Occurrence and origin of methane in groundwater in Alberta (Canada): Gas geochemical and isotopic approaches

Saline and hydrocarbon-bearing fluids detected in shallow aquifers of southern New Brunswick, Canada: Natural occurrence, or deep migration along faults and industrial wellbores?

Unconventional hydrocarbon production has sparked public concerns for several years, especially regarding potential potable groundwater contamination by hydrocarbons, brines, and various chemicals related to hydraulic fracturing operations. One possible contamination mechanism is upward migration of deep-seated contaminants over large vertical distances, through preferential pathways such as leaky well casings or permeable geological faults. In New Brunswick (Canada), thermogenic hydrocarbons and brackish water were previously reported in shallow water wells, some of them located close to unconventional gas wells or to major faults, but the exact origin of these fluids remained uncertain. The objective of this paper is to determine whether the presence of these fluids is the result of migration from the deep (>1 km) hydrocarbon bearing units (via natural or anthropogenic migration pathways), or whether they rather originate within the shallow aquifer (<100 m) or from intermediate zone. Tracking fluid origin was achieved by fingerprinting compositional and isotopic values of three indicators: 1) water isotopic signature (including tritium (3H), radiocarbon (14CDIC), δ18OH2O, δ2HH2O), 2) salinity (including Na, Ca, K, SO4, Cl, Br, 87Sr/86Sr), and 3) hydrocarbons (compositional data and δ13CCH4). These various analyses were conducted, when relevant, on samples of different matrices composing the hydrogeological system, namely shallow groundwater (12-90 m depth), shallow bedrock gas (8-131 m), and intermediate zone evaporitic rocks (173-332 m); they were compared with previously published values for deep basin brines and gases (1940-3168 m) from the hydrocarbon bearing Carboniferous Albert Formation. This unique suite of indicators, analytes and matrices allowed drawing the conclusion that thermogenic gas and high salinities present in the sampled wells were naturally occurring and originating from shallow and intermediate-zone bedrock units. Results obtained through this approach did not provide any evidence that hydrocarbon wells in this area have acted as preferential migration pathways for deep-seated fluids towards shallow aquifers.

What Can Groundwater Monitoring Tell Us About Gas Migration? A Numerical Modeling Study

Groundwater monitoring to measure a variety of indicator parameters including dissolved gas concentrations, total dissolved gas pressure (TDGP), and redox indicators is commonly used to evaluate the impacts of gas migration (GM) from energy development in shallow aquifer systems. However, these parameters can be challenging to interpret due to complex free-phase gas source architecture, multicomponent partitioning, and biogeochemical reactions. A series of numerical simulations using a gas flow model and a reactive transport model were conducted to delineate the anticipated evolution of indicator parameters following GM in an aquifer under a variety of physical and biogeochemical conditions. The simulations illustrate how multicomponent mass transfer processes and biogeochemical reactions create unexpected spatial and temporal variations in several analytes. The results indicate that care must be taken when interpreting measured indicator parameters including dissolved hydrocarbon concentrations and TDGP, as the presence of dissolved gases in background groundwater and biogeochemical processes can cause potentially misleading conclusions about the impact of GM. Based on the consideration of multicomponent gas partitioning in this study, it is suggested that dissolved background gases such as N2 and Ar can provide valuable insights on the presence, longevity and fate of free-phase natural gas in aquifer systems. Overall, these results contribute to developing a better understanding of indicators for GM in groundwater, which will aid the planning of future monitoring networks and subsequent data interpretation.

Field investigation of the transport and attenuation of fugitive methane in shallow groundwater around an oil and gas well with gas migration

'Fugitive' or 'stray' gas migration from deeper formations due to well bore integrity failure has prompted concern regarding environmental impacts. Unintended methane (CH4) migration can increase greenhouse gas emissions and affect groundwater quality in the critical zone. Although the CH4 transport in shallow aquifers has been investigated at experimental injection sites, no intensive groundwater studies have been published around an oil and gas well that has been leaking for a significant period of time. In this field study, groundwater samples were collected from sixteen groundwater monitoring wells (1.25 m below ground surface) installed around a suspended oil and gas well with decadal scale gas migration (estimated ~0.2 m3/day). Stray CH4 distribution and preferential pathways in the shallow groundwater zone were evaluated though high-resolution profiling of equivalent concentrations of hydrocarbon gases (C1-C6; >85 % CH4 at the study site) and bulk formation electrical conductivity to 6.0 m below ground surface. The highest dissolved CH4 concentration (0.074 mmol/L or 1.18 mg/L) in groundwater (1.25 m bgs) was observed immediately downgradient (1.25 m) of the oil and gas well head. Similarly, high-resolution profiling data also revealed the occurrence of relatively high CH4 concentrations in shallow groundwater along the groundwater flow direction and below fine-grained layers up to 10 m distance from the well head. Microbial DNA analysis from groundwater showed significant community shifts, with the highest relative abundance and diversity of methanotrophs observed in the vicinity of the oil and gas well. This study supports findings from experimental injection and laboratory studies, which also found that significant CH4 transport i) dominantly occurs in the groundwater flow direction, and ii) laterally as free phase below fine-grained layers. The occurrence of CH4 concentrations below saturation after more than two decades of gas migration suggests limited impacts have occurred in the shallow subsurface investigated.

