Studies of chemical composition of natural brines from rock formations in the Illinois Basin as part of the University of Illinois deep direct-use feasibility study.

Thermal property data for rocks and and minerals and unconsolidated (glacial) sediments units from within and outside the Illinois Basin were compiled for modeling heat transport in the subsurface.

This submission includes 3-D geocellular model files with formation top and formation thickness data for the St. Peter and Mt. Simon Sandstones in University of Illinois Deep Direct-Use project area. An input parameters file is also included for the St. Peter Sandstone.

These studies undertook detailed analyses of the Mt. Simon Sandstone in the Illinois Basin for geological storage and sequestration, and brine extraction.

Bedrock Geology of Champaign County, Illinois, map layers (shapefiles). Layers included: 1) Champaign County bedrock units. 2) Champaign County bedrock surface contours. Contour interval of 25 feet. 3) Colchester coal surface contours. Contour interval of 50 feet. 4) Kimmswick Limestone top contours, in the Mahomet dome area. Contour interval of 20 feet. 5) New Albany shale base contour. Contour interval of 100 feet.

Includes specification sheet, wellbore geometry, and drilling fluids at section target depth associated with the design of Injection Well #1 (CCS1) for the Illinois Basin Decatur Project (IBDP).

We developed a methodology to estimate maximum brine injection rates in subsurface formations across wide geographic areas using inverse modeling-based optimization techniques. We first defined geographic areas where groundwater was too saline to meet the standard for drinking water and where sufficient confining units existed above and below the injection layers. We then assumed concurrent brine injection into a system of wells on a consistent 25 km x 25 km spacing across the entire modeled area. Taking advantage of symmetry, we represented each 25 km x 25 km injection area as a 12.5 km-long one-dimensional radial model, divided into 100 logarithmically-sized grid blocks. A single layer of grid blocks was used because homogenous porous media were assumed. Brine injection was simulated into the leftmost (innner) grid block, and the injection rate was automatically adjusted to meet a maximum pressure buildup to 80% of the fracturing pressure, estimated as the least principal stress, at the injection location. A secondary constraint of 1 bar maximum pressure increase at the right-most (far-field boundary) grid block after 50 years of injection was applied. We demonstrated this method on three stratigraphic layers that overlie the Mt. Simon Sandstone (MSS) in the Illinois Basin, as well as in the MSS itself, because the MSS is a well-known CO2 injection target with a large estimated CO2 storage capacity. CO2 storage in the MSS could be optimized by extracting brine from that formation and injecting it elsewhere, so the brine injection rates estimated with the models contained herein could help to refine CO2 storage capacity estimates.

These brine samples are collected from the Soda Geyser (a thermal feature, temperature ~30 C) in Soda Springs, Idaho. These samples also represent the overthrust brines typical of oil and gas plays in western Wyoming. Samples were collected from the source and along the flow channel at different distances from the source. By collecting and analyzing these samples we are able to increase the density and quality of data from the western Wyoming oil and gas plays. Furthermore, the sampling approach also helped determine the systematic variation in REE concentration with the sampling distance from the source. Several geochemical processes are at work along the flow channels, such as degassing, precipitation, sorption, etc.

This dataset contains geochemical analyses of produced fluids from the Utah FORGE site, specifically from wells 16A(78)-32, 16B(78)-32, and 58-32, collected during various stimulation, flowback, and circulation tests conducted between 2022 and 2024. The data contains element concentrations, pH, and dissolved gas compositions. Geochemical analyses for 2022 and 2023 were performed at the Brigham Young University geochemistry laboratory, while the 2024 results were obtained from Thermochem. Dry gas samples were collected using a mini-separator attached to the single-phase production line between the wellhead and separator, where fluid was flashed to atmospheric pressure. Gas concentrations were recalculated to a single phase reservoir liquid based on heat and mass balance expressions. Additional contextual information, including interpretations of geochemical trends and reservoir behavior, is available in the included report from Simmons et al. (2025), which was presented at the Stanford Geothermal Workshop in February 2025.