Hydrocarbons in Upland Groundwater, Marcellus Shale Region, Northeastern Pennsylvania and Southern New York, U.S.A.

Water samples from 50 domestic wells located <1 km (proximal) and >1 km (distal) from shale-gas wells in upland areas of the Marcellus Shale region were analyzed for chemical, isotopic, and groundwater-age tracers. Uplands were targeted because natural mixing with brine and hydrocarbons from deep formations is less common in those areas compared to valleys. CH4-isotope, predrill CH4-concentration, and other data indicate that one proximal sample (5% of proximal samples) contains thermogenic CH4 (2.6 mg/L) from a relatively shallow source (Catskill/Lock Haven Formations) that appears to have been mobilized by shale-gas production activities. Another proximal sample contains five other volatile hydrocarbons (0.03-0.4 µg/L), including benzene, more hydrocarbons than in any other sample. Modeled groundwater-age distributions, calibrated to 3H, SF6, and 14C concentrations, indicate that water in that sample recharged prior to shale-gas development, suggesting that land-surface releases associated with shale-gas production were not the source of those hydrocarbons, although subsurface leakage from a nearby gas well directly into the groundwater cannot be ruled out. Age distributions in the samples span ∼20 to >10000 years and have implications for relating occurrences of hydrocarbons in groundwater to land-surface releases associated with recent shale-gas production and for the time required to flush contaminants from the system.

Occurrence and Sources of Radium in Groundwater Associated with Oil Fields in the Southern San Joaquin Valley, California.

Geochemical data from 40 water wells were used to examine the occurrence and sources of radium (Ra) in groundwater associated with three oil fields in California (Fruitvale, Lost Hills, South Belridge). 226Ra+228Ra activities (range = 0.010-0.51 Bq/L) exceeded the 0.185 Bq/L drinking-water standard in 18% of the wells (not drinking-water wells). Radium activities were correlated with TDS concentrations (p < 0.001, ρ = 0.90, range = 145-15,900 mg/L), Mn + Fe concentrations (p < 0.001, ρ = 0.82, range = <0.005-18.5 mg/L), and pH (p < 0.001, ρ = -0.67, range = 6.2-9.2), indicating Ra in groundwater was influenced by salinity, redox, and pH. Ra-rich groundwater was mixed with up to 45% oil-field water at some locations, primarily infiltrating through unlined disposal ponds, based on Cl, Li, noble-gas, and other data. Yet 228Ra/226Ra ratios in pond-impacted groundwater (median = 3.1) differed from those in oil-field water (median = 0.51). PHREEQC mixing calculations and spatial geochemical variations suggest that the Ra in the oil-field water was removed by coprecipitation with secondary barite and adsorption on Mn-Fe precipitates in the near-pond environment. The saline, organic-rich oil-field water subsequently mobilized Ra from downgradient aquifer sediments via Ra-desorption and Mn/Fe-reduction processes. This study demonstrates that infiltration of oil-field water may leach Ra into groundwater by changing salinity and redox conditions in the subsurface rather than by mixing with a high-Ra source.

Evidence for high salinity of Early Cretaceous sea water from the Chesapeake Bay crater.

High-salinity groundwater more than 1,000 metres deep in the Atlantic coastal plain of the USA has been documented in several locations, most recently within the 35-million-year-old Chesapeake Bay impact crater. Suggestions for the origin of increased salinity in the crater have included evaporite dissolution, osmosis and evaporation from heating associated with the bolide impact. Here we present chemical, isotopic and physical evidence that together indicate that groundwater in the Chesapeake crater is remnant Early Cretaceous North Atlantic (ECNA) sea water. We find that the sea water is probably 100-145 million years old and that it has an average salinity of about 70 per mil, which is twice that of modern sea water and consistent with the nearly closed ECNA basin. Previous evidence for temperature and salinity levels of ancient oceans have been estimated indirectly from geochemical, isotopic and palaeontological analyses of solid materials in deep sediment cores. In contrast, our study identifies ancient sea water in situ and provides a direct estimate of its age and salinity. Moreover, we suggest that it is likely that remnants of ECNA sea water persist in deep sediments at many locations along the Atlantic margin.

Methane and Benzene in Drinking-Water Wells Overlying the Eagle Ford, Fayetteville, and Haynesville Shale Hydrocarbon Production Areas.