Fluid migration pathways to groundwater in mature oil fields: Exploring the roles of water injection/production and oil-well integrity in California, USA

Mature oil fields potentially contain multiple fluid migration pathways toward protected groundwater (total dissolved solids, TDS, in nonexempted aquifer <10,000 mg/L) because of their extensive development histories. Time-series data for water use, fluid pressures, oil-well construction, and geochemistry from the South Belridge and Lost Hills mature oil fields in California are used to explore the roles of injection/production of oil-field water and well-integrity issues in fluid migration. Injection/production of oil-field water modified hydraulic gradients in both oil fields, resulting in chemical transport from deeper groundwater and hydrocarbon-reservoir systems to aquifers in the oil fields. Those aquifers are used for water supply outside the oil-field boundaries. Oil wells drilled before 1976 can be fluid migration pathways because a relatively large percentage of them have >10 m of uncemented annulus that straddles oil-well casing damage and/or the base of groundwater with TDS <10,000 mg/L. The risk of groundwater-quality degradation is higher when wells with those risk factors occur in areas with upward hydraulic gradients created by positive net injection, groundwater withdrawals, or combinations of these variables. The complex changes in hydrologic conditions and groundwater chemistry likely would not have been discovered in the absence of years to decades of monitoring data for groundwater elevations and chemistry, and installation of monitoring wells in areas with overlapping risk factors. Important monitoring concepts based on results from this and other studies include monitoring hydrocarbon-reservoir and groundwater systems at multiple spatiotemporal scales and maintaining transparency and accessibility of data and analyses. This analysis focuses on two California oil fields, but the methods used and processes affecting fluid migration could be relevant in other oil fields where substantial injection/production of oil-field water occurs and oil-well integrity is of concern.

Methane in aquifers and alluvium overlying a coal seam gas region: Gas concentrations and isotopic differentiation

The detection and attribution of methane in aquifers overlying oil and gas reservoirs has recently gained increasing attention internationally. The Surat Basin, in the Great Artesian Basin (GAB), Australia, hosts a coal seam gas (CSG) reservoir, with feedlots, town water supply, mines and agriculture that extract groundwater from aquifers that underly and overly the gas reservoir. This study aimed to use a multi-isotopic approach to differentiate biogenic methane generated in situ in GAB aquifers and the Condamine Alluvium, from the biogenic CSG produced from the underlying Walloon Coal Measures reservoir, to understand if gas had migrated or not. Dissolved methane (0.001 to 160 mg/l) and total methane concentrations (up to 91,818 ppmv) were measured using closed sampling methods and were higher than from open direct fill sampling (<0.001 to 25.4 mg/l), especially in gassy bores that contain dissolved methane above 10 to 13 mg/l. The CSG production waters and a gassy overlying aquifer bore had the most depleted water isotopes, and also the most enriched δ¹³C-DIC indicating strong methanogenesis. The majority of aquifers have isotopic signatures (δ¹³C-DIC, CH₄ and CO₂) indicating in situ methane production by primary CO₂ reduction or fermentation, distinct from secondary microbial CO₂ reduction in the CSG reservoir. Fractionation factors support methane production mainly via CO₂ reduction, with fermentation in a subset of aquifer samples. The gas wetness parameters (636 to 20,000) are consistent with mainly microbial gases, with low dissolved ethane (max 0.04 mg/l). The majority of aquifer and alluvium samples in this study are consistent with in situ methane production, not migration, however in several gassy bores the methane source could not be clearly identified. This study is broadly applicable to understanding methane sources in aquifers overlying CSG reservoirs.

In-Well Degassing of Monitoring Wells Completed in Gas-Charged Aquifers

Total dissolved gas pressure (P_TDG ) measurements are useful to measure accurate in situ dissolved gas concentrations in groundwater, but challenged by in-well degassing. Although in-well degassing has been widely observed, its cause(s) are not clear. We investigated the mechanism(s) by which gas-charged groundwater in a recently pumped well becomes degassed. Vertical P_TDG and dissolved gas concentration profiles were monitored in the standing water column (SWC) of a groundwater well screened in a gas-charged aquifer for 7 days before and 15 days after pumping. Prior to pumping, P_TDG values remained relatively constant and below calculated bubbling pressure (P_BUB ) at all depths. In contrast, significant increases in P_TDG were observed at all depths after pumping was initiated, as fresh groundwater with elevated in situ P_TDG values was pumped through the well screen. After pumping ceased, P_TDG values decreased to below P_BUB at all depths over the 15-day post-pumping period, indicating well degassing was active over this time frame. Vertical profiles of estimated dissolved gas concentrations before and after pumping provided insight into the mechanism(s) by which in-well degassing occurred in the SWC. During both monitoring periods, downward mixing of dominant atmospheric and/or tracer gases, and upwards mixing of dominant groundwater gases were observed in the SWC. The key mechanisms responsible for in-well degassing were (i) bubble exsolution when P_TDG exceeded P_BUB as gas-charged well water moves upwards in the SWC during recovery (i.e., hydraulic gradient driven convection), (ii) microadvection caused by the upward migration of bubbles under buoyancy, and (iii) long-term, thermally driven vertical convection.

