A key feature of unconventional shale reservoirs is low permeability. On average, only 10% of original oil in place and 25% of original gas in place is produced from these reservoirs. Understanding the mechanisms behind fracture conductivity past the first couple of years of shale production is still an ongoing research topic, as most such reservoirs report fast and massive production declines. Hydraulic fracturing is indispensable for stimulating low-permeability rocks for economical oil and gas production from unconventional reservoir rocks such as shales. In contrast, for subsurface sequestration and storage of fluids including supercritical CO2 (for carbon capture, utilization, and storage) and hydrogen gas, inadvertent creation of fractures can lead to breaching of shale caprock. The Caney Shale in southern Oklahoma is being evaluated as both a potential hydrocarbon-producing reservoir and a caprock for fluid sequestration. The Caney Shale is a Mississippian-age, organic-rich mudrock with intermittent calcareous laminae, that produces. But currently there is limited data reported regarding productivity of horizontally drilled wellbores. While many scholars have investigated fracture conductivity in shale reservoirs, the mechanisms of proppant embedment in relation to lithology are still under investigation. This study implemented a multi-scale approach towards investigating proppant embedment and fracture conductivity, from nano-scale instrumented micro/nano-indentation to millimeter (mm) scale, mono-layer propped fracture flow at reservoir temperature and pressure, and American Petroleum Institute (API)-RP19D conductivity tests using inch/cm-scale shale platens. At each scale, various material characterization tools were utilized, including Focused Ion Beam-Scanning Electron Microscopy (FIB-SEM), Energy Dispersive Spectroscopy (EDS), Raman spectroscopy, Laser profilometry, Computed X-ray Microscopy and X-ray Diffraction (XRD). The outcomes of the micro-indentation revealed variations in mechanical properties attributed to changing mineral composition and microstructures. Outcomes from API fracture conductivity testing and flow-through testing using a monolayer of proppant demonstrated: (1) a 50% impact on proppant embedment compared to ductile samples, (2) a significant decline in fracture conductivity with increasing stress and temperatures, and (3) conductivity that was also influenced by organic and inorganic content as well as internal sample architecture. Mineralogically, ductile samples contain about 25% more clay minerals compared to brittle regions. Heterogeneity in mineral composition causes the Caney Shale to show different responses at reservoir temperature and pressure, particularly in relation to creep and proppant embedment. Geomechanical and fluid-flow modeling have been conducted at several scales to help interpret laboratory results and apply findings to field-scale operation. The outcomes from this integration should aid geological and engineering predictions for the hydrocarbon production and caprock integrity of the Caney Shale.