Directional drilling and hydraulic-fracturing technologies are dramatically increasing natural-gas extraction. In aquifers overlying the Marcellus and Utica shale formations of northeastern ...Pennsylvania and upstate New York, we document systematic evidence for methane contamination of drinking water associated with shale-gas extraction. In active gas-extraction areas (one or more gas wells within 1 km), average and maximum methane concentrations in drinking-water wells increased with proximity to the nearest gas well and were 19.2 and 64 mg CHâ Lâ»Â¹ (n = 26), a potential explosion hazard; in contrast, dissolved methane samples in neighboring nonextraction sites (no gas wells within 1 km) within similar geologic formations and hydrogeologic regimes averaged only 1.1 mg Lâ»Â¹ (P < 0.05; n = 34). Average δ¹³C-CHâ values of dissolved methane in shallow groundwater were significantly less negative for active than for nonactive sites (-37 ± 7per thousand and -54 ± 11per thousand, respectively; P < 0.0001). These δ¹³C-CHâ data, coupled with the ratios of methane-to-higher-chain hydrocarbons, and δ²H-CHâ values, are consistent with deeper thermogenic methane sources such as the Marcellus and Utica shales at the active sites and matched gas geochemistry from gas wells nearby. In contrast, lower-concentration samples from shallow groundwater at nonactive sites had isotopic signatures reflecting a more biogenic or mixed biogenic/thermogenic methane source. We found no evidence for contamination of drinking-water samples with deep saline brines or fracturing fluids. We conclude that greater stewardship, data, and--possibly--regulation are needed to ensure the sustainable future of shale-gas extraction and to improve public confidence in its use.
Horizontal drilling and hydraulic fracturing are transforming energy production, but their potential environmental effects remain controversial. We analyzed 141 drinking water wells across the ...Appalachian Plateaus physiographic province of northeastern Pennsylvania, examining natural gas concentrations and isotopic signatures with proximity to shale gas wells. Methane was detected in 82% of drinking water samples, with average concentrations six times higher for homes <1 km from natural gas wells (P = 0.0006). Ethane was 23 times higher in homes <1 km from gas wells (P = 0.0013); propane was detected in 10 water wells, all within approximately 1 km distance (P = 0.01). Of three factors previously proposed to influence gas concentrations in shallow groundwater (distances to gas wells, valley bottoms, and the Appalachian Structural Front, a proxy for tectonic deformation), distance to gas wells was highly significant for methane concentrations (P = 0.007; multiple regression), whereas distances to valley bottoms and the Appalachian Structural Front were not significant (P = 0.27 and P = 0.11, respectively). Distance to gas wells was also the most significant factor for Pearson and Spearman correlation analyses (P < 0.01). For ethane concentrations, distance to gas wells was the only statistically significant factor (P < 0.005). Isotopic signatures (δ ¹³C-CH ₄, δ ¹³C-C ₂H ₆, and δ ²H-CH ₄), hydrocarbon ratios (methane to ethane and propane), and the ratio of the noble gas ⁴He to CH ₄ in groundwater were characteristic of a thermally postmature Marcellus-like source in some cases. Overall, our data suggest that some homeowners living <1 km from gas wells have drinking water contaminated with stray gases.
The debate surrounding the safety of shale gas development in the Appalachian Basin has generated increased awareness of drinking water quality in rural communities. Concerns include the potential ...for migration of stray gas, metal-rich formation brines, and hydraulic fracturing and/or flowback fluids to drinking water aquifers. A critical question common to these environmental risks is the hydraulic connectivity between the shale gas formations and the overlying shallow drinking water aquifers. We present geochemical evidence from northeastern Pennsylvania showing that pathways, unrelated to recent drilling activities, exist in some locations between deep underlying formations and shallow drinking water aquifers. Integration of chemical data (Br, Cl, Na, Ba, Sr, and Li) and isotopic ratios (⁸⁷Sr/ ⁸⁶Sr, ²H/H, ¹⁸O/ ¹⁶O, and ²²⁸Ra/ ²²⁶Ra) from this and previous studies in 426 shallow groundwater samples and 83 northern Appalachian brine samples suggest that mixing relationships between shallow ground water and a deep formation brine causes groundwater salinization in some locations. The strong geochemical fingerprint in the salinized (Cl > 20 mg/L) groundwater sampled from the Alluvium, Catskill, and Lock Haven aquifers suggests possible migration of Marcellus brine through naturally occurring pathways. The occurrences of saline water do not correlate with the location of shale-gas wells and are consistent with reported data before rapid shale-gas development in the region; however, the presence of these fluids suggests conductive pathways and specific geostructural and/or hydrodynamic regimes in northeastern Pennsylvania that are at increased risk for contamination of shallow drinking water resources, particularly by fugitive gases, because of natural hydraulic connections to deeper formations.
