (mean δ(13)CDIC = -9.5 ‰ for samples with >3 mg/L CH4 vs. -16.2 ‰ in all others), which is consistent with bacterial methanogenesis. Methane had δ(13)CCH4 values of -97.5 to -31.8 ‰ and δ(2)HCH4 values of -391 to -204 ‰ that were also consistent with bacterial methane, excluding one site with δ(13)CCH4 values of -31.8 to -37.9 ‰, where methane may have been thermogenic. Methane from different regions and aquifers had distinctive stable isotope values, indicating differences in the substrate and/or methanogenesis mechanism. Methane in the Upper Tertiary Aquifer in Central Gippsland had lower δ(13)CCH4 (-83.7 to -97.5 ‰) and δ(2)HCH4 (-236 to -391 ‰) values than in the deeper Lower Tertiary Aquifer (δ(13)CCH4 = -45.8 to -66.2 ‰ and δ(2)HCH4 = -204 to -311 ‰). The particularly low δ(13)CCH4 values in the former group may indicate methanogenesis at least partly through carbonate reduction. In deeper groundwater, isotopic values were more consistent with acetate fermentation. Not all methane at a given depth and location is interpreted as being necessarily produced in situ. We propose that high dissolved sulphate concentrations in combination with high methane concentrations can indicate gas resulting from contamination and/or rapid migration as opposed to in situ bacterial production or long-term migration. Isotopes of methane and dissolved inorganic carbon (DIC) serve as further lines of evidence to distinguish methane sources. The study demonstrates the value of isotopic characterisation of groundwater including dissolved gases in basins containing hydrocarbons.

Abstract:
Baseline characterization of concentrations and isotopic values of dissolved natural gases is needed to identify contamination caused by the leakage of fugitive gases from oil and gas activities. Methods to collect and analyze baseline concentration-depth profiles of dissolved CH4 and C2H6 and δ13C-CH4 in shales and Quaternary clayey tills were assessed at two sites in the Williston Basin, Canada. Core and cuttings samples were stored in Isojars® in a low O2 headspace prior to analysis. Measurements and multiphase diffusion modeling show that the gas concentrations in core samples yield well-defined and reproducible depth profiles after 31-d equilibration. No measurable oxidative loss or production during core sample storage was observed. Concentrations from cuttings and mud gas logging (including IsoTubes®) were much lower than from cores, but correlated well. Simulations suggest the lower concentrations from cuttings can be attributed to drilling time, and therefore their use to define gas concentration profiles may have inherent limitations. Calculations based on mud gas logging show the method can provide estimates of core concentrations if operational parameters for the mud gas capture cylinder are quantified. The δ13C-CH4 measured from mud gas, IsoTubes®, cuttings, and core samples are consistent, exhibiting slight variations that should not alter the implications of the results in identifying the sources of the gases. This study shows core and mud gas techniques and, to a lesser extent, cuttings, can generate high-resolution depth profiles of dissolved hydrocarbon gas concentrations and their isotopes.

Abstract:
Hydraulic fracturing of shale deposits has greatly increased the productivity of the natural gas industry by allowing it to exploit previously inaccessible reservoirs. Previous research has demonstrated that this practice has the potential to contaminate shallow aquifers with methane (CH4) from deeper formations. This study compares concentrations and isotopic compositions of CH4 sampled from domestic groundwater wells in Letcher County, Eastern Kentucky in order to characterize its occurrence and origins in relation to both neighboring hydraulically fractured natural gas wells and surface coal mines. The studied groundwater showed concentrations of CH4 ranging from 0.05 mg/L to 10 mg/L, thus, no immediate remediation is required. The δ13C values of CH4 ranged from −66‰ to −16‰, and δ2H values ranged from −286‰ to −86‰, suggesting an immature thermogenic and mixed biogenic/thermogenic origin. The occurrence of CH4 was not correlated with proximity to hydraulically fractured natural gas wells. Generally, CH4 occurrence corresponded with groundwater abundant in Na+, Cl−, and HCO3−, and with low concentrations of SO42−. The CH4 and SO42−concentrations were best predicted by the oxidation/reduction potential of the studied groundwater. CH4 was abundant in more reducing waters, and SO42− was abundant in more oxidizing waters. Additionally, groundwater in greater proximity to surface mining was more likely to be oxidized. This, in turn, might have increased the likelihood of CH4 oxidation in shallow groundwater.

