Biological treatment is effective but infrequently used for oil and gas produced water. To date, physical–chemical treatment methods have been favored due to the smaller space requirements and operational simplicity. Changing regulatory requirements and increased interest in recycling and beneficial reuse have led to increased interest in biological treatment. To elucidate its potential role, we reviewed and summarized 59 studies on the biological treatment of produced water. Oilfield produced water was predominantly studied (> 50%). More studies using real produced water were from China than from any other country (37%). Real produced water was used in most studies (73%). Studies were predominantly bench-scale experiments (69%). Fixed-film reactors were most prevalent (27%). Water quality of produced waters treated was variable; median total dissolved solids (TDS) was 28,000 mg L−1 and median chemical oxygen demand (COD) was 1125 mg L−1. Inhibition by salinity was variable according to the treatment system and study design, but efficacy generally decreased when TDS was above 50,000 mg L−1. For studies treating real samples, average COD removal was 73% when TDS was less than 50,000 mg L−1, and 54% when TDS was greater than 50,000 mg L−1. Key issues were microbial acclimation, toxicity, biological fouling, and mineral scaling. Finding an inoculum was not problematic as microorganisms capable of degrading hydrocarbons were isolated from various environments. Treatment performance was better where synthetic produced water was used in lieu of real samples. Biological treatment is promising for producing effluents suitable for reuse, particularly where it functions as part of a larger treatment train.

Unconventional oil and gas development uses the subsurface injection of large amounts of a variety of industrial chemicals, and there are concerns about the return of these chemical to the surface with water produced with oil and gas from stimulated wells. Produced water, including any flowback of injected fluids, must be managed so as to protect human health and the environment, and understanding the chemistry of produced water from stimulated wells is necessary to ensure the safe management of produced water. In 2014, California instituted mandatory reporting for all well stimulations, including sampling produced water two times and comprehensive chemical characterization of fluids injected and fluids recovered from stimulated wells. In this study, we analyzed data from mandatory reporting with the objective of closing previously identified data gaps concerning oil-field chemical practices and the nature of flowback and produced water from stimulated wells. It was found that the plug-flow conceptual model of flowback developed in shale formations, where salinity increases over time as produced water is extracted, was not appropriate for characterizing produced water from unconventional wells in these oil reservoirs, which are predominately diatomite and sandstones. In these formations stimulation caused a "first-flush" phenomena, where salts and metals were initially high and then decreased in concentration over time, as more produced water was extracted. Although widely applied to meet regulatory requirements, total carbohydrate measurement was not found to be a good chemical indicator of hydraulic fracturing flowback. Mandatory reporting closed data-gaps concerning chemical use, provided new information on acid treatments, and allowed more detailed analysis of hydraulic fracturing practices, including comparison of water use by geological formation.

Produced water is a significant waste stream that can be treated and reused; however, the removal of production chemicals-such as those added in hydraulic fracturing-must be addressed. One motivation for treating and reusing produced water is that current disposal methods-typically consisting of deep well injection and percolation in infiltration pits-are being limited. Furthermore, oil and gas production often occurs in arid regions where there is demand for new water sources. In this paper, hydraulic fracturing chemical additive data from California are used as a case study where physical-chemical and biodegradation data are summarized and used to screen for appropriate produced water treatment technologies. The data indicate that hydraulic fracturing chemicals are largely treatable; however, data are missing for 24 of the 193 chemical additives identified. More than one-third of organic chemicals have data indicating biodegradability, suggesting biological treatment would be effective. Adsorption-based methods and partitioning of chemicals into oil for subsequent separation is expected to be effective for approximately one-third of chemicals. Volatilization-based treatment methods (e.g. air stripping) will only be effective for approximately 10% of chemicals. Reverse osmosis is a good catch-all with over 70% of organic chemicals expected to be removed efficiently. Other technologies such as electrocoagulation and advanced oxidation are promising but lack demonstration. Chemicals of most concern due to prevalence, toxicity, and lack of data include propargyl alcohol, 2-mercaptoethyl alcohol, tetrakis hydroxymethyl-phosphonium sulfate, thioglycolic acid, 2-bromo-3-nitrilopropionamide, formaldehyde polymers, polymers of acrylic acid, quaternary ammonium compounds, and surfactants (e.g. ethoxylated alcohols). Future studies should examine the fate of hydraulic fracturing chemicals in produced water treatment trains to demonstrate removal and clarify interactions between upstream and downstream processes.