Constraining the effectiveness of inherent tracers of captured CO2 for tracing CO2 leakage: Demonstration in a controlled release site

Geological storage of carbon dioxide (CO₂) is an integral component of cost-effective greenhouse gas emissions reduction scenarios. However, a robust monitoring regime is necessary for public and regulatory assurance that any leakage from a storage site can be detected. Here, we present the results from a controlled CO₂ release experiment undertaken at the K-COSEM test site (South Korea) with the aim of demonstrating the effectiveness of the inherent tracer fingerprints (noble gases, δ¹³C) in monitoring CO₂ leakage. Following injection of 396 kg CO_2(g) into a shallow aquifer, gas release was monitored for 2 months in gas/water phases in and above the injection zone. The injection event resulted in negative concentration changes of the dissolved gases, attributed to the stripping action of the depleted CO₂. Measured fingerprints from inherent noble gases successfully identified solubility-trapping of the injected CO₂ within the shallow aquifer. The δ¹³C within the shallow aquifer could not resolve the level of gas trapping, due to the interaction with heterogeneous carbonate sources in the shallow aquifer. The time-series monitoring of δ¹³C_DIC and dissolved gases detected the stripping action of injected CO_2(g), which can provide an early warning of CO₂ arrival. This study highlights that inherent noble gases can effectively trace the upwardly migrating and fate of CO₂ within a shallow aquifer.

Free-Phase Gas Detection in Groundwater Wells via Water Pressure and Continuous Field Parameters

Detection of free-phase gas (FPG) in groundwater wells is critical for accurate assessment of dissolved gas concentrations and the occurrence of FPG in the subsurface, with consequent implications for understanding groundwater contamination and greenhouse gas emissions. However, identifying FPG is challenging during routine groundwater monitoring and there is poor agreement on the best approach to detect the occurrence of FPG in groundwater. In this study, laboratory experiments in a water column were designed to mimic nonflowing and flowing conditions in a groundwater well to evaluate how the presence of FPG affects water pressure and commonly used continuous field parameters. The laboratory results were extrapolated to interpret field data at an abandoned exploration well with episodic release of free-gas CO₂ . The FPG effect on water pressure varied between flowing and nonflowing wells, and depending on whether the FPG was above or below the sensor. Electrical conductivity values were decreased and/or behaved erratically when FPG was present in the water column. Findings from this study have shown that the combined measurement of water pressure, electrical conductivity, and total dissolved gas pressure can provide information about the occurrence of FPG in groundwater wells. Measurement of these parameters at different depths can also provide information about relative depths and amounts of FPG within the well water column. This approach can be used for long-term monitoring of groundwater gases, managing gas-locking in production wells with gassy groundwater, and measuring fugitive greenhouse gas emissions from groundwater wells.

Geochemical evidence for fugitive gas contamination and associated water quality changes in drinking-water wells from Parker County, Texas

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), and noble gases (He, Ne, Ar), boron (δ¹¹B) and strontium (⁸⁷Sr/⁸⁶Sr) isotopic compositions of water samples from 20 drinking-water wells from 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 along 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.

A review of physical, chemical, and hydrogeologic characteristics of stray gas migration: Implications for investigation and remediation

Releases of natural gas into groundwater from oil and gas exploration, production, or storage (i.e., "stray gas") can pose a risk to groundwater users and landowners in the form of a fire or explosive hazard. The acute nature of stray gas risk differs from the long-term health risks posed by the ingestion or inhalation of other petroleum hydrocarbons (e.g., benzene). Stray gas also exhibits different fate and transport behaviors in the environment from other hydrocarbon contaminants, including the potential for rapid and extensive transport of free-phase gas through preferential pathways, and the resulting variable and discontinuous spatial distribution of free and dissolved gas phases. While there is extensive guidance on response actions for releases of other hydrocarbons such as benzene, there are relatively few examples available in the technical literature that discuss appropriate response measures for the investigation and remediation of stray gas impacts. This paper describes key considerations in the physical, chemical, and hydrogeological characteristics of stray gas releases and implications for the improved investigation and mitigation of associated risks.

Developing a fuzzy logic-based risk assessment for groundwater contamination from well integrity failure during hydraulic fracturing

Recent natural gas development by means of hydraulic fracturing requires a detailed risk analysis to eliminate or mitigate damage to the natural environment. Such geo-energy related subsurface activities involve complex engineering processes and uncertain data, making comprehensive, quantitative risk assessments a challenge to develop. This research seeks to develop a risk framework utilising data for quantitative numerical analysis and expert knowledge for qualitative analysis in the form of fuzzy logic, focusing on hydraulically fractured wells during the well stimulation stage applied to scenarios in the UK and Canada. New fault trees are developed for assessing cement failure in the vertical and horizontal directions, resulting in probabilities of failure of 3.42% and 0.84%, respectively. An overall probability of migration to groundwater during the well injection stage was determined as 0.0006%, compared with a Canadian case study which considered 0.13% of wells failed during any stage of the wells life cycle. It incorporates various data types to represent the complexity of hydraulic fracturing, encouraging a more complete and accurate analysis of risk failures which engineers can directly apply to old and new hydraulic fracturing sites without the necessity for extensive historic and probabilistic data. This framework can be extended to assess risk across all stages of well development, which would lead to a gap in the modelled and actual probabilities narrowing. The framework developed has relevance to other geo-energy related subsurface activities such as CO₂ sequestration, geothermal, and waste fluid injection disposal.