Abstract:
Unconventional oil and gas development has generated intense public concerns about potential impacts to groundwater quality. Specific pathways of contamination have been identified; however, overall rates of contamination remain ambiguous. We used an archive of geochemical data collected from 1988 to 2014 to determine the sources and occurrence of groundwater methane in the Denver-Julesburg Basin of northeastern Colorado. This 60,000-km2 region has a 60-y-long history of hydraulic fracturing, with horizontal drilling and high-volume hydraulic fracturing beginning in 2010. Of 924 sampled water wells in the basin, dissolved methane was detected in 593 wells at depths of 20–190 m. Based on carbon and hydrogen stable isotopes and gas molecular ratios, most of this methane was microbially generated, likely within shallow coal seams. A total of 42 water wells contained thermogenic stray gas originating from underlying oil and gas producing formations. Inadequate surface casing and leaks in production casing and wellhead seals in older, vertical oil and gas wells were identified as stray gas migration pathways. The rate of oil and gas wellbore failure was estimated as 0.06% of the 54,000 oil and gas wells in the basin (lower estimate) to 0.15% of the 20,700 wells in the area where stray gas contamination occurred (upper estimate) and has remained steady at about two cases per year since 2001. These results show that wellbore barrier failure, not high-volume hydraulic fracturing in horizontal wells, is the main cause of thermogenic stray gas migration in this oil- and gas-producing basin.

Abstract:
Concern over potential impact of shale gas development on shallow groundwater systems requires greater understanding of crustal scale fluid movement. We examined natural deeply circulating groundwater systems in northeastern British Columbia adjacent to a region of shale gas development, in order to elucidate origin of waters, depths of circulation, and controls on fluid flow. These systems are expressed as thermal springs that occur in the deformed sedimentary rocks of the Liard Basin. Stable isotope data from these springs show that they originate as meteoric water. Although there are no thermal anomalies in the region, outlet temperatures range from 30 to 56 °C, reflecting depth of circulation. Based on aqueous geothermometry and geothermal gradients, circulation depths up to 3.8 km are estimated, demonstrating connection of deep groundwater systems to the surface. Springs are also characterised by leakage of thermogenic gas from deep strata that is partly attenuated by methanotrophic microbial communities in the spring waters. Springs are restricted to anomalous structural features, cross cutting faults, and crests of fault-cored anticlines. On a regional scale they are aligned with the major tectonic features of the Liard Line and Larsen Fault. This suggests that while connection of surface to deep reservoirs is possible, it is rare and restricted to highly deformed geologic units that produce permeable pathways from depth through otherwise thick intervening shale units. Results allow a better understanding of potential for communication between deep shale gas units and shallow aquifer systems.

Abstract:
More than 90% of Germany's domestic natural gas production and reserves are located in Lower Saxony, North Germany. Recently, research has been intensified with respect to unconventional shale gas, revealing a large additional resource potential in northern Germany. However, many concerns arise within the general public and government/political institutions over potential groundwater contamination from additional gas wells through hydraulic fracturing operations. In order to determine the naturally occurring background methane concentrations, ∼1000 groundwater wells, covering ∼48 000 km2, have been sampled and subsequently analyzed for dissolved methane, ethane and propane and the isotopic composition of methane (δ13C). Dissolved methane concentrations cover a range of ∼7 orders of magnitude between the limit of quantification at ∼20 nl/l and 60 ml/l. The majority of groundwater wells exhibit low concentrations (<1 μl/l), a small number of samples (65) reveal concentration in the range >10 ml/l. In 27% of all samples ethane and in 8% ethane and propane was detected. The median concentration of both components is generally very low (ethane 50 nl/l, propane 23 nl/l). Concentrations reveal a bimodal distribution of the dissolved gas, which might mirror a regional trend due to different hydrogeological settings. The isotopic composition of methane is normally distributed (mean ∼ −70‰ vs PDB), but shows a large variation between −110‰ and +20‰. Samples with δ13C values lower than −55‰ vs PDB (66%) are indicative for methanogenic biogenic processes. 5% of the samples are unusually enriched in 13C (≥25‰ vs PDB) and can best be explained by microbial methane oxidation. According to a standard diagnostic diagram based on methane δ13C values and the ratio of methane over the sum over ethane plus propane (“Bernard”-diagram) less than 4% of the samples plot into the diagnostic field of typical thermogenic natural gases. However, in most cases only ethane has been detected and the remaining less than 15 samples demonstrate an uncommon ratio of ethane to propane compared to typical thermogenic hydrocarbons. These data do not suggest a migration of deeper sourced gases, but a thermogenic source cannot be excluded entirely for some samples. However, ethane and propane can also be generated by microbial processes and might therefore represent ubiquitous background groundwater abundances of these gases. Nevertheless, our data suggest that due to the exceedingly low concentration of ethane and propane, respective concentration changes might prove to be a more sensitive parameter than methane to detect possible migration of deeper sourced (thermally generated) hydrocarbons into a groundwater aquifer.

