Repository for Oil and Gas Energy Research (ROGER)

Abstract:
Identifying the geochemical fingerprints of fluids that return to the surface after high volume hydraulic fracturing of unconventional oil and gas reservoirs has important applications for assessing hydrocarbon resource recovery, environmental impacts, and wastewater treatment and disposal. Here, we report for the first time, novel diagnostic elemental and isotopic signatures (B/Cl, Li/Cl, δ11B, and δ7Li) useful for characterizing hydraulic fracturing flowback fluids (HFFF) and distinguishing sources of HFFF in the environment. Data from 39 HFFFs and produced water samples show that B/Cl (>0.001), Li/Cl (>0.002), δ11B (25?31?) and δ7Li (6?10?) compositions of HFFF from the Marcellus and Fayetteville black shale formations were distinct in most cases from produced waters sampled from conventional oil and gas wells. We posit that boron isotope geochemistry can be used to quantify small fractions (?0.1%) of HFFF in contaminated fresh water and likely be applied universally to trace HFFF in other basins. The novel environmental application of this diagnostic isotopic tool is validated by examining the composition of effluent discharge from an oil and gas brine treatment facility in Pennsylvania and an accidental spill site in West Virginia. We hypothesize that the boron and lithium are mobilized from exchangeable sites on clay minerals in the shale formations during the hydraulic fracturing process, resulting in the relative enrichment of boron and lithium in HFFF.

Abstract:
One concern regarding unconventional hydrocarbon production from organic-rich shale is that hydraulic fracture stimulation could create pathways that allow injected fluids and deep brines from the target formation or adjacent units to migrate upward into shallow drinking water aquifers. This study presents Sr isotope and geochemical data from a well-constrained site in Greene County, Pennsylvania, in which samples were collected before and after hydraulic fracturing of the Middle Devonian Marcellus Shale. Results spanning a 15-month period indicated no significant migration of Marcellus-derived fluids into Upper Devonian/Lower Mississippian units located 900-1200 m above the lateral Marcellus boreholes or into groundwater sampled at a spring near the site. Monitoring the Sr isotope ratio of water from legacy oil and gas wells or drinking water wells can provide a sensitive early warning of upward brine migration for many years after well stimulation.

Abstract:
Fossil fuel extraction activities generate wastewaters that are often high in total dissolved solids (TDS) and specific constituents that can affect drinking water, if these wastewaters enter surface waters. Control of TDS in source waters is difficult without identification of the potential sources of high TDS wastewater associated with fossil fuel activities. Characteristics of natural waters, oil and gas-produced waters, and coal-related wastewaters were analyzed to extract information about constituent concentrations and anion ratios. Statistical analysis of the anion ratios indicates that the SO4/Cl ratio is higher in coal-related wastewaters than in oil and gas-produced waters, suggesting that wastewaters can be distinguished based on this ratio. An approach that compared the SO4/Cl ratio with bromide concentration for the wastewaters can serve to separate oil and gas-produced waters from brine treatment plant discharges, and from the various coal-related wastewaters. This method was applied to surface water quality data collected from two tributaries in Southwestern Pennsylvania from September 2009 to September 2012. Results show that this constituent and ratio method, combined with mixing curve calculations, can be used to identify water quality changes in these two tributaries. Similar mixing models, when applied to regionally relevant high TDS wastewater data, may be used in other areas experiencing water quality changes resulting from fossil fuel extraction activities. (C) 2014 American Society of Civil Engineers.