Occurrence and origin of groundwater methane in the Stellarton Basin, Nova Scotia, Canada

Groundwater methane (CH₄) in areas of fossil fuel development has been a recent focus of study as high CH₄ concentrations pose water quality concerns and potential explosive hazards. In 2013, a provincial study in Nova Scotia identified areas with elevated groundwater CH₄. However, due to limited data, the specific sources and local distribution of CH₄ in those areas remain unknown. In this study, we examined the Stellarton Basin in central Nova Scotia, Canada, a region with an abundance of coal formations, numerous abandoned coal mines, and an active open pit coal mine. Methane was detected in 94% of water samples that were sampled from 45 private water wells. Six water wells exceeded the 28 mg/L hazard mitigation threshold with CH₄ levels of up to 72.7 mg/L. The δ¹³C_CH4 (-85.5 to -48.5‰) and the δ²H_CH4 (-280 to -88‰) indicated that >95% of samples had CH₄ of microbial origin. However, the detection of ethane (C₂H₆) up to 2.97 mg/L and propane (C₃H₈) up to 0.008 mg/L, as well as the δ¹³C_C2H6 values (-30.1 to -15.6‰) suggested a mixture of microbial CH₄ with trace thermogenic gas, likely migrated from Stellarton coals (δ¹³C_C2H6 of -27.6 to -15.35‰). A mobile greenhouse gas analyzer survey was conducted within the perimeter of residences and off-gassing from taps had atmospheric CH₄ measurements as high as 66 ppmv. This study integrates multiple sampling and monitoring methods to investigate groundwater CH₄ in a coal-bearing region. The findings advance the understanding of the origin and occurrence of CH₄ in complex groundwater systems. The data acquired in this study may be used as a pre-drill baseline for groundwater CH₄ concentrations and origins should coal-bed methane operations in Nova Scotia proceed in the future.

Methane Emissions from Abandoned Oil and Gas Wells in California

California hosts ∼124,000 abandoned and plugged (AP) oil and gas wells, ∼38,000 idle wells, and ∼63,000 active wells, whose methane (CH₄) emissions remain largely unquantified at levels below ∼2 kg CH₄ h^-1. We sampled 121 wells using two methods: a rapid mobile plume integration method (detection ∼0.5 g CH₄ h^-1) and a more sensitive static flux chamber (detection ∼1 × 10^-6 g CH₄ h^-1). We measured small but detectable methane emissions from 34 of 97 AP wells (mean emission: 0.286 g CH₄ h^-1). In contrast, we found emissions from 11 of 17 idle wells-which are not currently producing (mean: 35.4 g CH₄ h^-1)-4 of 6 active wells (mean: 189.7 g CH₄ h^-1), and one unplugged well-an open casing with no infrastructure present (10.9 g CH₄ h^-1). Our results support previous findings that emissions from plugged wells are low but are more substantial from idle wells. In addition, our smaller sample of active wells suggests that their reported emissions are consistent with previous studies and deserve further attention. Due to limited access, we could not measure wells in most major active oil and gas fields in California; therefore, we recommend additional data collection from all types of wells but especially active and idle wells.

A dynamic baseline for dissolved methane in English groundwater

Elevated dissolved methane (CH₄) concentrations in groundwater are an environmental concern associated with hydraulic fracturing for shale gas. Therefore, determining dissolved CH₄ baselines is important for detecting and understanding any potential environmental impacts. Such baselines should change in time and space to reflect ongoing environmental change and should be able to predict the probability that a change in dissolved CH₄ concentration has occurred. We considered four dissolved CH₄ concentration datasets of English groundwater using a Bayesian approach: two national datasets and two local datasets from shale gas exploration sites. The most sensitive national dataset (the previously published British Geological Survey CH₄ baseline) was used as a strong prior for a larger (2153 measurements compared to 439) but less sensitive (detection limit 1000 times higher) Environment Agency dataset. The use of the strong prior over a weak prior improved the precision of the Environment Agency dataset by 75%. The expected mean dissolved CH₄ concentration in English groundwater based on the Bayesian approach is 0.24 mg/l, with a 95% credible interval of 0.11 to 0.45 mg/l, and a Weibull distribution of W(0.35 ± 0.01, 0.34 ± 0.16). This result indicates the amount of CH₄ degassing from English groundwater to the atmosphere equates to between 0.7 and 3.1 kt CH₄/year, with an expected value of 1.65 kt CH₄/year and a greenhouse gas warming potential of 40.3 kt CO₂eq/year. The two local monitoring datasets from shale gas exploration sites, in combination with the national datasets, show that dissolved CH₄ concentrations in English groundwater are generally low, but locations with concentrations greater than or equal to the widely used risk action level of 10.0 mg/l do exist. Statistical analyses of groundwater redox conditions at these locations suggest that it may be possible to identify other locations with dissolved CH₄ concentrations ≥10.0 mg/l using redox parameters such as Fe concentration.