Abstract:
Development of unconventional energy resources such as shale gas and coalbed methane has generated some public concern with regard to the protection of groundwater and surface water resources from leakage of stray gas from the deep subsurface. In terms of environmental impact to and risk assessment of shallow groundwater resources, the ultimate challenge is to distinguish (a) natural in situ production of biogenic methane, (b) biogenic or thermogenic methane migration into shallow aquifers due to natural causes, and (c) thermogenic methane migration from deep sources due to human activities associated with the exploitation of conventional or unconventional oil and gas resources. This study combines aqueous and gas (dissolved and free) geochemical and isotope data from 372 groundwater samples obtained from 186 monitoring wells of the provincial Groundwater Observation Well Network (GOWN) in Alberta (Canada), a province with a long record of conventional and unconventional hydrocarbon exploration. We investigated whether methane occurring in shallow groundwater formed in situ, or whether it migrated into the shallow aquifers from elsewhere in the stratigraphic column. It was found that methane is ubiquitous in groundwater in Alberta and is predominantly of biogenic origin. The highest concentrations of biogenic methane (> 0.01 mM or >0.2 mg L-1), characterized by delta C-13(CH4) values < -55 parts per thousand, occurred in anoxic Na-Cl, Na-HCO3, and Na-HCO3-Cl type groundwaters with negligible concentrations of nitrate and sulfate suggesting that methane was formed in situ under methanogenic conditions for 39.1% of the samples. In only a few cases (3.7%) was methane of biogenic origin found in more oxidizing shallow aquifer portions suggesting limited upward migration from deeper methanogenic aquifers. Of the samples, 14.1% contained methane with delta C-13(CH4) values >-54 parts per thousand, potentially suggesting a thermogenic origin, but aqueous and isotope geochemistry data revealed that the elevated delta C-13(CH4) values were caused by microbial oxidation of biogenic methane or post-sampling degradation of low CH4 content samples rather than migration of deep thermogenic gas. A significant number of samples (39.2%) contained methane with predominantly biogenic C isotope ratios (delta C-13(CH4) < -55 parts per thousand) accompanied by elevated concentrations of ethane and sometimes trace concentrations of propane. These gases, observed in 28.1% of the samples, bearing both biogenic (delta C-13) and thermogenic (presence of C-3) characteristics, are most likely derived from shallow coal seams that are prevalent in the Cretaceous Horseshoe Canyon and neighboring formations in which some of the groundwater wells are completed. The remaining 3.7% of samples were not assigned because of conflicting parameters in the data sets or between replicates samples. Hence, despite quite variable gas concentrations and a wide range of delta C-13(CH4) values in baseline groundwater samples, we found no conclusive evidence for deep thermogenic gas migration into shallow aquifers either naturally or via anthropogenically induced pathways in this baseline groundwater survey. This study shows that the combined interpretation of aqueous geochemistry data in concert with chemical and isotopic compositions of dissolved and/or free gas can yield unprecedented insights into formation and potential migration of methane in shallow groundwater. This enables the assessment of cross-formational methane migration and provides an understanding of alkane gas sources and pathways necessary for a stringent baseline definition in the context of current and future unconventional hydrocarbon exploration and exploitation.