Water wells (n = 116) overlying the Eagle Ford, Fayetteville, and Haynesville Shale hydrocarbon production areas were sampled for chemical, isotopic, and groundwater-age tracers to investigate the occurrence and sources of selected hydrocarbons in groundwater. Methane isotopes and hydrocarbon gas compositions indicate most of the methane in the wells was biogenic and produced by the CO2 reduction pathway, not from thermogenic shale gas. Two samples contained methane from the fermentation pathway that could be associated with hydrocarbon degradation based on their co-occurrence with hydrocarbons such as ethylbenzene and butane. Benzene was detected at low concentrations (<0.15 µg/L), but relatively high frequencies (2.4-13.3% of samples), in the study areas. Eight of nine samples containing benzene had groundwater ages >2500 years, indicating the benzene was from subsurface sources such as natural hydrocarbon migration or leaking hydrocarbon wells. One sample contained benzene that could be from a surface release associated with hydrocarbon production activities based on its age (10 ± 2.4 years) and proximity to hydrocarbon wells. Groundwater travel times inferred from the age-data indicate decades or longer may be needed to fully assess the effects of potential subsurface and surface releases of hydrocarbons on the wells.

Groundwater ages and mixing in the Piceance Basin natural gas province, Colorado.

Reliably identifying the effects of energy development on groundwater quality can be difficult because baseline assessments of water quality completed before the onset of energy development are rare and because interactions between hydrocarbon reservoirs and aquifers can be complex, involving both natural and human processes. Groundwater age and mixing data can strengthen interpretations of monitoring data from those areas by providing better understanding of the groundwater flow systems. Chemical, isotopic, and age tracers were used to characterize groundwater ages and mixing with deeper saline water in three areas of the Piceance Basin natural gas province. The data revealed a complex array of groundwater ages (<10 to >50,000 years) and mixing patterns in the basin that helped explain concentrations and sources of methane in groundwater. Age and mixing data also can strengthen the design of monitoring programs by providing information on time scales at which water quality changes in aquifers might be expected to occur. This information could be used to establish maximum allowable distances of monitoring wells from energy development activity and the appropriate duration of monitoring.

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.

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

Site-specific and regional analysis of time-series hydrologic and geochemical data collected from 15 monitoring wells in the Piceance Basin indicated that a leaking gas well contaminated shallow groundwater with thermogenic methane. The gas well was drilled in 1956 and plugged and abandoned in 1990. Chemical and isotopic data showed the thermogenic methane was not from mixing of gas-rich formation water with shallow groundwater or natural migration of a free-gas phase. Water-level and methane-isotopic data, and video logs from a deep monitoring well, indicated that a shale confining layer ~125m below the zone of contamination was an effective barrier to upward migration of water and gas. The gas well, located 27m from the contaminated monitoring well, had ~1000m of uncemented annular space behind production casing that was the likely pathway through which deep gas migrated into the shallow aquifer. Measurements of soil gas near the gas well showed no evidence of methane emissions from the soil to the atmosphere even though methane concentrations in shallow groundwater (16 to 20mg/L) were above air-saturation levels. Methane degassing from the water table was likely oxidized in the relatively thick unsaturated zone (~18m), thus rendering the leak undetectable at land surface. Drilling and plugging records for oil and gas wells in Colorado and proxies for depth to groundwater indicated thousands of oil and gas wells were drilled and plugged in the same timeframe as the implicated gas well, and the majority of those wells were in areas with relatively large depths to groundwater. This study represents one of the few detailed subsurface investigations of methane leakage from a plugged and abandoned gas well. As such, it could provide a useful template for prioritizing and assessing potentially leaking wells, particularly in cases where the leakage does not manifest itself at land surface.

Ground water discharge and nitrate flux to the Gulf of Mexico.

Ground water samples (37 to 186 m depth) from Baldwin County, Alabama, are used to define the hydrogeology of Gulf coastal aquifers and calculate the subsurface discharge of nutrients to the Gulf of Mexico. The ground water flow and nitrate flux have been determined by linking ground water concentrations to 3H/3He and 4He age dates. The middle aquifer (A2) is an active flow system characterized by postnuclear tritium levels, moderate vertical velocities, and high nitrate concentrations. Ground water discharge could be an unaccounted source for nutrients in the coastal oceans. The aquifers annually discharge 1.1 +/- 0.01 x 10(8) moles of nitrate to the Gulf of Mexico, or 50% and 0.8% of the annual contributions from the Mobile-Alabama River System and the Mississippi River System, respectively. In southern Baldwin County, south of Loxley, increasing reliance on ground water in the deeper A3 aquifer requires accurate estimates of safe ground water withdrawal. This aquifer, partially confined by Pliocene clay above and Pensacola Clay below, is tritium dead and contains elevated 4He concentrations with no nitrate and estimated ground water ages from 100 to 7000 years. The isotopic composition and concentration of natural gas diffusing from the Pensacola Clay into the A3 aquifer aids in defining the deep ground water discharge. The highest 4He and CH4 concentrations are found only in the deepest sample (Gulf State Park), indicating that ground water flow into the Gulf of Mexico suppresses the natural gas plume. Using the shape of the CH4-He plume and the accumulation of 4He rate (2.2 +/- 0.8 microcc/kg/1000 years), we estimate the natural submarine discharge and the replenishment rate for the A3 aquifer.