Tracing nitrate sources with a combined isotope approach (δ15NNO3, δ18ONO3 and δ11B) in a large mixed-use watershed in southern Alberta, Canada

Rapid population growth and land-use intensification over the last century have resulted in a substantial increase in nutrient loads degrading marine and freshwater ecosystems worldwide. In mixed-use watersheds, elevated nitrogen loads from wastewater treatment plant (WWTP) effluent or agricultural runoff often drive the eutrophication of waterways. Accordingly, the objective of this research was to identify sources of riverine nitrate (NO₃), a deleterious dissolved species of nitrogen, with a combined isotopic tracing technique in the Bow River and the Oldman River in Alberta, Canada. Riverine NO₃ and boron (B) concentrations, mean daily flux and δ¹⁵N_NO3, δ¹⁸O_NO3, and δ¹¹B values were determined at 17 mainstem sites during high and low discharge periods in 2014 and 2015. The data for mainstem sites were then compared to results for effluent from seven WWTPs, eight synthetic fertilizers, cow manure, and three predominantly agricultural tributary sites to estimate point and non-point NO₃ sources. The NO₃ flux, δ¹⁵N_NO3 and δ¹⁸O_NO3 values indicated the city of Calgary's Bonnybrook WWTP effluent accounts for the majority of the NO₃ flux in the Bow River downstream of Calgary. δ¹⁵N_NO3 and δ¹¹B values in the Bow River highlighted an increase in agricultural NO₃ loading downstream of irrigation return-flows. A three-fold decrease in the NO₃:B flux ratio indicated NO₃-removal processes are active in the lower reaches of the Bow River. For the Oldman River, δ¹¹B values revealed elevated nutrient loading from the Lethbridge WWTP effluent (10% of downstream B flux). Furthermore, the agricultural tributaries contributed 25% of the local B flux to the Oldman River. Overall, δ¹¹B was proven to be an effective co-tracer for discriminating between urban and agricultural sources of NO₃ in these large mixed-use watersheds. This combined isotope tracing approach has significant potential to identify point and non-point NO₃ sources driving eutrophication around the world.

Methane oxidation and methylotroph population dynamics in groundwater mesocosms

Extraction of natural gas from unconventional hydrocarbon reservoirs by hydraulic fracturing raises concerns about methane migration into groundwater. Microbial methane oxidation can be a significant methane sink. Here, we inoculated replicated, sand‐packed, continuous mesocosms with groundwater from a field methane release experiment. The mesocosms experienced thirty‐five weeks of dynamic methane, oxygen and nitrate concentrations. We determined concentrations and stable isotope signatures of methane, carbon dioxide and nitrate and monitored microbial community composition of suspended and attached biomass. Methane oxidation was strictly dependent on oxygen availability and led to enrichment of ¹³C in residual methane. Nitrate did not enhance methane oxidation under oxygen limitation. Methylotrophs persisted for weeks in the absence of methane, making them a powerful marker for active as well as past methane leaks. Thirty‐nine distinct populations of methylotrophic bacteria were observed. Methylotrophs mainly occurred attached to sediment particles. Abundances of methanotrophs and other methylotrophs were roughly similar across all samples, pointing at transfer of metabolites from the former to the latter. Two populations of Gracilibacteria (Candidate Phyla Radiation) displayed successive blooms, potentially triggered by a period of methane famine. This study will guide interpretation of future field studies and provides increased understanding of methylotroph ecophysiology.

Hydro-biogeochemical impacts of fugitive methane on a shallow unconfined aquifer

Oil and gas development can result in natural gas migration into shallow groundwater. Methane (CH₄), the primary component of natural gas, can subsequently react with solutes and minerals in the aquifer to create byproducts that affect groundwater chemistry. Hydro-biogeochemical processes induced by fugitive gas from leaky oil and gas wells are currently not well understood. We monitored the hydro-biogeochemical responses of a controlled natural gas release into a well-studied Pleistocene beach sand aquifer (Canadian Forces Base Borden, Ontario, Canada). Groundwater samples were collected before, during, and up to 700 days after gas injection and analyzed for pH, major and minor ions, alkalinity, dissolved gases, stable carbon isotope ratios of CO₂ and CH₄, and microbial community composition. Gas injection resulted in a dispersed plume of free and dissolved phase natural gas, affecting groundwater chemistry in two distinct temporal phases. Initially (i.e. during and immediately after gas injection), pH declined and major ions and trace elements fluctuated; at times increasing above baseline concentrations. Changes in the short-term were due to invasion of deep groundwater with elevated total dissolved solids entrained with the upward migration of free phase gas and, reactions that were instigated through the introduction of constituents other than CH₄ present in the injected gas (e.g. CO₂). At later times, more pronounced aerobic and anaerobic CH₄ oxidation led to subtle increases in major ions (e.g. Ca²⁺, H₄SiO₄) and trace elements (e.g. As, Cr). Microbial community profiling indicated a persistent perturbation to community composition with a conspicuous ingrowth of taxa implicated in aerobic CH₄ oxidation as well anaerobic S, N and Fe species metabolism.

A Probabilistic Approach for Predicting Methane Occurrence in Groundwater

Aqueous geochemistry datasets from regional groundwater monitoring programs can be a major asset for environmental baseline assessment (EBA) in regions with development of natural gases from unconventional hydrocarbon resources. However, they usually do not include crucial parameters for EBA in areas of shale gas development such as methane concentrations. A logistic regression (LR) model was developed to predict the probability of methane occurrence in aquifers in Alberta (Canada). The model was calibrated and tested using geochemistry data including methane concentrations from two groundwater monitoring programs. The LR model correctly predicts methane occurrence in 89.8% (n = 234 samples) and 88.1% (n = 532 samples) of groundwater samples from each monitoring program. Methane concentrations strongly depend on the occurrence of electron donors such as sulfate and to a lesser extent on well depth and the total dissolved solids of groundwater. The model was then applied to a province-wide public health groundwater monitoring program (n = 52,849 samples) providing aqueous geochemistry data but no methane concentrations. This approach allowed the prediction of methane occurrence in regions where no groundwater gas data are available, thereby increasing the resolution of EBA in areas of shale gas development by using basic hydrochemical parameters measured in high-density groundwater monitoring programs.