Abstract:
Shale gas exploration in the St. Lawrence Platform of southern Quebec (eastern Canada) focussed on the Upper Ordovician Utica Shale from 2006 to 2010 during which 28 wells were drilled, 18 of which were fracked. The St. Lawrence Platform is thus considered as a pristine geological domain where potential environmental effects of fracking can be evaluated relative to the natural baseline conditions of the shallow aquifers. In the Saint-Édouard area southwest of Quebec City, it has been shown that groundwater carries variable and locally high levels of naturally occurring dissolved hydrocarbons in which thermogenic ethane and propane can be found. Fifteen shallow (30–147 m) wells were drilled into bedrock and sampled (cores and cuttings) with the purpose of characterizing the shallow bedrock in a shale gas pre-development context. The shallow bedrock geology is made of three Upper Ordovician clastic formations. The Lotbinière and Les Fonds formations are time- and facies-correlative with the Utica Shale present at a depth of 1.5 to 2 km in this area. They are dominated by calcareous black shales with minor siltstone and micrite beds. The Nicolet Formation is the youngest unit of the area and consists of gray to dark gray shales with locally abundant thick siltstone and fine-grained sandstone beds. The organic matter in the Lotbinière and Les Fonds formations is represented by solid bitumen with subordinate liptinite algae, graptolites and chitinozoans representing normal marine Type II kerogen. Both formations are at the post-peak hydrocarbon generation as indicated by the equivalent random vitrinite reflectance of 0.94 to 1.04%. Rock Eval data support the Type II nature of the kerogen and the late oil window maturation level. Hydrocarbon extracts from the three formations have yielded high to low concentrations of C1 to C6. For all units, an upward decrease in total volatiles (C1 + C2 + C3) together with an increase in the gas dryness ratio (C1/C2 + C3) is recorded, the transitions occurring at depths shallower than 50 m where the shales are more fractured. The upward increase in the gas dryness ratio results from the more significant reduction of ethane and propane concentrations compared to that of methane. Consistent with the dryness ratio trend, the δ13CVPDB values of methane change from thermogenic values (≈− 50‰) for deeper samples, to more biogenic (negative) values (<− 60‰) at shallow depths. A similar δ2HVSMOW trend of more negative values at shallower depths is noted. The δ13CVPDB and δ2HVSMOW values of rock-hosted methane indicate that samples at shallow depth recorded a microbial influence. It is proposed that diffusion and some microbial degradation of hydrocarbons are responsible for the decrease of rock volatiles and the in situ generation of biogenic methane in the shales at shallow depths to mix with the in situ thermogenic methane. The Utica Shale is a very good source rock with high generation potential. However, thermogenic volatiles can also originate from shallower units with much shorter migration pathways. The mixed thermogenic and biogenic methane in the groundwater results from fracture-enhanced diffusion and biodegradation of volatiles at shallow depths.

Abstract:
Analysis of dissolved light hydrocarbon gas concentrations (primarily methane and ethane) in water supply wells is commonly used to establish conditions before and after drilling in areas of shale gas and oil extraction. Several methods are currently used to collect samples for dissolved gas analysis from water supply wells; however, the reliability of results obtained from these methods has not been quantified. This study compares dissolved methane and ethane concentrations measured in groundwater samples collected using three sampling methods employed in pre- and post-drill sampling programs in the Appalachian Basin. These include an open-system collection method where 40 mL volatile organic analysis (VOA) vials are filled directly while in contact with the atmosphere (Direct-Fill VOA) and two alternative methods: (1) a semi-closed system method whereby 40 mL VOA vials are filled while inverted under a head of water (Inverted VOA) and (2) a relatively new (2013) closed system method in which the sample is collected without direct contact with purge water or the atmosphere (IsoFlask®). This study reveals that, in the absence of effervescence, the difference in methane concentrations between the three sampling methods was relatively small. However, when methane concentrations equaled or exceeded 20 mg/L (the approximate concentration at which effervescence occurs in the study area), IsoFlask® (closed system) samples yielded significantly higher methane concentrations than Direct-Fill VOA (open system) samples, and Inverted VOA (semi-closed system) samples yielded lower concentrations. These results suggest that open and semi-closed system sample collection methods are adequate for non-effervescing samples. However, the use of a closed system collection method provides the most accurate means for the measurement of dissolved hydrocarbon gases under all conditions.

