Methane in groundwater from a leaking gas well, Piceance Basin, Colorado, USA

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.

Commingled Fluids in Abandoned Boreholes: Proximity Analysis of a Hidden Liability

The interactions between old abandoned wellbores of suspect well integrity with hydraulic fracturing (HF), enhanced oil recovery (EOR), or salt water disposal (SWD) operations can result in upward leakage of deep aqueous liquids into overlying aquifers. This potential for upward fluid migration is largely unquantified as monitoring abandoned wells is rarely done, and leakage may go unnoticed especially when in deeper aquifers. This study performs a proximity analysis between old abandoned wells and HF, EOR, and SWD wells, and identifies commingled old abandoned wellbores, which are those wells where groundwater may flow from one aquifer to one or more other aquifers, to identify the locations with the greatest potential for upward aqueous fluid migration at three study sites in the Western Canadian Sedimentary Basin. Our analysis indicates that at all three study sites there are several locations where HF, EOR, or SWD operations are located in close proximity to a given old abandoned well. Much of this overlap occurs in formations above typically produced hydrocarbon reservoirs but below exploited potable aquifers, otherwise known as the intermediate zone, which is often connected between abandonment plugs in old abandoned wells. Information on the intermediate zone is often lacking, and this study suggests that unanticipated alterations to groundwater flow systems within the intermediate zone may be occurring. Results indicate the need for more field-based research on the intermediate zone.

Groundwater Quality of Aquifers Overlying the Oxnard Oil Field, Ventura County, California

Groundwater samples collected from irrigation, monitoring, and municipal supply wells near the Oxnard Oil Field were analyzed for chemical and isotopic tracers to evaluate if thermogenic gas or water from hydrocarbon-bearing formations have mixed with surrounding groundwater. New and historical data show no evidence of water from hydrocarbon-bearing formations in groundwater overlying the field. However, thermogenic gas mixed with microbial methane was detected in 5 wells at concentrations ranging from 0.011-9.1 mg/L. The presence of these gases at concentrations <10 mg/L do not indicate degraded water quality posing a known health risk. Analysis of carbon isotopes (δ¹³C-CH₄) and hydrogen isotopes (δ²H-CH₄) of methane and ratios of methane to heavier hydrocarbon gases were used to differentiate sources of methane between a) microbial, b) thermogenic or c) mixed sources. Results indicate that microbial-sourced methane is widespread in the study area, and concentrations overlap with those from thermogenic sources. The highest concentrations of thermogenic gas were observed in proximity to relatively high density of oil wells, large injection volumes of water disposal and cyclic steam, shallow oil development, and hydrocarbon shows in sediments overlying the producing oil reservoirs. Depths of water wells containing thermogenic gas were within approximately 200 m of the top of the Vaca Tar Sand production zone (approximately 600 m below land surface). Due to the limited sampling density, the source and pathways of thermogenic gas detected in groundwater could not be conclusively determined. Thermogenic gas detected in the absence of co-occurring water from hydrocarbon-bearing formations may result from natural gas migration over geologic time from the Vaca Tar Sand or deeper formations, hydrocarbon shows in sediments overlying producing zones, and/or gas leaking from oil-field infrastructure. Denser sampling of groundwater, potential end-members, and pressure monitoring could help better distinguish pathways of thermogenic gases.

Microbial and Biogeochemical Indicators of Methane in Groundwater Aquifers of the Denver Basin, Colorado

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.

Transport model for shale gas well leakage through the surrounding fractured zones of a longwall mine

The environmental risks associated with casing deformation in unconventional (shale) gas wells positioned in abutment pillars of longwall mines is a concern to many in the mining and gas well industry. With the recent interest in shale exploration and the proximity to longwall mining in Southwestern Pennsylvania, the risk to mine workers could be catastrophic as fractures in surrounding strata create pathways for transport of leaked gases. Hence, this research by the National Institute for Occupational Safety and Health (NIOSH) presents an analytical model of the gas transport through fractures in a low permeable stratum. The derived equations are used to conduct parametric studies of specific transport conditions to understand the influence of stratum geology, fracture lengths, and the leaked gas properties on subsurface transport. The results indicated that the prediction that the subsurface gas flux decreases with an increase in fracture length is specifically for a non-gassy stratum. The sub-transport trend could be significantly impacted by the stratum gas generation rate within specific fracture lengths, which emphasized the importance of the stratum geology. These findings provide new insights for improved understanding of subsurface gas transport to ensure mine safety.