A geochemical and multi-isotope modeling approach to determine sources and fate of methane in shallow groundwater above unconventional hydrocarbon reservoirs

Due to increasing concerns over the potential impact of shale gas and coalbed methane (CBM) development on groundwater resources, it has become necessary to develop reliable tools to detect any potential pollution associated with hydrocarbon exploitation from unconventional reservoirs. One of the key concepts for such monitoring approaches is the establishment of a geochemical baseline of the considered groundwater systems. However, the detection of methane is not enough to assess potential impact from CBM and shale gas exploitation since methane in low concentrations has been found to be naturally ubiquitous in many groundwater systems. The objective of this study was to determine the methane sources, the extent of potential methane oxidation, and gas-water-rock-interactions in shallow aquifers by integrating chemical and isotopic monitoring data of dissolved gases and aqueous species into a geochemical PHREEQC model. Using data from a regional groundwater observation network in Alberta (Canada), the model was designed to describe the evolution of the concentrations of methane, sulfate and dissolved inorganic carbon (DIC) as well as their isotopic compositions (δ³⁴S_SO4, δ¹³C_CH4 and δ¹³C_DIC) in groundwater subjected to different scenarios of migration, oxidation and in situ generation of methane. Model results show that methane migration and subsequent methane oxidation in anaerobic environments can strongly affect its concentration and isotopic fingerprint and potentially compromise the accurate identification of the methane source. For example elevated δ¹³C_CH4 values can be the result of oxidation of microbial methane and may be misinterpreted as methane of thermogenic origin. Hence, quantification of the extent of methane oxidation is essential for determining the origin of methane in groundwater. The application of this model to aquifers in Alberta shows that some cases of elevated δ¹³C_CH4 values were due to methane oxidation resulting in pseudo-thermogenic isotopic fingerprints of methane. The model indicated no contamination of shallow aquifers by deep thermogenic methane from conventional and unconventional hydrocarbon reservoirs under baseline conditions. The developed geochemical and multi-isotopic model describing the sources and fate of methane in groundwater is a promising tool for groundwater assessment purposes in areas with shale gas and coalbed methane development.

Using permutational and multivariate statistics to understand inorganic well water chemistry and the occurrence of methane in groundwater, southeastern New Brunswick, Canada

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.

Monitoring concentration and isotopic composition of methane in groundwater in the Utica Shale hydraulic fracturing region of Ohio

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. Graphical abstract A shale gas well in rural Appalachian Ohio. Photo credit: Claire Botner.

High resolution spatial and temporal evolution of dissolved gases in groundwater during a controlled natural gas release experiment

Fugitive gas comprised primarily of methane (CH₄) with traces of ethane and propane (collectively termed C_1-3) may negatively impact shallow groundwater when unintentionally released from oil and natural gas wells. Currently, knowledge of fugitive gas migration, subsurface source identification and oxidation potential in groundwater is limited. To advance understanding, a controlled release experiment was performed at the Borden Research Aquifer, Canada, whereby 51m³ of natural gas was injected into an unconfined sand aquifer over 72days with dissolved gases monitored over 323days. During active gas injection, a dispersed plume of dissolved C_1-3 evolved in a depth discrete and spatially complex manner. Evolution of the dissolved gas plume was driven by free-phase gas migration controlled by small-scale sediment layering and anisotropy. Upon cessation of gas injection, C_1-3 concentrations increased to the greatest levels observed, particularly at 2 and 6m depths, reaching up to 31.5, 1.5 and 0.1mg/L respectively before stabilizing and persisting. At no time did groundwater become fully saturated with natural gas at the scale of sampling undertaken. Throughout the experiment the isotopic composition of injected methane (δ¹³C of -42.2‰) and the wetness parameter (i.e. the ratio of C₁ to C₂₊) constituted excellent tracers for the presence of fugitive gas at concentrations >2mg/L. At discrete times C_1-3 concentrations varied by up to 4 orders of magnitude over 8m of aquifer thickness (e.g. from <0.01 to 30mg/L for CH₄), while some groundwater samples lacked evidence of fugitive gas, despite being within 10m of the injection zone. Meanwhile, carbon isotope ratios of dissolved CH₄ showed no evidence of oxidation. Our results show that while impacts to aquifers from a fugitive gas event are readily detectable at discrete depths, they are spatially and temporally variable and dissolved methane has propensity to persist.

Can groundwater sampling techniques used in monitoring wells influence methane concentrations and isotopes?