Abstract:
To assess potential future impacts on shallow aquifers by leakage of natural gas from unconventional energy resource development it is essential to establish a reliable baseline. Occurrence of methane in shallow groundwater in Alberta between 2006 and 2014 was assessed and was ubiquitous in 186 sampled monitoring wells. Free and dissolved gas sampling and measurement approaches yielded comparable results with low methane concentrations in shallow groundwater, but in 28 samples from 21 wells methane exceeded 10 mg/L in dissolved gas and 300,000 ppmv in free gas. Methane concentrations in free and dissolved gas samples were found to increase with well depth and were especially elevated in groundwater obtained from aquifers containing coal seams and shale units. Carbon isotope ratios of methane averaged − 69.7 ± 11.1‰ (n = 63) in free gas and − 65.6 ± 8.9‰ (n = 26) in dissolved gas. δ13C values were not found to vary with well depth or lithology indicating that methane in Alberta groundwater was derived from a similar source. The low δ13C values in concert with average δ2HCH4 values of − 289 ± 44‰ (n = 45) suggest that most methane was of biogenic origin predominantly generated via CO2 reduction. This interpretation is confirmed by dryness parameters typically > 500 due to only small amounts of ethane and a lack of propane in most samples. Comparison with mud gas profile carbon isotope data revealed that methane in the investigated shallow groundwater in Alberta is isotopically similar to hydrocarbon gases found in 100–250 meter depths in the WCSB and is currently not sourced from thermogenic hydrocarbon occurrences in deeper portions of the basin. The chemical and isotopic data for methane gas samples obtained from Alberta groundwater provide an excellent baseline against which potential future impact of deeper stray gases on shallow aquifers can be assessed.

Abstract:
Prior work suggests spatial parameters (e.g., landscape position, distance to nearest gas well) can be used to estimate the amount of dissolved methane in domestic drinking water wells overlying the deep Marcellus Shale. New York (NY) provides an opportunity to investigate methane occurrence prior to expansion of high-volume hydraulic fracturing because unconventional gas production is currently banned in the state. We sampled domestic groundwater wells for methane in 2013 (n = 137) across five counties of NY bordering Pennsylvania, and then resampled a subset of those wells in 2014 for methane concentrations and δ13C-CH4 and δD-CH4. The majority of waters from wells sampled (77%) had low concentrations of methane (<0.1 mg/L), and only 5% (n = 7) had actionable levels of methane (>10 mg/L). Dissolved methane concentrations did not change as a function of proximity to existing vertical gas wells, nor other parameters indicating subsurface planes of weakness (i.e., faults or lineaments). Methane levels were significantly higher in wells closer to hydrography flow lines, and most strongly correlated to Na-HCO3 water type. The distribution of methane between Ca-HCO3 (n = 76) and Na-HCO3 (n = 23) water types significantly differed (p < 0.01), with median methane concentrations of 0.002 and 0.78 mg/L, respectively. Combined classification of sampled waters based on the dominant water cation, well topographic position, and geologic unit of well completion effectively identified wells with a greater than 50% probability of having methane concentrations exceeding 1 mg/L. Such classification schemes may be useful as a screening tool to assess natural versus gas production-related sources of methane in domestic wells.