High-frequency data and a link-node model were used to investigate the relative importance of mass loads of oxygen-demanding substances and channel geometry on recurrent low dissolved oxygen (DO) in the San Joaquin River Estuary in California. The model was calibrated using 6 years of data. The calibrated model was then used to determine the significance of the following factors on low DO: excavation of the river to allow navigation of large vessels, non-point source pollution from the agricultural watershed, effluent from a wastewater treatment plant, and non-point source pollution from an urban area. An alternative metric for low DO, excess net oxygen demand (ENOD), was applied to better characterize DO impairment. Model results indicate that the dredged ship channel had the most significant effect on DO (62 % fewer predicted hourly DO violations), followed by mass load inputs from the watershed (52 % fewer predicted hourly DO violations). Model results suggest that elimination of any one factor will not completely resolve DO impairment and that continued use of supplemental aeration is warranted. Calculation of ENOD proved more informative than the sole use of DO. Application of the simple model allowed for interpretation of the extensive data collected. The current monitoring program could be enhanced by additional monitoring stations that would provide better volumetric estimates of low DO.

The potential hazards and risks associated with well-stimulation in unconventional oil and gas development (hydraulic fracturing, acid fracturing, and matrix acidizing) have been investigated and evaluated and federal and state regulations requiring chemical disclosure for well-stimulation have been implemented as part of an overall risk management strategy for unconventional oil and gas development. Similar evaluations for chemicals used in other routine oil and gas development activities, such as maintenance acidizing, gravel packing, and well drilling, have not been previously conducted, in part due to a lack of reliable information concerning on-field chemical-use. In this study, we compare chemical-use between routine activities and the more closely regulated well-stimulation activities using data collected by the South Coast Air Quality Monitoring District (SCAQMD), which mandates the reporting of both unconventional and routine on-field chemical-use for parts of Southern California. Analysis of this data shows that there is significant overlap in chemical-use between so-called unconventional activities and routine activities conducted for well maintenance, well-completion, or rework. A comparison within the SCAQMD shows a significant overlap between both types and amounts of chemicals used for well-stimulation treatments included under State mandatory-disclosure regulations and routine treatments that are not included under State regulations. A comparison between SCAQMD chemical-use for routine treatments and state-wide chemical-use for hydraulic fracturing also showed close similarity in chemical-use between activities covered under chemical disclosure requirements (e.g. hydraulic fracturing) and many other oil and gas field activities. The results of this study indicate regulations and risk assessments focused exclusively on chemicals used in well-stimulation activities may underestimate potential hazard or risk from overall oil field chemical-use.

Chemical additives used for hydraulic fracturing and matrix acidizing of oil reservoirs were reviewed and priority chemicals of concern needing further environmental risk assessment, treatment demonstration, or evaluation of occupational hazards were identified. We evaluated chemical additives used for well stimulation in California, the third largest oil producing state in the USA, by the mass and frequency of use, as well as toxicity. The most frequently used chemical additives in oil development were gelling agents, cross-linkers, breakers, clay control agents, iron and scale control agents, corrosion inhibitors, biocides, and various impurities and product stabilizers used as part of commercial mixtures. Hydrochloric and hydrofluoric acids, used for matrix acidizing and other purposes, were reported infrequently. A large number and mass of solvents and surface active agents were used, including quaternary ammonia compounds (QACs) and nonionic surfactants. Acute toxicity was evaluated and many chemicals with low hazard to mammals were identified as potentially hazardous to aquatic environments. Based on an analysis of quantities used, toxicity, and lack of adequate hazard evaluation, QACs, biocides, and corrosion inhibitors were identified as priority chemicals of concern that deserve further investigation.