Methane concentrations and isotopic composition in groundwater are the focus of a growing number of studies. However, concerns are often expressed regarding the integrity of samples, as methane is very volatile and may partially exsolve during sample lifting in the well and transfer to sampling containers. While issues concerning bottle-filling techniques have already been documented, this paper documents a comparison of methane concentration and isotopic composition obtained with three devices commonly used to retrieve water samples from dedicated observation wells. This work lies within the framework of a larger project carried out in the Saint-Édouard area (southern Québec, Canada), whose objective was to assess the risk to shallow groundwater quality related to potential shale gas exploitation. The selected sampling devices, which were tested on ten wells during three sampling campaigns, consist of an impeller pump, a bladder pump, and disposable sampling bags (HydraSleeve). The sampling bags were used both before and after pumping, to verify the appropriateness of a no-purge approach, compared to the low-flow approach involving pumping until stabilization of field physicochemical parameters. Results show that methane concentrations obtained with the selected sampling techniques are usually similar and that there is no systematic bias related to a specific technique. Nonetheless, concentrations can sometimes vary quite significantly (up to 3.5 times) for a given well and sampling event. Methane isotopic composition obtained with all sampling techniques is very similar, except in some cases where sampling bags were used before pumping (no-purge approach), in wells where multiple groundwater sources enter the borehole.

Hydrocarbon-Rich Groundwater above Shale-Gas Formations: A Karoo Basin Case Study

Horizontal drilling and hydraulic fracturing have enhanced unconventional hydrocarbon recovery but raised environmental concerns related to water quality. Because most basins targeted for shale-gas development in the USA have histories of both active and legacy petroleum extraction, confusion about the hydrogeological context of naturally occurring methane in shallow aquifers overlying shales remains. The Karoo Basin, located in South Africa, provides a near-pristine setting to evaluate these processes, without a history of conventional or unconventional energy extraction. We conducted a comprehensive pre-industrial evaluation of water quality and gas geochemistry in 22 groundwater samples across the Karoo Basin, including dissolved ions, water isotopes, hydrocarbon molecular and isotopic composition, and noble gases. Methane-rich samples were associated with high-salinity, NaCl-type groundwater and elevated levels of ethane, ⁴ He, and other noble gases produced by radioactive decay. This endmember displayed less negative δ¹³ C-CH₄ and evidence of mixing between thermogenic natural gases and hydrogenotrophic methane. Atmospheric noble gases in the methane-rich samples record a history of fractionation during gas-phase migration from source rocks to shallow aquifers. Conversely, methane-poor samples have a paucity of ethane and ⁴ He, near saturation levels of atmospheric noble gases, and more negative δ¹³ C-CH₄ ; methane in these samples is biogenic and produced by a mixture of hydrogenotrophic and acetoclastic sources. These geochemical observations are consistent with other basins targeted for unconventional energy extraction in the USA and contribute to a growing data base of naturally occurring methane in shallow aquifers globally, which provide a framework for evaluating environmental concerns related to unconventional energy development (e.g., stray gas).

Structural and Hydrogeological Controls on Hydrocarbon and Brine Migration into Drinking Water Aquifers in Southern New York

Environmental concerns regarding the potential for drinking water contamination in shallow aquifers have accompanied unconventional energy development in the northern Appalachian Basin. These activities have also raised several critical questions about the hydrogeological parameters that control the naturally occurring presence and migration of hydrocarbon gases in shallow aquifers within petroliferous basins. To interrogate these factors, we analyzed the noble gas, dissolved ion, and hydrocarbon gas (molecular and isotopic composition) geochemistry of 98 groundwater samples from south-central New York. All samples were collected ≫1km from unconventional drilling activities and sample locations were intentionally targeted based on their proximity to various types of documented fault systems. In agreement with studies from other petroliferous basins, our results show significant correlations between elevated levels of radiogenic [⁴ He], thermogenic [CH₄ ], and dissolved ions (e.g., Cl, Br, Sr, Ba). In combination, our data suggest that faults have facilitated the transport of exogenous hydrocarbon-rich brines from Devonian source rocks into overlying Upper Devonian aquifer lithologies over geologic time. These data conflict with previous reports, which conclude that hydrodynamic focusing regulates the occurrence of methane and salt in shallow aquifers and leads to elevated levels of these species in restricted flow zones within valley bottoms. Instead, our data suggest that faults in Paleozoic rocks play a fundamental role in gas and brine transport from depth, regulate the distribution of their occurrence in shallow aquifers, and influence the geochemistry of shallow groundwater in this petroliferous basin.

Numerical Modeling of Methane Leakage from a Faulty Natural Gas Well into Fractured Tight Formations

Horizontal drilling and hydraulic fracturing have enabled hydrocarbon recovery from unconventional reservoirs, but led to natural gas contamination of shallow groundwaters. We describe and apply numerical models of gas-phase migration associated with leaking natural gas wells. Three leakage scenarios are simulated: (1) high-pressure natural gas pulse released into a fractured aquifer; (2) continuous slow leakage into a tilted fractured formation; and (3) continuous slow leakage into an unfractured aquifer with fluvial channels, to facilitate a generalized evaluation of natural gas transport from faulty natural gas wells. High-pressure pulses of gas leakage into sparsely fractured media are needed to produce the extensive and rapid lateral spreading of free gas previously observed in field studies. Transport in fractures explains how methane can travel vastly different distances and directions laterally away from a leaking well, which leads to variable levels of methane contamination in nearby groundwater wells. Lower rates of methane leakage (≤1 Mcf/day) produce shorter length scales of gas transport than determined by the high-pressure scenario or field studies, unless aquifers have low vertical permeabilities (≤1 millidarcy) and fractures and bedding planes have sufficient tilt (∼10°) to allow a lateral buoyancy component. Similarly, in fractured rock aquifers or where permeability is controlled by channelized fluvial deposits, lateral flow is not sufficiently developed to explain fast-developing gas contamination (0-3 months) or large length scales (∼1 km) documented in field studies. Thus, current efforts to evaluate the frequency, mechanism, and impacts of natural gas leakage from faulty natural gas wells likely underestimate contributions from small-volume, low-pressure leakage events.