Abstract:
The last decade has seen a dramatic increase in domestic energy production from unconventional reservoirs. This energy boom has generated marked economic benefits, but simultaneously evoked significant concerns regarding the potential for drinking-water contamination in shallow aquifers. Presently, efforts to evaluate the environmental impacts of shale gas development in the northern Appalachian Basin (NAB), located in the northeastern US, are limited by: (1) a lack of comprehensive “pre-drill” data for groundwater composition (water and gas); (2) uncertainty in the hydrogeological factors that control the occurrence of naturally present CH4 and brines in shallow Upper Devonian (UD) aquifers; and (3) limited geochemical techniques to quantify the sources and migration of crustal fluids (specifically methane) at various time scales. To address these questions, we analyzed the noble gas, dissolved ion, and hydrocarbon gas geochemistry of 72 drinking-water wells and one natural methane seep all located ≫1 km from shale gas drill sites in the NAB. In the present study, we consciously avoided groundwater wells from areas near active or recent drilling to ensure shale gas development would not bias the results. We also intentionally targeted areas with naturally occurring CH4 to characterize the geochemical signature and geological context of gas-phase hydrocarbons in shallow aquifers of the NAB. Our data display a positive relationship between elevated [CH4], [C2H6], [Cl], and [Ba] that co-occur with high [4He]. Although four groundwater samples show mantle contributions ranging from 1.2% to 11.6%, the majority of samples have [He] ranging from solubility levels (∼45 × 10−6 cm3 STP/L) with below-detectable [CH4] and minor amounts of tritiogenic 3He in low [Cl] and [Ba] waters, up to high [4He] = 0.4 cm3 STP/L with a purely crustal helium isotopic end-member (3He/4He = ∼0.02 times the atmospheric ratio (R/Ra)) in samples with CH4 near saturation for shallow groundwater (P(CH4) = ∼1 atmosphere) and elevated [Cl] and [Ba]. These data suggest that 4He is dominated by an exogenous (i.e., migrated) crustal source for these hydrocarbon gas- and salt-rich fluids. In combination with published inorganic geochemistry (e.g., 87Sr/86Sr, Sr/Ba, Br−/Cl−), new noble gas and hydrocarbon isotopic data (e.g., 20Ne/36Ar, C2+/C1, δ13C-CH4) suggest that a hydrocarbon-rich brine likely migrated from the Marcellus Formation (via primary hydrocarbon migration) as a dual-phase fluid (gas + liquid) and was fractionated by solubility partitioning during fluid migration and emplacement into conventional UD traps (via secondary hydrocarbon migration). Based on the highly fractionated 4He/CH4 data relative to Marcellus and UD production gases, we propose an additional phase of hydrocarbon gas migration where natural gas previously emplaced in UD hydrocarbon traps actively diffuses out into and equilibrates with modern shallow groundwater (via tertiary hydrocarbon migration) following uplift, denudation, and neotectonic fracturing. These data suggest that by integrating noble gas geochemistry with hydrocarbon and dissolved ion chemistry, one can better determine the source and migration processes of natural gas in the Earth’s crust, which are two critical factors for understanding the presence of hydrocarbon gases in shallow aquifers.

Abstract:
Migration of stray methane gas near the town of Dimock, Pennsylvania, has been at the center of the debate on the safety of shale gas drilling and hydraulic fracturing in the United States. The presented study relates temporal variations in molecular concentrations and stable isotope compositions of methane and ethane to shale-gas well activity (i.e., vertical/horizontal drilling, hydraulic fracturing and remedial actions). This was accomplished by analyzing data collected, between 2008 and 2012, by state and federal agencies and the gas well operator. In some cases, methane migration started prior to hydraulic fracturing. Methane levels of contaminated water wells sampled were one to several orders of magnitude greater than the concentrations due to natural variation in water wells of the local area. Isotope analyses indicate that all samples had a thermogenic origin at varying maturity levels, but from formations above the hydraulically fractured Marcellus Shale. The results from the initial water well samples were similar to annular gas values, but not those of production gases. This indicates that leakage by casing cement seals most likely caused the impacts, not breaks in the production casing walls. Remediation by squeeze cementing was partially effective in mitigating impacts of gas migration. In several cases where remediation caused a substantial reduction in methane levels, there were also substantial changes in the isotope values, providing evidence of two sources, one natural and the other man-induced. Sampling water wells while venting gas wells appears to be a cost-effective method for determining if methane migration has occurred.