Abstract:
Multiple geographic information system (GIS) datasets, including joint orientations from nine bedrock outcrops, inferred faults, topographic lineaments, geophysical data (e.g. regional gravity, magnetic and stress field), 290 pre-gas-drilling groundwater samples (Cl–Br data) and Appalachian Basin brine (ABB) Cl–Br data, have been integrated to assess pre-gas-drilling salinization sources throughout Susquehanna County, Pennsylvania (USA), a focus area of Marcellus Shale gas development. ABB has migrated naturally and preferentially to shallow aquifers along an inferred normal fault and certain topographic lineaments generally trending NNE–SSW, sub-parallel with the maximum regional horizontal compressive stress field (orientated NE–SW). Gravity and magnetic data provide supporting evidence for the inferred faults and for structural control of the topographic lineaments with dominant ABB shallow groundwater signatures. Significant permeability at depth, imparted by the geologic structures and their orientation to the regional stress field, likely facilitates vertical migration of ABB fluids from depth. ABB is known to currently exist within Ordovician through Devonian stratigraphic units, but likely originates from Upper Silurian strata, suggesting significant migration through geologic time, both vertically and laterally. The natural presence of ABB-impacted shallow groundwater has important implications for differentiating gas-drilling-derived brine contamination, in addition to exposing potential vertical migration pathways for gas-drilling impacts.

Abstract:
The rapid rise in natural gas extraction using hydraulic fracturing increases the potential for contamination of surface and ground water from chemicals used throughout the process. Hundreds of products containing more than 750 chemicals and components are potentially used throughout the extraction process, including more than 100 known or suspected endocrine-disrupting chemicals. We hypothesized that a selected subset of chemicals used in natural gas drilling operations and also surface and ground water samples collected in a drilling-dense region of Garfield County, Colorado, would exhibit estrogen and androgen receptor activities. Water samples were collected, solid-phase extracted, and measured for estrogen and androgen receptor activities using reporter gene assays in human cell lines. Of the 39 unique water samples, 89%, 41%, 12%, and 46% exhibited estrogenic, antiestrogenic, androgenic, and antiandrogenic activities, respectively. Testing of a subset of natural gas drilling chemicals revealed novel antiestrogenic, novel antiandrogenic, and limited estrogenic activities. The Colorado River, the drainage basin for this region, exhibited moderate levels of estrogenic, antiestrogenic, and antiandrogenic activities, suggesting that higher localized activity at sites with known natural gas–related spills surrounding the river might be contributing to the multiple receptor activities observed in this water source. The majority of water samples collected from sites in a drilling-dense region of Colorado exhibited more estrogenic, antiestrogenic, or antiandrogenic activities than reference sites with limited nearby drilling operations. Our data suggest that natural gas drilling operations may result in elevated endocrine-disrupting chemical activity in surface and ground water., AffiliationsDepartment of Obstetrics, Gynecology and Women's Health and Division of Biological Sciences (C.D.K., A.M.H., S.C.N.), University of Missouri, Columbia, Missouri 65211; US Geological Survey (D.E.T.), Columbia Environmental Research Center, Columbia, Missouri 65201; and Departments of Statistics and Health Management and Informatics (J.W.D.), University of Missouri, Columbia, Missouri 65211

Abstract:
Public concerns over potential environmental contamination associated with oil and gas well drilling and fracturing in the Wattenberg field in northeast Colorado are increasing. One of the issues of concern is the migration of oil, gas, or produced water to a groundwater aquifer resulting in contamination of drinking water. Since methane is the major component of natural gas and it can be dissolved and transported with groundwater, stray gas in aquifers has elicited attention. The initial step toward understanding the environmental impacts of oil and gas activities, such as well drilling and fracturing, is to determine the occurrence, where it is and where it came from. In this study, groundwater methane data that has been collected in response to a relatively new regulation in Colorado is analyzed. Dissolved methane was detected in 78% of groundwater wells with an average concentration of 4.0 mg/L and a range of 0?37.1 mg/L. Greater than 95% of the methane found in groundwater wells was classified as having a microbial origin, and there was minimal overlap between the C and H isotopic characterization of the produced gas and dissolved methane measured in the aquifer. Neither density of oil/gas wells nor distance to oil/gas wells had a significant impact on methane concentration suggesting other important factors were influencing methane generation and distribution. Thermogenic methane was detected in two aquifer wells indicating a potential contamination pathway from the producing formation, but microbial-origin gas was by far the predominant source of dissolved methane in the Wattenberg field.

