Geology topics

Jessica Chenault

Publications and source records attributed to Jessica Chenault.

8 recordsLinked to original sources

USGS2026

Geochemical geodatabase of sedimentary strata (coal, coal-adjacent rocks, tuffaceous oil shale, phosphate-rich rocks) and produced water in the Uinta region, Utah and Colorado

The Geochemical Geodatabase of Sedimentary Strata (Coal, Coal-adjacent Rocks, Tuffaceous Oil Shale, Phosphate-rich Rocks) and Produced Water in the Uinta Region, Utah and Colorado, consists of compiled datasets acquired as part of the Carbon Ore, Rare Earth, and Critical Mineral (CORE-CM) Uinta Region assessment funded by the U.S. Department of Energy (DEFE0032046, 2021–2024; Birgenheier et al., 2024). The CORE-CM assessment focused on providing comprehensive geological and geochemical characterization of current and prospective sedimentary-hosted resources including coal, oil shale, phosphatic limestone, and produced water from oil and gas targets present in eastern Utah and northwestern Colorado (Figure 1). This Data Series includes a geodatabase that consists of analytical geochemical data collected September 2021 through December 2024 via portable X-ray fluorescence (pXRF), and laboratory measured analyses produced by inductively coupled plasma mass spectrometry (ICP-MS) and inductively coupled plasma optical emission spectroscopy (ICP-OES). The coal-related geochemical data are derived primarily from the Cretaceous Blackhawk Formation and Ferron Sandstone of Utah, and the Mesaverde Group of Colorado. Additional non-coal resources assessed include oil shale-bearing strata of the Eocene upper Green River Formation (Utah and Colorado), phosphate-rich limestone of the Permian Park City Formation (Utah) and produced water from oil and gas-bearing strata of the Eocene Green River and Wasatch Formations (Uinta Basin) and the Pennsylvanian Paradox Formation (Paradox Basin) (Table 1). The CORE-CM assessment included a wide range of lithologies present in the coal, oil shale, and phosphate geologic resource systems whether or not the specific lithology has current economic value. Geochemical analyses of produced water from oil and gas wells focused on current and emerging hydrocarbon targets in the central Uinta Basin and northern Paradox Basin. A total of 13,092 geochemical analyses from these geologic systems is provided in the included geodatabase. A series of coal quality data (e.g., composition and maceral analyses) is also included in the database and was digitized from archived coal samples from the Utah Geological Survey (Appendix A).

Colorado, Utah↗

USGS2026

Lithium brine potential of North Dakota: Results from the 2025 sampling program

Lithium (Li), classified as a critical mineral and key in energy storage applications because of its high energy density, faces unprecedented demand. This has driven interest in unconventional sources of Li, especially brines from sedimentary basins. Accordingly, the spatial distribution of basinal brinehosted Li resources across North America is becoming better defined, including the Williston Basin underlying Saskatchewan, Canada. This has led to growing investment and exploration by industry throughout the 2020s; however, despite this interest, the Li potential of basinal brines of the Williston Basin in North Dakota remain underexplored. This work presents the results from the 2025 joint brine sampling campaign between the North Dakota Geological Survey, the United States Geological Survey (USGS), and The University of Texas at Austin. Twenty-seven fluid samples were collected from producing oil and water source wells from eight stratigraphic intervals across western North Dakota and analyzed for major cation and anion concentrations. Similar to southeastern Saskatchewan, the highest Li concentrations were identified in the Devonian Duperow Formation, with concentrations up to 179 mg/L being observed in a well commingled between the Duperow and Red River Formations. Some samples from the overlying Birdbear Formation exceeded 75 mg/L, whereas Li concentrations were lower in the Madison Group (33-44 mg/L) and the Three Forks (50 mg/L), Dawson Bay (43 mg/L), Winnipegosis (23 mg/L), and Red River (40.0 mg/L) Formations. This work indicates Li resource potential exists across the Williston Basin and advances our understanding of the Li distribution in basinal brines which could provide a new domestic source of this critical mineral.