Fluoride occurrence in United States groundwater

Data from 38,105 wells were used to characterize fluoride (F) occurrence in untreated United States (U.S.) groundwater. For domestic wells (n = 11,032), water from which is generally not purposely fluoridated or monitored for quality, 10.9% of the samples have F concentrations >0.7 mg/L (U.S. Public Health Service recommended optimal F concentration in drinking water for preventing tooth decay) (87% are <0.7 mg/L); 2.6% have F > 2 mg/L (EPA Secondary Maximum Contaminant Level, SMCL); and 0.6% have F > 4 mg/L (EPA MCL). The data indicate the biggest concern with F in domestic wells at the national scale could be one of under consumption of F with respect to the oral-health benchmark (0.7 mg/L). Elevated F concentrations relative to the SMCL and MCL are regionally important, particularly in the western U.S. Statistical comparisons of potentially important controlling factors in four F-concentration categories (<0.1-0.7 mg/L; >0.7-2 mg/L; >2-4 mg/L; >4 mg/L) at the national scale indicate the highest F-concentration category is associated with groundwater that has significantly greater pH values, TDS and alkalinity concentrations, and well depths, and lower Ca/Na ratios and mean annual precipitation, than the lowest F-concentration category. The relative importance of the controlling factors appears to be regionally variable. Three case studies illustrate the spatial variability in controlling factors using groundwater-age (groundwater residence time), water-isotope (evaporative concentration), and water-temperature (geothermal processes) data. Populations potentially served by domestic wells with F concentrations <0.7, >0.7, >2, and >4 mg/L are estimated to be ~28,200,000, ~3,110,000; ~522,000; and ~172,000 people, respectively, in 40 principal aquifers with at least 25 F analyses per aquifer.

The Use of Noble Gas Isotopes in Detecting Methane Contamination of Groundwater in Shale Gas Development Areas: An Overview of Technology and Methods

Groundwater contamination by stray gas (mainly methane) in areas of shale-gas development has captured publics, political and scientific attention. However, the sources and potential mechanisms of groundwater contamination are still debated. Noble gases can provide useful information on fluid migration for discerning the scale, conditions, and physical mechanisms. In this study, details about analytical technology and theoretical approach of noble gases in tracing groundwater contaminations are presented. In addition, applications of noble-gases isotopes for determining contamination sources and potential pathways are explored and reviewed. Recent developments are discussed and highlighted with focusing on new utilities of noble-gas isotope parameters in evaluating groundwater contamination. Some usages of indicators (⁴He/²⁰Ne, CH₄/³⁶Ar, ⁴He/CH₄, etc.) are discussed through specific research articles. And it is a new trend to make comprehensive use of multiple geochemical parameters to determine the occurrence, source, and process of methane pollution in groundwater.

Impact of groundwater flow on methane gas migration and retention in unconsolidated aquifers

Methane leaking at depth from hydrocarbon wells poses an environmental and safety hazard. However, determining the occurrence and magnitude of gas migration at ground surface is challenging, as part of the leaking gas is retained during upward migration. We investigated migration through unconsolidated sedimentary aquifers using a two-phase, two-component (water and methane) flow and transport model constructed in DuMu^x. A sensitivity analysis for migration through a 60 m thick sandy aquifer showed that retention by dissolution can be significant even with low groundwater Darcy velocities of 1 m.yr^-1. Retention was negligible in the absence of groundwater flow. Besides groundwater velocity, both hydrogeological (permeability, entry pressure, pore-size distribution, and residual gas saturation) and leakage conditions (depth, magnitude and spatial dimensions) determined model outcomes. Additional simulations with interbedded finer grained sediments resulted in substantial lateral spreading of migrating gas. This delayed upward migration and enhanced retention in overlying sandy units where groundwater velocities are highest. Overall, the results of this study show that for unconsolidated aquifer systems and the most commonly observed leakage rates (0.1-10 m³.d^-1), significant amounts of migrating methane can be retained due to dissolution into laterally flowing groundwater. Consequently, resulting atmospheric methane emissions above such leaks may be delayed with decades after the onset of leakage, significantly reduced, or prevented entirely.

A portrait of wellbore leakage in northeastern British Columbia, Canada

Oil and gas well leakage is of public concern primarily due to the perceived risks of aquifer contamination and greenhouse gas (GHG) emissions. This study examined well leakage data from the British Columbia Oil and Gas Commission (BC OGC) to identify leakage pathways and initially quantify incident rates of leakage and GHG emissions from leaking wells. Three types of leakage are distinguished: "surface casing vent flow" (SCVF), "outside the surface casing leakage" (OSCL), and "cap leakage" (CL). In British Columbia (BC), the majority of reported incidents involve SCVF of gases, which does not pose a risk of aquifer contamination but does contribute to GHG emissions. Reported liquid leakage of brines and hydrocarbons is rarer. OSCL and CL of gas are more serious problems due to the risk of long-term leakage from abandoned wells; some were reported to be leaking gas several decades after they were permanently abandoned. According to the requirements of provincial regulation, 21,525 have been tested for leakage. In total, 2,329 wells in BC have had reported leakage during the lifetime of the well. This represents 10.8% of all wells in the assumed test population. However, it seems likely that wells drilled and/or abandoned before 2010 have unreported leakage. In BC, the total GHG emission from gas SCVF is estimated to reach about 75,000 t/y based on the existing inventory calculation; however, this number is likely higher due to underreporting.