Fate and Transport of Shale-derived, Biogenic Methane

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 δ¹³C-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 δ¹³C-CH₄ (following glaciation) can complicate fugitive gas interpretations. The sensitivity of the δ¹³C-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.

Controls on Methane Occurrences in Shallow Aquifers Overlying the Haynesville Shale Gas Field, East Texas

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.

Methane Occurrences in Aquifers Overlying the Barnett Shale Play with a Focus on Parker County, Texas

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 km² ) 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 (δ¹³ 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.

Controls on Methane Occurrences in Aquifers Overlying the Eagle Ford Shale Play, South Texas

Assessing natural vs. anthropogenic sources of methane in drinking water aquifers is a critical issue in areas of shale oil and gas production. The objective of this study was to determine controls on methane occurrences in aquifers in the Eagle Ford Shale play footprint. A total of 110 water wells were tested for dissolved light alkanes, isotopes of methane, and major ions, mostly in the eastern section of the play. Multiple aquifers were sampled with approximately 47 samples from the Carrizo-Wilcox Aquifer (250-1200 m depth range) and Queen City-Sparta Aquifer (150-900 m depth range) and 63 samples from other shallow aquifers but mostly from the Catahoula Formation (depth <150 m). Besides three shallow wells with unambiguously microbial methane, only deeper wells show significant dissolved methane (22 samples >1 mg/L, 10 samples >10 mg/L). No dissolved methane samples exhibit thermogenic characteristics that would link them unequivocally to oil and gas sourced from the Eagle Ford Shale. In particular, the well water samples contain very little or no ethane and propane (C1/C2+C3 molar ratio >453), unlike what would be expected in an oil province, but they also display relatively heavier δ¹³ C_methane (>-55‰) and δD_methane (>-180‰). Samples from the deeper Carrizo and Queen City aquifers are consistent with microbial methane sourced from syndepositional organic matter mixed with thermogenic methane input, most likely originating from deeper oil reservoirs and migrating through fault zones. Active oxidation of methane pushes δ¹³ C_methane and δD_methane toward heavier values, whereas the thermogenic gas component is enriched with methane owing to a long migration path resulting in a higher C1/C2+C3 ratio than in the local reservoirs.

Geochemical indicators of the origins and evolution of methane in groundwater: Gippsland Basin, Australia

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 δ¹³C and δ²H values (n = 31) in methane and groundwater from the 46,000-km² 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 δ¹³C_DIC values ranged from -26.4 to -0.4 ‰ and were generally higher in groundwater with high methane concentrations (mean δ¹³C_DIC = -9.5 ‰ for samples with >3 mg/L CH₄ vs. -16.2 ‰ in all others), which is consistent with bacterial methanogenesis. Methane had δ¹³C_CH4 values of -97.5 to -31.8 ‰ and δ²H_CH4 values of -391 to -204 ‰ that were also consistent with bacterial methane, excluding one site with δ¹³C_CH4 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 δ¹³C_CH4 (-83.7 to -97.5 ‰) and δ²H_CH4 (-236 to -391 ‰) values than in the deeper Lower Tertiary Aquifer (δ¹³C_CH4 = -45.8 to -66.2 ‰ and δ²H_CH4 = -204 to -311 ‰). The particularly low δ¹³C_CH4 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.

Anthropogenic and natural methane emissions from a shale gas exploration area of Quebec, Canada

The increasing number of studies on the determination of natural methane in groundwater of shale gas prospection areas offers a unique opportunity for refining the quantification of natural methane emissions. Here methane emissions, computed from four potential sources, are reported for an area of ca. 16,500km(2) of the St. Lawrence Lowlands, Quebec (Canada), where Utica shales are targeted by the petroleum industry. Methane emissions can be caused by 1) groundwater degassing as a result of groundwater abstraction for domestic and municipal uses; 2) groundwater discharge along rivers; 3) migration to the surface by (macro- and micro-) diffuse seepage; 4) degassing of hydraulic fracturing fluids during first phases of drilling. Methane emissions related to groundwater discharge to rivers (2.47×10(-4) to 9.35×10(-3)Tgyr(-1)) surpass those of diffuse seepage (4.13×10(-6) to 7.14×10(-5)Tgyr(-1)) and groundwater abstraction (6.35×10(-6) to 2.49×10(-4)Tgyr(-1)). The methane emission from the degassing of flowback waters during drilling of the Utica shale over a 10- to 20-year horizon is estimated from 2.55×10(-3) to 1.62×10(-2)Tgyr(-1). These emissions are from one third to sixty-six times the methane emissions from groundwater discharge to rivers. This study shows that different methane emission sources need to be considered in environmental assessments of methane exploitation projects to better understand their impacts.

Groundwater methane in relation to oil and gas development and shallow coal seams in the Denver-Julesburg Basin of Colorado

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-km(2) 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.