North Dakota↗

USGS2024

Lithium resource in the Smackover Formation brines of Southern Arkansas

Lithium-rich brine deposits occur throughout the United States, including in the Smackover Formation. The concentration of lithium in Smackover Formation brines was predicted across southern Arkansas by using a machine-learning model that incorporated lithium concentration data and geologic information. Between 5.1 and 19.0 million metric tons of lithium are calculated to be present in the brines of the Smackover Formation in southern Arkansas. The range in possible total lithium reflects the uncertainty in machine-learning predictions of lithium concentrations and the range of Smackover Formation porosity. This estimate quantifies the in-place lithium resource and does not consider the technological and economic feasibility of extracting the lithium from the brines.

Arkansas↗

USGS2024

Produced water geochemistry from hydraulically stimulated Niobrara Formation petroleum wells: Origin of salinity and temporal perspectives on treatment and reuse

Produced water (i.e., a mixture of returned injection fluids and geologic formation brines) represents the largest volumetric waste stream associated with petroleum production in the United States. As such, produced water has been the focus of intense study with emphasis on understanding the geologic origin of the fluids, environmental impacts of unintended or intentional release, disposal concerns, and their commodity (e.g., lithium) potential. However, produced water geochemistry from many active petroleum plays remain poorly constrained leading to knowledge gaps associated with the origin of brine salinity and parameters (e.g., radium levels) that can impact treatment, disposal, and possible reuse. Here we evaluate the major ion geochemistry, radium concentrations, and stable water isotope composition of ~120 produced water samples collected from 17 producing unconventional petroleum wells in Weld County, Colorado from the Late Cretaceous Niobrara Formation. This sample set encompasses eight produced water time series from four new wells across production days 0 to ~365 and from four established wells across production days ~1000 to ~1700. Additionally, produced water from nine other established Niobrara Formation wells were sampled at discrete time points ranging from day 458 to day 2256, as well as hydraulic fracturing input fluids. These results expand the available Niobrara Formation produced water geochemical data, previously limited to few wells sampled within the first year of production, allowing for the heterogeneity of major ions and radium to be evaluated. Furthermore, we explore the geochemical relationships between major ion ratios and stable water isotope composition to understand the origin of salinity in Niobrara Formation brines from the Denver-Julesburg Basin. These findings are discussed with perspective toward potential treatment and reuse of Niobrara produced water prior to disposal.

Colorado, Nebraska, Wyoming↗

USGS2024

Evaluation of the lithium resource in the Smackover Formation brines of southern Arkansas using machine learning

Global demand for lithium, the primary component of lithium-ion batteries, greatly exceeds known supplies, and this imbalance is expected to increase as the world transitions away from fossil fuel energy sources. High concentrations of lithium in brines have been observed in the Smackover Formation in southern Arkansas (>400 milligrams per liter). We used published and newly collected brine lithium concentration data to train a random forest machine-learning model using geologic, geochemical, and temperature explanatory variables and create a map of predicted lithium concentrations in Smackover Formation brines across southern Arkansas. Using these predicted lithium maps with reservoir parameters and geologic information, we calculated that there are 5.1 to 19 million tons of lithium in Smackover Formation brines in southern Arkansas, which represents 35 to 136% of the current US lithium resource estimate. Based on these calculations, in 2022, 5000 tons of dissolved lithium were brought to the surface within brines as waste streams of the oil, gas, and bromine industries.