In this study, the geochemistry and origin of natural gas and formation waters in Devonian age organic-rich shales and reservoir sandstones across the northern Appalachian Basin margin (western New ...York, eastern Ohio, northwestern Pennsylvania, and eastern Kentucky) were investigated. Additional samples were collected from Mississippian Berea Sandstone, Silurian Medina Sandstone and Ordovician Trenton/Black River Group oil and gas wells for comparison. Dissolved gases in shallow groundwaters in Devonian organic-rich shales along Lake Erie contain detectable CH
4 (0.01–50.55
mol%) with low δ
13C–CH
4 values (−74.68 to −57.86‰) and no higher chain hydrocarbons, characteristics typical of microbial gas. Nevertheless, these groundwaters have only moderate alkalinity (1.14–8.72
meq/kg) and relatively low δ
13C values of dissolved inorganic C (DIC) (−24.8 to −0.6‰), suggesting that microbial methanogenesis is limited. The majority of natural gases in Devonian organic-rich shales and sandstones at depth (>168
m) in the northern Appalachian Basin have a low CH
4 to ethane and propane ratios (3–35
mol%; C
1/C
2
+
C
3) and high δ
13C and δD values of CH
4 (−53.35 to −40.24‰, and −315.0 to −174.6‰, respectively), which increase in depth, reservoir age and thermal maturity; the molecular and isotopic signature of these gases show that CH
4 was generated via thermogenic processes. Despite this, the geochemistry of co-produced brines shows evidence for microbial activity. High δ
13C values of DIC (>+10‰), slightly elevated alkalinity (up to 12.01
meq/kg) and low SO
4 values (<1 mmole/L) in select Devonian organic-rich shale and sandstone formation water samples suggest the presence of methanogenesis, while low δ
13C–DIC values (<−22‰) and relatively high SO
4 concentrations (up to 12.31 mmole/L) in many brine samples point to SO
4 reduction, which likely limits microbial CH
4 generation in the Appalachian Basin. Together the formation water and gas results suggest that the vast majority of CH
4 in the Devonian organic-rich shales and sandstones across the northern Appalachian Basin margin is thermogenic in origin. Small accumulations of microbial CH
4 are present at shallow depths along Lake Erie and in western NY.
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.
Natural gas reservoirs in organic-rich shales in the Appalachian and Michigan basins in the United States are currently being produced via hydraulic fracturing. Stratigraphically-equivalent shales ...occur in the Canadian portion of the basins in southwestern Ontario with anecdotal evidence of gas shows, yet there has been no commercial shale gas production to date. To provide baseline data in the case of future environmental issues related to hydraulic fracturing and shale gas production, such as leakage of natural gas, saline water, and/or hydraulic fracturing fluids, and to evaluate hydrogeochemical controls on natural gas accumulations in shallow groundwater in general, this study investigates the origin and distribution of natural gas and brine in shallow aquifers across southwestern Ontario. An extensive geochemical database of major ion and trace metal chemistry and methane concentrations of 1010 groundwater samples from shallow, domestic wells in bedrock and overburden aquifers throughout southwestern Ontario was utilized. In addition, select wells (n = 36) were resampled for detailed dissolved gas composition, delta super(13)C of CH sub(4), C sub(2), C sub(3), and CO sub(2), and delta D of CH sub(4). Dissolved gases in groundwater from bedrock and overburden wells were composed primarily of CH sub(4) (29.7-98.6 mol% of total gas volume), N sub(2) (0.8-66.2 mol%), Ar + O sub(2) (0.2-3.4 mol%), and CO sub(2) (0-1.2 mol%). Ethane was detected, but only in low concentrations (<0.041 mol%), and no other higher chain hydrocarbons were present, except for one well in overburden overlying the Dundee Formation, which contained 0.81 mol% ethane and 0.21 mol% propane. The highest methane concentrations (30 to >100 in situ % saturation) were found in bedrock wells completed in the Upper Devonian Kettle Point Formation, Middle Devonian Hamilton Group and Dundee Formation, and in surficial aquifers overlying these organic-rich shale-bearing formations, indicating that bedrock geology is the primary control on methane occurrences. A few (n = 40) samples showed Na-Cl-Br evidence of brine mixing with dilute groundwater, however only one of these samples contained high (>60 in situ % saturation) CH sub(4). The relatively low delta super(13)C values of CH sub(4) (-89.9ppt to -57.3ppt), covariance of delta D values of CH sub(4) and H sub(2)O, positive correlation between delta super(13)C values of CH sub(4) and CO sub(2), and lack of higher chain hydrocarbons (C sub(3+)) in all but one dissolved gas sample indicates that the methane in groundwater throughout the study area is primarily microbial in origin. The presence or absence of alternative electron acceptors (e.g. dissolved oxygen, Fe, NO sub(3), SO sub(4)), in addition to organic substrates, controls the occurrence of microbial CH sub(4) in shallow aquifers. Microbial methane has likely been accumulating in the study area, since at least the Late Pleistocene to the present, as indicated by the co-variance and range of delta D values of CH sub(4) (-314ppt to -263ppt) and associated groundwater (-19ppt to -6ppt delta D-H sub(2)O).