The energy transition towards a more sustainable and renewable future is a pivotal global endeavor. Central to this shift for the United States is the critical role of domestically sourced lithium, a key mineral in the production of high-performance batteries essential for electric vehicles and renewable energy storage systems. This has driven the United States to invest heavily in a domestic supply chain for battery-grade lithium to enhance energy security, reduce supply chain vulnerabilities, and foster economic growth by tapping into local resources. A notable example is the Biden Administration’s “American Battery Materials Initiative,” which was included in the $2.8-billion Bipartisan Infrastructure Law (The White House, 2022). The “Salton Sea Known Geothermal Resource Area” in Imperial County, California has been identified as a potential domestic U.S. resource of lithium due to the brine-hosted lithium in the deep subsurface geothermal reservoir. An analysis funded by the U.S. Department of Energy provides an overview of opportunities and challenges associated with developing the lithium resource in the Salton Sea geothermal reservoir, as well as potential environmental and societal impacts to the county and surrounding region. The geologic history of the region suggests that lithium in the subsurface brines could have come from multiple sources, including water and sediments from the Colorado River, which have been periodically deposited over the past several million years; rocks from the mountain ranges surrounding the Imperial Valley; and lithium-bearing volcanic rocks and igneous intrusions from past geologic events. Further, several processes may have concentrated lithium in the brine over time, including evaporative concentration of lithium-bearing water that flowed into the basin and leaching of lithium from the sediments and rocks by the circulating geothermal brines. Geothermal brine production at the Salton Sea Geothermal Field, the area with existing geothermal power plants, has averaged just over 120 million metric tons per year since 2004. Using an approximate lithium brine concentration of 198 parts per million (ppm), the amount of dissolved lithium contained in these produced brines is estimated to be 127,000 metric tons of lithium carbonate equivalent (LCE) per year. The total dissolved lithium content in the well-characterized portion of the Salton Sea Geothermal Reservoir is estimated at 4.1 million metric tons of LCE, and the estimated total resource increases to 18 million metric tons of LCE if assumptions for porosity and total reservoir size are increased to reflect the probable resource extent. Analysts measured lithium concentrations in the reservoir rocks, which were shown to vary with depth and mineralogy. These data were used to help refine conceptual and computer models of the reservoir; specifically, two complementary computer models of the reservoir were developed. Analysts used the first model to simulate the approximate 30-year history of geothermal power production in the area using historical production and reinjection data, then used that model to simulate a 30-year forecasting period. This forecast assumed continued production and reinjection rates at current levels but removes 95% of the lithium from the produced geothermal brine starting January 1, 2024. The model found that lithium recovery declines by more than half, from 0.8 to 0.3 kilograms per second (kg/s). Forecast scenarios that are optimized to both recover lithium and harness geothermal energy are expected to sustain lithium production rates much more effectively. The second model included more detailed simulations of the movement of brine and chemical reactivity of lithium within the reservoir. It showed that the reactions of relatively stable lithium-bearing minerals are slow, and that the primary replenishment mechanism for lithium in the brines is the upward flux of convecting lithium-rich brine from below the producing reservoir. However, these replenishment rates are not fast enough to produce significant increases in lithium, which could limit the long-term sustainability of the lithium resource. It is important to note that these models are preliminary and are based on current understanding of fluid replenishment rates, the minerals present in the geothermal system, and their chemical properties and reactivity. Further work should be undertaken to improve them and the associated predictions. The report also considered potential impacts on regional water resources, air quality, chemical use, and solid waste disposal needs, as well as the seismic risk associated with geothermal power production and lithium extraction activity. These investigations highlighted the need to proceed with good monitoring and verification systems and with appropriate mitigation technologies. However, the analysis illustrates that if these things are done properly, lithium development is not likely to create significant negative environmental impacts. Specifically, expanding geothermal energy production and lithium extraction will have a modest impact on water availability in the region. Initial estimates suggested that ~3% of historically available water supply for the region would be needed for currently proposed geothermal energy and lithium recovery operations; the majority of current water usage is for agriculture. It is not anticipated that expanding geothermal capacity or lithium production would impact the availability or quality of water used for human consumption and will not directly affect the water quality of the Salton Sea. However, the long-term drought conditions in the western United States may restrict future availability of water to the region, which is sourced from the Colorado River. In terms of regional air emissions of all pollutants identified in the analysis (particulate matter, hydrogen sulfide, ammonia, and benzene, expanding geothermal energy and adding lithium extraction overall have a small impact. Chemical use involved in geothermal power production and lithium extraction is consistent with chemical use in industrial settings, and the analysis did not identify any persistent organic pollutants or acutely toxic chemicals among those currently being used. Moving fluids within the subsurface can impact subsurface pressures and stresses, potentially triggering seismic activity. Early in geothermal energy production, increasing seismicity rates in the Salton Sea Geothermal Field correlated strongly with energy production activity; however, that correlation weakened after 1996. Even following the onset of geothermal energy production, seismic hazard in the Salton Sea Geothermal Field has not increased beyond that of the surrounding region. In addition to technical outcomes from the analysis, the report describes an initial effort to incorporate community engagement into lithium research by understanding the local context and priorities and identifying how to effectively communicate to share information and gather feedback. The report includes information about the social and historical context of the region to enable a more holistic understanding of the resource and its potential impact, and identifies key community questions by observing public meetings, visiting the region, and consulting with local organizations. The report provides recommendations about how future research efforts can address community concerns and implement more community-engaged practices. These include developing formal partnerships with local organizations and establishing a community advisory board to facilitate ongoing dialogue and opportunities for feedback. The future work will build on and further refine the models and scenarios presented in the report and strive to deepen engagement with local communities.