In order to reduce greenhouse gas emissions while recovering hydrocarbons from unconventional shale formations, processes that make use of carbon dioxide to enhance oil recovery while storing carbon dioxide (CO2) should be considered. Here, we examine samples from three shale basins across the United States (Utica and Marcellus Shales in the Appalachian Basin, Barnett Shale in the Bend Arch-Ft. Worth Basin, and Eagle Ford in the Western Gulf Basin) to address the following questions: (1) do changes from reaction with CO2 and fluids at the micrometer and nanometer scale alter flow pathways and, in turn, impact hydrocarbon production, CO2 storage, and seal integrity and (2) can CO2 or fluid reactivity be predicted based on physical or chemical properties of shale formations? Experiments were conducted at 40 °C and 10.3 MPa to characterize the interaction between CO2 and shale using X-ray diffraction (XRD), carbon and sulfur analysis, in situ Fourier transform infrared spectroscopy (FT-IR), feature relocation scanning electron microscopy coupled with energy-dispersive spectroscopy (SEM-EDS), mercury (Hg) intrusion porosimetry, and Brunauer–Emmett–Teller (BET) surface area and pore size analysis coupled with density functional theory (DFT) methods. Changes in mechanical, physical, and flow properties of shale cores due to CO2 exposure were addressed using a New England Research Autolab 1500 and Xenon X-ray computed tomography (CT) scanning. Results showed that CO2 did not promote significant reactivity with the shale if water was not present; only shales with swelling clays or residual interstitial pore water reacted with dry CO2 to promote reactivity in shale. When water was added as a reactant, CO2 formed carbonic acid and reacted with the shale to dissolve carbonate pockets, etched and pitted the shale matrix surfaces, and increased the microporosity and decreased nanoporosity. Porosity and permeability increased appreciably in core shale samples after exposure to CO2 saturated fluid due to dissolution of carbonate. Shale mechanical properties were not altered. Trends were not observed that could tie CO2 or fluid reactivity to physical or chemical properties of the shale formations at the basin scale from the samples we examined. However, if the shale contained significant amounts of carbonate and water was available to react with the CO2, pore sizes were altered in the matrix and permeability and porosity increased.
As demand increases for an affordable energy source that is tied to an environmental obligation to reduce greenhouse gas emissions and water usage, there is a growing consideration in shale production utilizing processes such as (1) enhancing hydrocarbon recovery via carbon dioxide (CO2) flooding, (2) using CO2 as a fracturing agent to minimize water use, and (3) storing CO2 in depleted shale formations to mitigate emissions to the atmosphere. Understanding the geochemical reactions and alterations that occur as shale is exposed to fluids and CO2 is necessary to develop and optimize each of these processes for field applications. Although the majority of shale formations are stimulated using a traditional fracturing fluid, some may be fractured using CO2 or other nontraditional means. We examine the effect the fracturing fluid has on shale and how it behaves with secondary exposure to dry CO2 or CO2-saturated water using in situ Fourier transform infrared (FTIR) spectroscopy, feature relocation scanning electron microscopy (SEM), and surface area and pore size analysis using volumetric gas sorption. These techniques were performed on Eagle Ford and Barnett shale samples that were exposed to the fracturing fluid and unexposed (as received). Shales that have been exposed to the traditional fracturing fluid experienced two reaction fronts. The first reaction front was formed during exposure to the fracturing fluid (pH of ∼1.4). A secondary reaction front was formed as a result of CO2-saturated fluid exposure in the form of carbonic acid (pH ∼ 5.6). These two different reaction mechanisms drove multiple dissolution and precipitation cycles which altered petrophysical properties of the shale and could lead to a significant impact on flow pathways. FTIR spectroscopy showed that equilibration of carbonate dissolution and precipitation cycles could take as long as 35 days. Samples exposed to the fracturing fluid showed significantly less carbonate reactivity compared to those exposed to water. Pore size analysis results indicate that exposure to the fracturing fluid blocked small nanopores (0.7–10 nm) reducing BET surface area and total pore volume. SEM results show barite precipitated heavily during exposure to the fracturing fluid. It appeared that carbonic acid was able to extract sulfur from organic matter to form gypsum evaporites. The mineralogical (barite precipitation and calcite dissolution/precipitation) and pore-scale alterations observed in these samples may lead to enhancement of flow pathways for injected CO2 or produced hydrocarbons.
Abstract Decarbonatization initiatives have rapidly increased the demand for lithium. This study uses public waste compliance reports and Monte Carlo approaches to estimate total lithium mass yields from produced water (PW) sourced from the Marcellus Shale in Pennsylvania (PA). Statewide, Marcellus Shale PW has substantial extractable lithium, however, concentrations, production volumes and extraction efficiencies vary between the northeast and southwest operating zones. Annual estimates suggest statewide lithium mass yields of approximately 1,159 (95% CI: 1139–1178) metric tons per year. Production decline curve analysis on PW volumes reveal cumulative volumetric disparities between the northeast (median = 2.89 X 10 7 L/10-yr) and southwest (median = 5.56 x 10 7 L/10-yr) regions of the state, influencing estimates for ultimate lithium yields from wells in southwest [2.90 (95% CI: 2.80–2.99) mt/ 10-yr] and northeast [1.96 (CI: 1.86–2.07) mt/10-yr] PA. Moreover, Mg/Li mass ratios vary regionally, where NE PA are low Mg/Li fluids, having a median Mg/Li mass ratio of 5.39 (IQR, 2.66–7.26) and SW PA PW is higher with a median Mg/Li mass ratio of 17.8 (IQR, 14.3–20.7). These estimates indicate lithium mass yields from Marcellus PW are substantial, though regional variability in chemistry and production may impact recovery efficiencies.
