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.

Lithium is the principal component of high-energy-density batteries and is a critical material necessary for the economy and security of the United States. Brines from geothermal power production have been identified as a potential domestic source of lithium; however, lithium-rich geothermal brines are characterized by complex chemistry, high salinity, and high temperatures, which pose unique challenges for economic lithium extraction. The purpose of this paper is to examine and analyze direct lithium extraction technology in the context of developing sustainable lithium production from geothermal brines. In this paper, we are focused on the challenges of applying direct lithium extraction technology to geothermal brines; however, applications to other brines (such as coproduced brines from oil wells) are considered. The most technologically advanced approach for direct lithium extraction from geothermal brines is adsorption of lithium using inorganic sorbents. Other separation processes include extraction using solvents, sorption on organic resin and polymer materials, chemical precipitation, and membrane-dependent processes. The Salton Sea geothermal field in California has been identified as the most significant lithium brine resource in the US and past and present efforts to extract lithium and other minerals from Salton Sea brines were evaluated. Extraction of lithium with inorganic molecular sieve ion-exchange sorbents appears to offer the most immediate pathway for the development of economic lithium extraction and recovery from Salton Sea brines. Other promising technologies are still in early development, but may one day offer a second generation of methods for direct, selective lithium extraction. Initial studies have demonstrated that lithium extraction and recovery from geothermal brines are technically feasible, but challenges still remain in developing an economically and environmentally sustainable process at scale.

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.