Arkansas↗

USGS2020

Utica shale play oil and gas brines: Geochemistry and factors influencing wastewater management

The Utica and Marcellus Shale Plays in the Appalachian Basin are the fourth and first largest natural gas producing plays in the United States, respectively. Hydrocarbon production generates large volumes of brine (“produced water”) that must be disposed of, treated, or reused. Though Marcellus brines have been studied extensively, there are few studies from the Utica Shale Play. This study presents new brine chemical analyses from 16 Utica Shale Play wells in Ohio and Pennsylvania. Results from Na–Cl–Br systematics and stable and radiogenic isotopes suggest that the Utica Shale Play brines are likely residual pore water concentrated beyond halite saturation during the formation of the Ordovician Beekmantown evaporative sequence. The narrow range of chemistry for the Utica Shale Play produced waters (e.g., total dissolved solids = 214–283 g/L) over both time and space implies a consistent composition for disposal and reuse planning. The amount of salt produced annually from the Utica Shale Play is equivalent to 3.4% of the annual U.S. halite production. Utica Shale Play brines have radium activities 580 times the EPA maximum contaminant level and are supersaturated with respect to barite, indicating the potential for surface and aqueous radium hazards if not properly disposed of.

Kentucky, Maryland, New York, Ohio, Pennsylvania, ↗

USGS2020

Direct trace element determination in oil and gas produced waters with inductively coupled plasma - Optical emission spectrometry (ICP-OES): Advantages of high salinity tolerance

Waters co-produced during petroleum extraction are the largest waste stream from oil and gas development. Reuse or disposal of these waters is difficult due to their high salinities and the sheer volumes generated. Produced waters may also contain valuable mineral commodities. While an understanding of produced water trace element composition is required for evaluating the associated resource and waste potential of these materials, measuring trace elements in brines is challenging due to the dilution requirements of typical methods. Alternatively, inductively coupled plasma-optical emission spectrometry (ICP-OES) has shown promise as being capable of direct measurements of trace elements within produced waters with minimal dilution. Here we evaluate direct ICP-OES trace element quantification in produced waters for 17 trace elements (As, Al, Ba, Be, Cd, Cr, Co, Cu, Hg, Mo, Ni, Pb, Rb, Sb, U, V, and Zn) within 15 produced waters from five U.S. continuous reservoirs. The ICP-OES results are compared against trace element levels determined using inductively coupled plasma-mass spectrometry from the same samples. Our results demonstrate the potential for direct analysis of high salinity waters using ICP-OES with minimal dilution and provide trace element concentrations in waters from several important U.S. petroleum-generating reservoirs where available data is sparse.

Montana, New York, North Dakota, Ohio, Pennsylvani↗

USGS2020

Origin and geochemistry of formation waters from the lower Eagle Ford Group, Gulf Coast Basin, south central Texas

The lower Eagle Ford Group (LEFG) is one of the most productive continuous hydrocarbon plays in the United States but few associated produced waters data and minimal interpretation have been published. This effort focuses on results from compositional and isotopic data from 39 produced water samples collected from horizontal wells producing from the LEFG in south central Texas. The depth of the LEFG increases by approximately 1 km across the study area, from northwest (2.9 km) to southeast (3.9 km). Associated increases in calculated reservoir temperature (125-165 C), development of reservoir over-pressuring (400-800 bars total pressure), and increased thermal maturity (heavy oil to gas condensate) also occur along this trend. Produced water salinity starts at nearly 100 g/L in the shallowest samples and decreases linearly with depth to <35 g/L. Comparison of Br/Cl and ⁸⁷Sr/⁸⁶Sr data between LEFG produced waters and the Louann salt, suggests that halite recycling is the mechanism behind salinity greater than seawater. Decreasing salinity with depth and thermal maturity in the Gulf Coast Basin have previously been shown to be a result of release of inter-layer water during smectite to illite conversion. The produced water samples show increasing 18O and decreasing 2H with depth, which is attributed temperature-dependent isotope fractionation of O and H exchange between seawater and clays and calcite with increasing temperature. Multiple sources of data indicate that the waters in the LEFG are not connate, but rather entered the unit prior to smectite-illite conversion. Presence of allochthonous water in many major tight oil and shale gas plays in the U.S., including the LEFG, suggests there is unknown mechanism allowing for water advection into low permeability reservoirs.

Texas↗