Abstract:
Fluids co-produced with oil and gas production (produced waters) are often brines that contain elevated concentrations of bromide. Bromide is an important precursor of several toxic disinfection by-products (DBPs) and the treatment of produced water may lead to more brominated DBPs. To determine if wastewater treatment plants that accept produced waters discharge greater amounts of brominated DBPs, water samples were collected in Pennsylvania from four sites along a large river including an upstream site, a site below a publicly owned wastewater treatment plant (POTW) outfall (does not accept produced water), a site below an oil and gas commercial wastewater treatment plant (CWT) outfall, and downstream of the POTW and CWT. Of 29 DBPs analyzed, the site at the POTW outfall had the highest number detected (six) ranging in concentration from 0.01 to 0.09 μg L− 1 with a similar mixture of DBPs that have been detected at POTW outfalls elsewhere in the United States. The DBP profile at the CWT outfall was much different, although only two DBPs, dibromochloronitromethane (DBCNM) and chloroform, were detected, DBCNM was found at relatively high concentrations (up to 8.5 μg L− 1). The water at the CWT outfall also had a mixture of inorganic and organic precursors including elevated concentrations of bromide (75 mg L− 1) and other organic DBP precursors (phenol at 15 μg L− 1). To corroborate these DBP results, samples were collected in Pennsylvania from additional POTW and CWT outfalls that accept produced waters. The additional CWT also had high concentrations of DBCNM (3.1 μg L− 1) while the POTWs that accept produced waters had elevated numbers (up to 15) and concentrations of DBPs, especially brominated and iodinated THMs (up to 12 μg L− 1 total THM concentration). Therefore, produced water brines that have been disinfected are potential sources of DBPs along with DBP precursors to streams wherever these wastewaters are discharged.

Abstract:
The safe disposal of liquid wastes associated with oil and gas production in the United States is a major challenge given their large volumes and typically high levels of contaminants. In Pennsylvania, oil and gas wastewater is sometimes treated at brine treatment facilities and discharged to local streams. This study examined the water quality and isotopic compositions of discharged effluents, surface waters, and stream sediments associated with a treatment facility site in western Pennsylvania. The elevated levels of chloride and bromide, combined with the strontium, radium, oxygen, and hydrogen isotopic compositions of the effluents reflect the composition of Marcellus Shale produced waters. The discharge of the effluent from the treatment facility increased downstream concentrations of chloride and bromide above background levels. Barium and radium were substantially (>90%) reduced in the treated effluents compared to concentrations in Marcellus Shale produced waters. Nonetheless, 226Ra levels in stream sediments (544?8759 Bq/kg) at the point of discharge were ?200 times greater than upstream and background sediments (22?44 Bq/kg) and above radioactive waste disposal threshold regulations, posing potential environmental risks of radium bioaccumulation in localized areas of shale gas wastewater disposal.

Abstract:
Natural gas has become a leading source of alternative energy with the advent of techniques to economically extract gas reserves from deep shale formations. Here, we present an assessment of private well water quality in aquifers overlying the Barnett Shale formation of North Texas. We evaluated samples from 100 private drinking water wells using analytical chemistry techniques. Analyses revealed that arsenic, selenium, strontium and total dissolved solids (TDS) exceeded the Environmental Protection Agency?s Drinking Water Maximum Contaminant Limit (MCL) in some samples from private water wells located within 3 km of active natural gas wells. Lower levels of arsenic, selenium, strontium, and barium were detected at reference sites outside the Barnett Shale region as well as sites within the Barnett Shale region located more than 3 km from active natural gas wells. Methanol and ethanol were also detected in 29% of samples. Samples exceeding MCL levels were randomly distributed within areas of active natural gas extraction, and the spatial patterns in our data suggest that elevated constituent levels could be due to a variety of factors including mobilization of natural constituents, hydrogeochemical changes from lowering of the water table, or industrial accidents such as faulty gas well casings.