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

Abstract:
Methane and brine leakage rates and associated time scales along the cemented casing of a hypothetical decommissioned shale gas well have been assessed with a multiphase flow and multicomponent numerical model. The conceptual model used for the simulations assumes that the target shale formation is 200 m thick, overlain by a 750 m thick caprock, which is in turn overlain by a 50 m thick surficial sand aquifer, the 1000 m geological sequence being intersected by a fully penetrating borehole. This succession of geological units is representative of the region targeted for shale gas exploration in the St. Lawrence Lowlands (Québec, Canada). The simulations aimed at assessing the impact of well casing cementation quality on methane and brine leakage at the base of a surficial aquifer. The leakage of fluids can subsequently lead to the contamination of groundwater resources and/or, in the case of methane migration to ground surface, to an increase in greenhouse gas emissions. The minimum reported surface casing vent flow (measured at ground level) for shale gas wells in Quebec (0.01 m3/d) is used as a reference to evaluate the impact of well casing cementation quality on methane and brine migration. The simulations suggest that an adequately cemented borehole (with a casing annulus permeability kc ≤ 1 mD) can prevent methane and brine leakage over a time scale of up to 100 years. However, a poorly cemented borehole (kc ≥ 10 mD) could yield methane leakage rates at the base of an aquifer ranging from 0.04 m3/d to more than 100 m3/d, depending on the permeability of the target shale gas formation after abandonment and on the quantity of mobile gas in the formation. These values are compatible with surface casing vent flows reported for shale gas wells in the St. Lawrence Lowlands (Quebec, Canada). The simulated travel time of methane from the target shale formation to the surficial aquifer is between a few months and 30 years, depending on cementation quality and hydrodynamic properties of the casing annulus. Simulated long-term brine leakage rates after 100 years for poorly cemented boreholes are on the order of 10−5 m3/d (10 mL/d) to 10−3 m3/d (1 L/d). Based on scoping calculations with a well-mixed aquifer model, these rates are unlikely to have a major impact on groundwater quality in a confined aquifer since they would only increase the chloride concentration in a pristine aquifer to 1 mg/L, which is significantly below the commonly recommended aesthetic objective of 250 mg/L for chloride.

Abstract:
The environmental impacts of shale,gas development on water resources, including methane migration to shallow groundwater, have been difficult to assess. Monitoring around gas wells is generally limited to domestic water-supply well's, which often are not situated along predominant groundwater flow paths. A new concept is tested here: combining stream hydrocarbon and noble-gas measurements with reach mass-balance modeling to estimate thermogenic methane concentrations and fluxes in groundwater discharging to streams and to constrain methane sources. In the Marcellus Formation shalegas play of northern Pennsylvania (U.S.A.), we sampled methane in 15 streams as a reconnaissance tool to locate methane-laden groundwater discharge: concentrations up to 69 mu gL(-1) were observed, with four streams >= 5 mu g L-1. Geochemical analyses of water from one stream with high methane (Sugar Run, Lycoming County) were consistent with Middle Devonian gases. After sampling was completed, we learned of a state regulator investigation of stray-gas migration from a nearby Marcellus Formation gas well. Modeling indicates a groundwater thermogenic methane flux of about 0.5 kg d(-1) discharging into Sugar Run, possibly from this fugitive gas source. Since flow paths often coalesce into gaining streams, stream methane monitoring provides the first watershed-scale method to assess grOundwatet contamination from shale-gas development.

Abstract:
Recent studies in northeastern Pennsylvania report higher concentrations of dissolved methane in domestic water wells associated with proximity to nearby gas-producing wells [Osborn et al. Proc. Natl. Acad. Sci. U. S. A. 2011, 108, 8172] and [Jackson et al. Proc. Natl. Acad. Sci. U. S. A., 2013, 110, 11250]. We test this possible association by using Chesapeake Energy?s baseline data set of over 11,300 dissolved methane analyses from domestic water wells, densely arrayed in Bradford and nearby counties (Pennsylvania), and near 661 pre-existing oil and gas wells. The majority of these, 92%, were unconventional wells, drilled with horizontal legs and hydraulically fractured. Our data set is hundreds of times larger than data sets used in prior studies. In contrast to prior findings, we found no statistically significant relationship between dissolved methane concentrations in groundwater from domestic water wells and proximity to pre-existing oil or gas wells. Previous analyses used small sample sets compared to the population of domestic wells available, which may explain the difference in prior findings compared to ours.

