## 1 Introduction
### Shale Interactions (Multi-Mineral)
[PERSON] et al. [50] also found that decreases in the micropore surface area and volume after exposure to CO\({}_{2}\) indicated possible alterations of the permeability and the fracture network. [PERSON] et al. [13] conducted experiments in which shale rock was also exposed to wet CO\({}_{2}\). Autoclave vessels were used to treat the samples with either dry scCO\({}_{2}\) or a mixture of CO\({}_{2}\) and water. For both types of treatment, the vessels were held at 40 \({}^{\circ}\)C and 10.3 MPa for 14 days. In the mixture treatment, samples were submerged in 100 mL of ultrapure water. A water-only treatment was also performed for comparison. [PERSON] et al. [13] found that the addition of water acted as a blocking agent between the CO\({}_{2}\) and the sample. Interactions were no longer direct, but were primarily due to the dissolved CO\({}_{2}\) lowering the pH level of the water layer. This was indicated by the presence of an absorption band centred at 2342 cm\({}^{-1}\) in the FTIR spectrum. In general, the presence of water acted to exacerbate effects seen previously by [PERSON] et al. [48]. FE-SEM showed increased signs of etching and pitting in the calcite matrix, with calcite precipitation. Redistribution of calcite can occur when it has been dissolved and then transported within the aqueous phase. Adsorption experiments showed a further decreasing trend for the BET surface area, micropore surface area, and volume, between approximately 0.9 and 2 nm. However, the volume of mesopores increased due to carbonate dissolution. More recent work by [PERSON] et al. [25] examined how fluids interact in the natural fractures and matrix pores of Utica shale. Two samples were tested; one from an outcrop in New York state and the other from a natural gas production zone in Eastern Ohio (from a depth of 3259 m). Both shale samples were largely inorganic carbonate, but the 'production' shale had c. 5% TOC. Several characterisation techniques were used to study the shales both before and after treatment. These included field emission-scanning electron microscopy  
Figure 3: Comparing CO\({}_{2}\) adsorption isotherms for the US-1 shale sample to the various clay (mixed layer illite-smectite (ISCz-1), illite (IMt-2), chlorite (CCA-2), and kaolinite (KGa-1b)) and kerogen (NAk-1) components typically found in shale. Note that data for NAK-1 and CCA-2 were collected gravimetrically using a microbalance at \(-200\)\({}^{\circ}\)C. The remaining samples are measured at \(-25\)\({}^{\circ}\)C using a volumetric Sievert apparatus. Reprinted from [PERSON] et al. [50]. Copyright (2018), with permission from Elsevier. (FE-SEM), CO\({}_{2}\) and N\({}_{2}\) sorption isotherms, mercury intrusion porosimetry, and small-angle X-ray scattering (SAXS) methods. The results showed pores both opening at the microscale and closing at the nanoscale, depending on their pore type and size classification. Etching and pitting were seen in FE-SEM results following both dry and wet CO\({}_{2}\) treatments. [PERSON] et al. [25] found changes at the micropore scale due to carbonate dissolution and precipitation. An analysis of the region of pores with sizes between 1000 nm and 15,000 nm showed that their porosity increased from 1.8% to 7.6% following treatment with dry CO\({}_{2}\), and up to 33% following treatment with wet CO\({}_{2}\). These changes were associated with both intraparticle and interparticle pores within the mineral matter and natural fractures as carbonate was dissolved. Pore volumes and pore size distributions in the shale were examined following treatment using a combination of CO\({}_{2}\) and N\({}_{2}\) sorption isotherms, as well as mercury intrusion porosimetry. Other metrics, such as bulk density, apparent density, and BET surface area, were also calculated. The sorption methods used were in the same way as described earlier for [PERSON] et al. [50].