Abstract:
Gaining streams can provide an integrated signal of relatively large groundwater capture areas. In contrast to the point-specific nature of monitoring wells, gaining streams coalesce multiple flow paths. Impacts on groundwater quality from unconventional gas development may be evaluated at the watershed scale by the sampling of dissolved methane (CH4) along such streams. This paper describes a method for using stream CH4 concentrations, along with measurements of groundwater inflow and gas transfer velocity interpreted by 1-D stream transport modeling, to determine groundwater methane fluxes. While dissolved ionic tracers remain in the stream for long distances, the persistence of methane is not well documented. To test this method and evaluate CH4 persistence in a stream, a combined bromide (Br) and CH4 tracer injection was conducted on Nine-Mile Creek, a gaining stream in a gas development area in central Utah. A 35% gain in streamflow was determined from dilution of the Br tracer. The injected CH4 resulted in a fivefold increase in stream CH4 immediately below the injection site. CH4 and δ13CCH4 sampling showed it was not immediately lost to the atmosphere, but remained in the stream for more than 2000 m. A 1-D stream transport model simulating the decline in CH4 yielded an apparent gas transfer velocity of 4.5 m/d, describing the rate of loss to the atmosphere (possibly including some microbial consumption). The transport model was then calibrated to background stream CH4 in Nine-Mile Creek (prior to CH4 injection) in order to evaluate groundwater CH4 contributions. The total estimated CH4 load discharging to the stream along the study reach was 190 g/d, although using geochemical fingerprinting to determine its source was beyond the scope of the current study. This demonstrates the utility of stream-gas sampling as a reconnaissance tool for evaluating both natural and anthropogenic CH4 leakage from gas reservoirs into groundwater and surface water.

Abstract:
Abstract Exploration of unconventional natural gas reservoirs such as impermeable shale basins through the use of horizontal drilling and hydraulic fracturing has changed the energy landscape in the USA providing a vast new energy source. The accelerated production of natural gas has triggered a debate concerning the safety and possible environmental impacts of these operations. This study investigates one of the critical aspects of the environmental effects; the possible degradation of water quality in shallow aquifers overlying producing shale formations. The geochemistry of domestic groundwater wells was investigated in aquifers overlying the Fayetteville Shale in north-central Arkansas, where approximately 4000 wells have been drilled since 2004 to extract unconventional natural gas. Monitoring was performed on 127 drinking water wells and the geochemistry of major ions, trace metals, CH4 gas content and its C isotopes (δ13CCH4), and select isotope tracers (δ11B, 87Sr/86Sr, δ2H, δ18O, δ13CDIC) compared to the composition of flowback-water samples directly from Fayetteville Shale gas wells. Dissolved CH4 was detected in 63% of the drinking-water wells (32 of 51 samples), but only six wells exceeded concentrations of 0.5 mg CH4/L. The δ13CCH4 of dissolved CH4 ranged from −42.3‰ to −74.7‰, with the most negative values characteristic of a biogenic source also associated with the highest observed CH4 concentrations, with a possible minor contribution of trace amounts of thermogenic CH4. The majority of these values are distinct from the reported thermogenic composition of the Fayetteville Shale gas (δ13CCH4 = −35.4‰ to −41.9‰). Based on major element chemistry, four shallow groundwater types were identified: (1) low (<100 mg/L) total dissolved solids (TDS), (2) TDS > 100 mg/L and Ca–HCO3 dominated, (3) TDS > 100 mg/L and Na–HCO3 dominated, and (4) slightly saline groundwater with TDS > 100 mg/L and Cl > 20 mg/L with elevated Br/Cl ratios (>0.001). The Sr (87Sr/86Sr = 0.7097–0.7166), C (δ13CDIC = −21.3‰ to −4.7‰), and B (δ11B = 3.9–32.9‰) isotopes clearly reflect water–rock interactions within the aquifer rocks, while the stable O and H isotopic composition mimics the local meteoric water composition. Overall, there was a geochemical gradient from low-mineralized recharge water to more evolved Ca–HCO3, and higher-mineralized Na–HCO3 composition generated by a combination of carbonate dissolution, silicate weathering, and reverse base-exchange reactions. The chemical and isotopic compositions of the bulk shallow groundwater samples were distinct from the Na–Cl type Fayetteville flowback/produced waters (TDS ∼10,000–20,000 mg/L). Yet, the high Br/Cl variations in a small subset of saline shallow groundwater suggest that they were derived from dilution of saline water similar to the brine in the Fayetteville Shale. Nonetheless, no spatial relationship was found between CH4 and salinity occurrences in shallow drinking water wells with proximity to shale-gas drilling sites. The integration of multiple geochemical and isotopic proxies shows no direct evidence of contamination in shallow drinking-water aquifers associated with natural gas extraction from the Fayetteville Shale.

