Carbon sequestration technology requires injection and storage of large volumes of carbon dioxide (CO2) in subsurface geological formations. Shale caprock which constitutes more than 60% of effective seals for geologic hydrocarbon bearing formations are therefore of considerable interest in underground CO2 storage into depleted oil and gas formations. This study investigated experimentally shale caprock's geophysical and geochemical behavior when in contact with aqueous CO2 over a long period of time. The primary concern is a potential increase in hydraulic conductivity of clay-rich rocks as a result of acidic brine-rock minerals geochemical interactions. Both, mineral reactivity and microstructural characteristics, such as presence and development of fracture networks, may lead to potential leakage of CO2 to the surface or underground water sources. Bulk XRD analysis and Transmitted Light Microscopic imaging results acquired on six shale samples showed some heterogeneity in the shale caprock but the mineralogy and particle orientation are similar reflecting the same depositional environment. The XRD analyses indicated the presence of quartz, feldspar, albite, and bulk clays (muscovite, chlorite, and kaolinite). Some micro-heterogeneity in the depositional distribution of the shale minerals was observed. Capillary entry pressure using CO2-brine fluid revealed high seal strength. Nano-pores constituted the controlling pore size but the presence of blind and unconnected micropores might degrade or improve seal capacity in the long term. The geochemical buffer strength of shale appears to be durable. Inductively Coupled Plasma Spectroscopy showed positive mineralogical alterations with slow reactive transport of dissolved CO2 as seal enhancing mechanism supporting predicted simulation studies. Useful geochemical and geophysical data on the regional shale caprock were obtained for coupled predictive modeling of seal integrity in CO2 sequestration.