Pollution, management, and mitigation of idle and orphaned oil and gas wells in Alberta, Canada

Alberta has extensive non-renewable energy resources which contribute to the Canadian economy. A downturn in oil and gas energy prices in 2014 contributed to increased idle and orphaned wells, posing potential environmental and human health risks, as well as an economic burden on the province of Alberta. Idle and orphaned wells contribute to local adverse environmental and human health effects from soil and groundwater contamination to greenhouse gas emissions. With increasing numbers of idle and orphaned wells, current monitoring measures, including regulation and cost to identify well leakage, are insufficient. Current policy measures to manage idle and orphaned well environmental liabilities were found to be inadequate to cover cleanup costs. With oil and gas prices showing no signs of rebound, these idle and orphaned well liabilities need to be addressed. This paper discusses potential environmental risks that idle and orphaned oil and gas wells pose, compares Alberta's current monitoring and policy initiatives to those in other provinces as well as the USA, and recommends future management strategies to mitigate the issue.

Occurrence and fate of methane leakage from cut and buried abandoned gas wells in the Netherlands

Methane leakage caused by well integrity failure was assessed at 28 abandoned gas wells and 1 oil well in the Netherlands, which have been plugged, cut and buried to below the ground surface (≥3 mbgl). At each location, methane concentrations were thoroughly scanned at the surface. A static chamber setup was used to measure methane flow rates from the surface as well as from 1 m deep holes drilled using a hand auger. An anomalously high flow rate from 1 m depth combined with isotopic confirmation of a thermogenic origin revealed ongoing leakage at 1 of the 29 wells (3.4%), that had gone undetected by surficial measurements. Gas fluxes at the other sites were due to shallow production of biogenic methane. Detailed investigation at the leaking well (MON-02), consisting of 28 flux measurements conducted in a 2 × 2 m grid from holes drilled to 1 and 2 m depth, showed that flux magnitude was spatially heterogeneous and consistently larger at 2 m depth compared to 1 m. Isotopic evidence revealed oxidation accounted for roughly 25% of the decrease in flux towards the surface. The estimated total flux from the well (443 g CH₄ hr^-1) was calculated by extrapolation of the individual flow rate measurements at 2 m depth and should be considered an indicative value as the validity of the estimate using our approach requires confirmation by modelling and/or experimental studies. Together, our findings show that total methane emissions from leaking gas wells in the Netherlands are likely negligible compared to other sources of anthropogenic methane emissions (e.g. <1% of emissions from the Dutch energy sector). Furthermore, subsurface measurements greatly improve the likelihood of detecting leakage at buried abandoned wells and are therefore essential to accurately assess their greenhouse gas emissions and explosion hazards.

Identification, spatial extent and distribution of fugitive gas migration on the well pad scale

Global methane (CH₄) emissions are becoming increasingly important due to the contribution of CH₄ to global warming. Leaking oil and gas wells can lead to subsurface CH₄ gas migration (GM), which can cause both aquifer contamination and atmospheric emissions. Despite the need to identify and quantify GM at oil and gas well pads, effective and reliable monitoring techniques are lacking. In this field study, we used CH₄ and carbon dioxide (CO₂) efflux measurements together with soil gas stable carbon isotopic signatures to identify the occurrence and to characterize the spatio-temporal migration of fugitive gas across 17 selected well pads in Northeastern British Columbia, Canada. At 13 of these sites, operators had previously reported the occurrence of GM; however, subsequent inspections based on visual, olfactory or auditory evidence only identified GM at two of these sites. Using the soil gas efflux method, evidence for GM was found at 15 of the 17 well pads with CH₄ and CO₂ effluxes ranging from 0.017 to 180μmolm^-2s^-1(0.024 to 250gCH₄m^-2d^-1) and 0.50 to 32μmolm^-2s^-1 (1.9 to 122gCO₂m^-2d^-1), respectively. Stable carbon isotopic composition was assessed at 10 of the 17 well pads with 9 well pads showing evidence of GM. The isotopic values indicated that CH₄ in soil gas was from the same origin as CH₄ in the surface casing vent flow gas. There was no correlation between CH₄ effluxes and the distance from the well head; an equal portion of elevated effluxes were detected >10m from the well head as were detected <5m from the well head. In addition, CH₄ effluxes varied temporally with values changing by up to an order of magnitude over 2h. Although the study was carried out in Northeastern British Columbia, the results are applicable on a global scale, suggesting that inspections mostly based on visual evidence (e.g. bubbling at the well head) are not reliable for the identification of GM and, that infrequent survey measurements at predefined locations close to the well head may overestimate, underestimate or even miss CH₄ effluxes. Repetitive and relatively densely spaced gas efflux measurements using a dynamic closed chamber method proved to be a useful tool for detecting GM.