Abstract:
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 (δ13C-CH4, δ13C-C2H6, and δ2H-CH4), hydrocarbon ratios (methane to ethane and propane), and the ratio of the noble gas 4He to CH4 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.

Abstract:
Water and gas samples were collected from (1) nine shallow groundwater aquifers overlying Marcellus Shale in north-central West Virginia before active shale gas drilling, (2) wells producing gas from Upper Devonian sands and Middle Devonian Marcellus Shale in southwestern Pennsylvania, (3) coal-mine water discharges in southwestern Pennsylvania, and (4) streams in southwestern Pennsylvania and north-central West Virginia. Our preliminary results demonstrate that the oxygen and hydrogen isotope composition of water, carbon isotope composition of dissolved inorganic carbon, and carbon and hydrogen isotope compositions of methane in Upper Devonian sands and Marcellus Shale are very different compared with shallow groundwater aquifers, coal-mine waters, and stream waters of the region. Therefore, spatiotemporal stable isotope monitoring of the different sources of water before, during, and after hydraulic fracturing can be used to identify migrations of fluids and gas from deep formations that are coincident with shale gas drilling.

Abstract:
Testing of 1701 water wells in northeastern Pennsylvania shows that methane is ubiquitous in groundwater, with higher concentrations observed in valleys vs. upland areas and in association with calcium-sodium-bicarbonate, sodium-bicarbonate, and sodium-chloride rich waters-indicating that, on a regional scale, methane concentrations are best correlated to topographic and hydrogeologic features, rather than shale-gas extraction. In addition, our assessment of isotopic and molecular analyses of hydrocarbon gases in the Dimock Township suggest that gases present in local water wells are most consistent with Middle and Upper Devonian gases sampled in the annular spaces of local gas wells, as opposed to Marcellus Production gas. Combined, these findings suggest that the methane concentrations in Susquehanna County water wells can be explained without the migration of Marcellus shale gas through fractures, an observation that has important implications for understanding the nature of risks associated with shale-gas extraction.

Abstract:
Unconventional natural gas development in Pennsylvania has created a new wastewater stream. In an effort to stop the discharge of Marcellus Shale unconventional natural gas development wastewaters into surface waters, on May 19, 2011 the Pennsylvania Department of Environmental Protection (PADEP) requested drilling companies stop disposing their wastewater through wastewater treatment plants (WWTPs). This research includes a chemical analysis of effluents discharged from three WWTPs before and after the aforementioned request. The WWTPs sampled included two municipal, publicly owned treatment works and a commercially operated industrial wastewater treatment plant. Analyte concentrations were quanitified and then compared to water quality criteria, including U.S. Environmental Protection Agency MCLs and "human health criteria." Certain analytes including barium, strontium, bromides, chlorides, total dissolved solids, and benzene were measured in the effluent at concentrations above criteria. Analyte concentrations measured in effluent samples before and after the PADEP's request were compared for each facility. Analyte concentrations in the effluents decreased in the majority of samples after the PADEP's request (p < .05). This research provides preliminary evidence that these and similar WWTPs may not be able to provide sufficient treatment for this wastewater stream, and more thorough monitoring is recommended.