Abstract:
Hydraulic fracturing is becoming an important technique worldwide to recover hydrocarbons from unconventional sources such as shale gas. In Quebec (Canada), the Utica Shale has been identified as having unconventional gas production potential. However, there has been a moratorium on shale gas exploration since 2010. The work reported here was aimed at defining baseline concentrations of methane in shallow aquifers of the St. Lawrence Lowlands and its sources using δ13C methane signatures. Since this study was performed prior to large-scale fracturing activities, it provides background data prior to the eventual exploitation of shale gas through hydraulic fracturing. Groundwater was sampled from private (n=81), municipal (n=34) and observation (n=15) wells between August 2012 and May 2013. Methane was detected in 80% of the wells with an average concentration of 3.8 ± 8.8 mg/L, and a range of < 0.0006 to 45.9 mg/L. Methane concentrations were linked to groundwater chemistry and distance to the major faults in the studied area. The methane δ13C signature of 19 samples was > -50‰, indicating a potential thermogenic source. Localized areas of high methane concentrations from predominantly biogenic sources were found throughout the study area. In several samples, mixing, migration and oxidation processes likely affected the chemical and isotopic composition of the gases, making it difficult to pinpoint their origin. Energy companies should respect a safe distance from major natural faults in the bedrock when planning the localization of hydraulic fracturation activities to minimize the risk of contaminating the surrounding groundwater since natural faults are likely to be a preferential migration pathway for methane.

Abstract:
The hypothetical leakage of methane gas caused by fracking a 1,000-m deep Cretaceous claystone horizon at Damme, Germany, is simulated in a TOUGHREACT reactive-transport model with 5,728 elements. A hypothetical leakage zone connects the Cretaceous horizon with a Quaternary potable-water aquifer (q1). Methane gas rises up to the q1 horizon in less than 2 days in all calculated scenarios. The simulations include the major constituents of groundwater as well as the seven most hazardous trace components that are natural constituents of groundwater (As, Cd, Cr, Ni, Pb, Se and U). The general trend is characterised by depletion of the natural hazardous components with decreasing acidity and oxygen fugacity in the relevant pH range (7–9). Nevertheless, the concentrations of elements whose dominant aqueous species are negatively charged in this pH range (Cr and Se) rise against the general trend due to desorption reactions. Slight enhancement effects are produced by the dissolution of contaminant-bearing oxides such as Cr-bearing goethite. In summary, the geological risks of a fracking operation are minor. The technical risks are more important. This is especially the case when rising methane gas gets into contact with fracking fluid that accidentally escapes through faulty well seals.

Abstract:
Horizontal drilling and hydraulic fracturing have enhanced energy production but raised concerns about drinking-water contamination and other environmental impacts. Identifying the sources and mechanisms of contamination can help improve the environmental and economic sustainability of shale-gas extraction. We analyzed 113 and 20 samples from drinking-water wells overlying the Marcellus and Barnett Shales, respectively, examining hydrocarbon abundance and isotopic compositions (e.g., C2H6/CH4, δ13C-CH4) and providing, to our knowledge, the first comprehensive analyses of noble gases and their isotopes (e.g., 4He, 20Ne, 36Ar) in groundwater near shale-gas wells. We addressed two questions. (i) Are elevated levels of hydrocarbon gases in drinking-water aquifers near gas wells natural or anthropogenic? (ii) If fugitive gas contamination exists, what mechanisms cause it? Against a backdrop of naturally occurring salt- and gas-rich groundwater, we identified eight discrete clusters of fugitive gas contamination, seven in Pennsylvania and one in Texas that showed increased contamination through time. Where fugitive gas contamination occurred, the relative proportions of thermogenic hydrocarbon gas (e.g., CH4, 4He) were significantly higher (P < 0.01) and the proportions of atmospheric gases (air-saturated water; e.g., N2, 36Ar) were significantly lower (P < 0.01) relative to background groundwater. Noble gas isotope and hydrocarbon data link four contamination clusters to gas leakage from intermediate-depth strata through failures of annulus cement, three to target production gases that seem to implicate faulty production casings, and one to an underground gas well failure. Noble gas data appear to rule out gas contamination by upward migration from depth through overlying geological strata triggered by horizontal drilling or hydraulic fracturing.

Abstract:
Development of unconventional shale gas reservoirs in the Appalachian Basin has raised questions regarding the potential for these activities to affect shallow groundwater resources. Geochemical indicators, such as stable carbon and hydrogen isotopes of methane, stable carbon isotopes of ethane, and hydrocarbon ratios, have been used to evaluate methane sources however their utility is complicated by influences from multiple physical (e.g., mixing) and geochemical (e.g., redox) processes. Baseline sampling of shallow aquifers prior to development, and measurement of additional geochemical indicators within samples from across the Appalachian Basin, may aid in identifying natural causes for dissolved methane in shallow groundwater versus development-induced pathways.