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 CO(2 )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 similar to 1.4). A secondary reaction front was formed as a result of CO2-saturated fluid exposure in the form of carbonic acid (pH similar to 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 porescale alterations observed in these samples may lead to enhancement of flow pathways for injected CO2 or produced hydrocarbons.