Abstract: The key factors controlling the densification of unconventional reservoirs (e.g., tight oil and gas reservoirs) remain poorly understood and directly affect the distribution of exploitable resources. Here, systematically explored reservoir characteristics, depositional microfacies, and the main factors controlling densification of the tight oil reservoir in the Chang 8 Member (Yanchang Formation, Middle Triassic) in the Zhenjing area of the southern Ordos Basin by thin section analysis, scanning electron microscopy, physical property measurement, X-ray diffraction, and mercury injection. Our results confirm the Chang 8 reservoir as an extremely low permeability tight sandstone reservoir mainly comprising lithic feldspathic sandstone with various primary and secondary pores and fine pore channels. The highest quality reservoir is mainly restricted to the middle and lower parts of subaqueous distributary channel microfacies. Dissolution partly contributed to reservoir formation, but the persistence of early, non-compressed storage space was more important. The compression of plastic rock debris removed a significant amount of porosity, and calcite and kaolinite both fill pores and contribute to the structural strength of pore space. We identified three densification processes: the persistent densification of highly plastic rocks, calcite cementation, and feldspar dissolution and subsequent kaolinite precipitation. After their compaction, the Chang 8 Member reservoirs were charged with hydrocarbons. We applied clustering analysis to eight reservoir characteristics (porosity, permeability, median pore-throat radius, maximum pore-throat radius, median capillary pressure, pore discharge pressure, chlorite content, kaolinite content) to quantitatively classify the Chang 8 reservoir into three categories. Type-I reservoirs have the best conditions for hosting tight oil reservoirs, with ∼12% porosity, permeabilities of ∼0.2 × 10−3 μm2, trial oil production rates of >5 m3/d, and, indeed, occur in subaqueous distributary channel microfacies. Type-II reservoirs ∼10% porosity, permeabilities of ∼0.1 × 10−3 μm2, and trial oil production rates of 1–5 m3/d. Type-III reservoirs have ∼5% porosity, permeabilities of ∼0.05 × 10−3 μm2, and trial oil production rates <1 m3/d. These results provide an important basis for predicting the distribution of exploitable zones in the Chang 8 sandstone and other adjacent tight sandstones.