Baseline groundwater geochemical mapping of inorganic and isotopic parameters across 44,000 km
2
of southwestern Ontario (Canada) has delineated a discreet zone of natural gas in the bedrock aquifer ...coincident with an 8,000-km
2
exposure of Middle Devonian shale. This study describes the ambient geochemical conditions in these shales in the context of other strata, including Ordovician shales, and discusses shale-related natural and anthropogenic processes contributing to hydrogeochemical conditions in the aquifer. The three Devonian shales—the Kettle Point Formation (Antrim equivalent), Hamilton Group and Marcellus Formation—have higher DOC, DIC, HCO
3
, CO
2(aq)
, pH and iodide, and much higher CH
4(aq).
The two Ordovician shales—the Queenston and Georgian-Bay/Blue Mountain Formations—are higher in Ca, Mg, SO
4
and H
2
S. In the Devonian shale region, isotopic zones of Pleistocene-aged groundwater have halved in size since first identified in the 1980s; potentiometric data implicate regional groundwater extraction in the shrinkage. Isotopically younger waters invading the aquifer show rapid increases in CH
4(aq)
, pH and iodide with depth and rapid decrease in oxidized carbon species including CO
2
, HCO
3
and DIC, suggesting contemporary methanogenesis. Pumping in the Devonian shale contact aquifer may stimulate methanogenesis by lowering TDS, removing products and replacing reactants, including bicarbonate, derived from overlying glacial sedimentary aquifers.
We developed a screening framework for identifying organic components of hydraulic fracturing fluid with increased probability of exposure via groundwater based on mobility, persistence, toxicity, ...and frequency of use. Of 996 organic fracturing fluid compounds identified by the U.S. Environmental Protection Agency and FracFocus for four states, data were available to perform an initial screening of 659 compounds for sufficient mobility and persistence to reach a water well under fast and slow groundwater transport scenarios. For the fast transport scenario, 15 compounds identified on at least 50 FracFocus reports were predicted to have an elevated exposure potential, which was defined as ≥10% of the initial concentration remaining at a transport distance of 94 m, the average setback distance in the United States. Of these 15 compounds, two were identified on >20% of FracFocus reports (naphthalene and 2-butoxyethanol), four were compounds identified on >5% of reports, and three had health-based standards.
Mutations in the biosynthesis or signaling pathways of gibberellin (GA) can cause dwarfing phenotypes in plants, and the use of such mutations in plant breeding was a major factor in the success of ...the Green Revolution. DELLA proteins are GA signaling repressors whose functions are conserved in different plant species. Recent studies show that GA promotes stem growth by causing degradation of DELLA proteins via the ubiquitin-proteasome pathway. The most widely utilized dwarfing alleles in wheat (Triticum aestivum; e.g. Rht-B1b and Rht-D1b) encode GA-resistant forms of a DELLA protein that function as dominant and constitutively active repressors of stem growth. All of the previously identified dominant DELLA repressors from several plant species contain N-terminal mutations. Here we report on a novel dwarf mutant from Brassica rapa (Brrga1-d) that is caused by substitution of a conserved amino acid in the C-terminal domain of a DELLA protein. Brrga1-d, like N-terminal DELLA mutants, retains its repressor function and accumulates to high levels, even in the presence of GA. However, unlike wild-type and N-terminal DELLA mutants, Brrga1-d does not interact with a protein component required for degradation, suggesting that the mutated amino acid causes dwarfism by preventing an interaction needed for its degradation. This novel mutation confers nondeleterious dwarf phenotypes when transferred to Arabidopsis (Arabidopsis thaliana) and oilseed rape (Brassica napus), indicating its potential usefulness in other crop species.
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