Abstract:
Silurian and Devonian natural gas reservoirs present within New York state represent an example of unconventional gas accumulations within the northern Appalachian Basin. These unconventional energy resources, previously thought to be noneconomically viable, have come into play following advances in drilling (i.e., horizontal drilling) and extraction (i.e., hydraulic fracturing) capabilities. Therefore, efforts to understand these and other domestic and global natural gas reserves have recently increased. The suspicion of fugitive mass migration issues within current Appalachian production fields has catalyzed the need to develop a greater understanding of the genetic grouping (source) and migrational history of natural gases in this area. We introduce new noble gas data in the context of published hydrocarbon carbon (C1,C2+) (delta13C) data to explore the genesis of thermogenic gases in the Appalachian Basin. This study includes natural gases from two distinct genetic groups: group 1, Upper Devonian (Marcellus shale and Canadaway Group) gases generated in situ, characterized by early mature (Delta13C[C1 minus C2][delta13C1minusdelta13C2]: lt–9permil), isotopically light methane, with low (4He) (average, 1 times 10minus3 cc/cc) elevated 4He/40Arast and 21Neast/40Arast (where the asterisk denotes excess radiogenic or nucleogenic production beyond the atmospheric ratio), and a variable, atmospherically (air-saturated–water) derived noble gas component; and group 2, a migratory natural gas that emanated from Lower Ordovician source rocks (i.e., most likely, Middle Ordovician Trenton or Black River group) that is currently hosted primarily in Lower Silurian sands (i.e., Medina or Clinton group) characterized by isotopically heavy, mature methane (Delta13C[C1 – C2] [delta13C1minusdelta13C2]: gt3permil), with high (4He) (average, 1.85 times 10minus3 cc/cc) 4He/40Arast and 21Neast/40Arast near crustal production levels and elevated crustal noble gas content (enriched 4He, 21Neast, 40Arast). Because the release of each crustal noble gas (i.e., He, Ne, Ar) from mineral grains in the shale matrix is regulated by temperature, natural gases obtain and retain a record of the thermal conditions of the source rock. Therefore, noble gases constitute a valuable technique for distinguishing the genetic source and post-genetic processes of natural gases.

Abstract:
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 CH4 L-1 (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 L-1 (P < 0.05; n = 34). Average δ13C-CH4 values of dissolved methane in shallow groundwater were significantly less negative for active than for nonactive sites (-37 ± 7‰ and -54 ± 11‰, respectively; P < 0.0001). These δ13C-CH4 data, coupled with the ratios of methane-to-higher-chain hydrocarbons, and δ2H-CH4 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.

Abstract:
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 CH4 (0.01–50.55 mol%) with low δ13C–CH4 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 δ13C 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 CH4 to ethane and propane ratios (3–35 mol%; C1/C2 + C3) and high δ13C and δD values of CH4 (−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 CH4 was generated via thermogenic processes. Despite this, the geochemistry of co-produced brines shows evidence for microbial activity. High δ13C values of DIC (>+10‰), slightly elevated alkalinity (up to 12.01 meq/kg) and low SO4 values (<1 mmole/L) in select Devonian organic-rich shale and sandstone formation water samples suggest the presence of methanogenesis, while low δ13C–DIC values (<−22‰) and relatively high SO4 concentrations (up to 12.31 mmole/L) in many brine samples point to SO4 reduction, which likely limits microbial CH4 generation in the Appalachian Basin. Together the formation water and gas results suggest that the vast majority of CH4 in the Devonian organic-rich shales and sandstones across the northern Appalachian Basin margin is thermogenic in origin. Small accumulations of microbial CH4 are present at shallow depths along Lake Erie and in western NY.