Occurrence and sources of radium in groundwater associated with oil fields in the southern San Joaquin Valley, California

Author Posting. © American Chemical Society, 2019. This is an open access article published under an ACS AuthorChoice License. The definitive version was published in Environmental Science and Technology 53(16), (2019): 9398-9406, doi:10.1021/acs.est.9b02395.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.This article was improved by the reviews of John Izbicki and anonymous reviewers for the journal. This work was funded by the California State Water Resources Control Board’s Regional Groundwater Monitoring in Areas of Oil and Gas Production Program and the USGS Cooperative Water Program. A.V., A.J.K., and Z.W were supported by USDA-NIFA grant (#2017-68007-26308). Any use of trade, firm, or product names is for description purposes only and does not imply endorsement by the U.S. Government

The Water-Energy Nexus of Hydraulic Fracturing: A Global Hydrologic Analysis for Shale Oil and Gas Extraction

Shale deposits are globally abundant and widespread. Extraction of shale oil and shale gas is generally performed through water-intensive hydraulic fracturing. Despite recent work on its environmental impacts, it remains unclear where and to what extent shale resource extraction could compete with other water needs. Here we consider the global distribution of known shale deposits suitable for oil and gas extraction and develop a water balance model to quantify their impacts on local water availability for other human uses and ecosystem functions. We find that 31–44% of the world's shale deposits are located in areas where water stress would either emerge or be exacerbated as a result of shale oil or gas extraction; 20% of shale deposits are in areas affected by groundwater depletion and 30% in irrigated land. In these regions shale oil and shale gas production would likely compete for local water resources with agriculture, environmental flows, and other water needs. By adopting a hydrologic perspective that considers water availability and demand together, decision makers and local communities can better understand the water and food security implications of shale resource development

Desalination of Shale Gas Wastewater: Thermal and Membrane Applications for Zero-Liquid Discharge

Natural gas exploration from unconventional shale formations, known as “shale gas,” has recently arisen as an appealing energy supply to meet the increasing worldwide demand. During the last decade, development of horizontal drilling and hydraulic fracturing (“fracking”) technologies have allowed the cost-effective gas exploration from previously inaccessible shale deposits. In spite of optimistic expansion projections, natural gas production from tight shale formations has social and environmental implications mainly associated with the depletion of freshwater resources and polluting wastewater generation. In this context, the capability of desalination technologies to allow water recycling and/or water reuse is crucial for the shale gas industry. Advances in zero-liquid discharge (ZLD) desalination processes for treating hypersaline shale gas wastewater can play a key role in the mitigation of public health and environmental impacts, and in the improvement of overall process sustainability. This chapter outlines the most promising thermal- and membrane-based alternatives for ZLD desalination of shale gas wastewater.This project has received funding from the European Union’s Horizon 2020 Research and Innovation Programme under grant agreement No. 640979

Examining the Feasibility of using Coal Mine Drainage as a Hydraulic Fracturing Fluid

Much of the current concern about hydraulic fracturing revolves around the treatment and disposal of wastewaters that come up out of the well after fracturing has occurred. These “produced waters” and “flowback waters” in some cases are high in concentrations of total dissolved solids (TDS), naturally occurring radioactive material (NORM), and metals. There are currently many ways these wastewaters are managed including being recycled on site, treated at commercial waste water treatment plants, or shipped away for storage in federally permitted underground injection wells. This study suggests that by supplementing wastewater with high-sulfate coal mine drainage (CMD), on site recycling can be even more effective through the removal of high metal concentrations and NORM from the wastewater. This could potentially allow for 100% waste water recycling, saving local water resources, while a legacy environmental problem may be remediated. This study was focused on the idea that by mixing coal mine drainage with flowback or produced water, many of the negative characteristics of both fluids can be remediated. The sulfate can be removed from the coal mine drainage, and with it, the barium and radium can be removed from the coal mine drainage. Mix ratios of 1:4, 1:2, and 3:4 were used for this study and in almost every case a majority of the radium (100% for each ratio), barium (75, 90, and 80% respectively), and sulfate (90, 75, and 40% respectively) precipitated out of the mixture. Barium and radium concentrations were found to be strongly correlated within each the sample (r2 of .815). In addition to that, the removal of those solutes was also found to be correlated (r2 of .75). Finally, using spatial analysis and a number of input factors, it was found that on average the use of coal mine drainage is between $30 and$200 thousand more expensive to use per well than fresh water. These results indicate that mixing AMD and flowback water is an effect means of water treatment for re-use as hydraulic fracturing fluid. Although not currently cost effective, the potential to clean up a legacy environmental problem has inspired policy makers to begin the process of making the use of coal mine drainage more cost effective with less legal consequence

Water Footprint of Hydraulic Fracturing

We evaluated the overall water footprint of hydraulic fracturing of unconventional shale gas and oil throughout the United States based on integrated data from multiple database sources. We show that between 2005 and 2014, unconventional shale gas and oil extraction used 708 billion liters and 232 billion liters of water, respectively. From 2012 to 2014, the annual water use rates were 116 billion liters per year for shale gas and 66 billion liters per year for unconventional oil. Integrated data from 6 to 10 years of operation yielded 803 billion liters of combined flowback and produced water from unconventional shale gas and oil formations. While the hydraulic fracturing revolution has increased water use and wastewater production in the United States, its water use and produced water intensity is lower than other energy extraction methods and represents only a fraction of total industrial water use nationwide

Quantification of the water-use reduction associated with the transition from coal to natural gas in the US electricity sector

The transition from coal to natural gas and renewables in the electricity sector and the rise of unconventional shale gas extraction are likely to affect water usage throughout the US. While new natural-gas power plants use less water than coal-fired power plants, shale gas extraction through hydraulic fracturing has increased water utilization and intensity. We integrated water and energy use data to quantify the intensity of water use in the US throughout the electricity’s lifecycle. We show that in spite of the rise of water use for hydraulic fracturing, during 2013–2016 the overall annual water withdrawal (8.74 × 10 ^10 m ^3 ) and consumption (1.75 × 10 ^9 m ^3 ) for coal were larger than those of natural gas (4.55 × 10 ^10 m ^3 , and 1.07 × 10 ^9 m ^3 , respectively). We find that during this period, for every MWh of electricity that has been generated with natural gas instead of coal, there has been a reduction of ∼1 m ^3 in water consumption and ∼40 m ^3 in water withdrawal. Examining plant locations spatially, we find that only a small proportion of net electricity generation takes place in water stressed areas, while a large proportion of both coal (37%) and natural gas (50%) are extracted in water stressed areas. We also show that the growing contribution of renewable energy technologies such as wind and solar will reduce water consumption at an even greater magnitude than the transition from coal to natural gas, eliminating much of water withdrawals and consumption for electricity generation in the US