To explore the influence of differential diagenesis on the oil bearing properties of tight sandstone reservoirs，Chang 8 reser‐voirs with ultra-low porosity and ultra-low permeability in the Qingcheng area were used as an example. Based on the statistical cast thin section data of 337 samples and the scanning electron microscope（SEM）and high-pressure mercury injection data of 10 samples，the porosity evolution characteristics of different types of reservoirs were calculated，and the influence of differential diagen‐esis on the oil bearing properties of the reservoirs was analyzed. The research results show that the Chang 8 tight sandstone reservoirs in the Qingcheng area are mainly composed of lithic feldspar sandstone and feldspathic litharenite，with dissolution pores and residual intergranular pores developed. According to the characteristics of brittle mineral content，soft particle content，porosity，and calcare‐ous cement content，the Chang 8 reservoirs can be divided into three types：high-porosity sandstone（Type Ⅰ），high-porosity cal‐careous sandstone（Type Ⅱ），and rich soft particle sandstone（Type Ⅲ）. Type Ⅰ reservoirs are mostly underwater distributary chan‐nel sand bodies and have the strongest compaction effect in the early diagenesis stage，with an average compaction porosity reduction rate of 60.0%，but they have a strong dissolution effect in the later stage，with an average dissolution porosity increase rate of 11.8%，weak cementation effect，and an average cementation porosity reduction rate of 27%. The average remaining porosity value is 9.5%.Type Ⅱ reservoirs are mostly underwater distributary channel sand bodies，and their estuarine bar sand body is slightly developed compared with Type Ⅰ reservoirs. The early calcium cementation of Type Ⅱ reservoirs is strong，and the compaction is relatively weak. The average compaction porosity reduction rate is 56.8%，and the average cementation porosity reduction rate is 34.1%；the av‐erage dissolution porosity increase rate is 11.5%，and the average remaining porosity is 7.9%. Type III reservoirs are more likely to de‐velop in sand bodies along the side of underwater distributary channels. The early compaction of Type II reservoirs is not strong，with an average compaction porosity reduction rate of 49.3%，but the later dissolution is weak，with an average dissolution porosity in‐crease rate of 10.5%. The late cementation is strong，with an average cementation porosity reduction rate of 43.2%. The final porosity is the lowest，with an average value of 6.9%. The pore throat radius of Type Ⅰ and Type Ⅱ reservoirs is concentrated in 0.1-1 μm，and the pore throat connectivity is good. The pore throat heterogeneity is weak，and the oil bearing property is good. The distribution of pore throat in Type III reservoirs is not concentrated，and the connectivity is poor；the pore throat heterogeneity is strong，and the oil bearing property is poor. In the Late Early Cretaceous，oil and gas migrated and accumulated on a large scale，and the three types of reservoirs were not densified. With the further densification of reservoirs in the middle diagenesis A stage，the differences in physical properties and pore throat structure of the three types of reservoirs are enhanced，affecting the adjustment distribution of oil and gas in the later stage. The oil bearing property of Chang 8₂ is poorer than that of Chang 8₁ because the Type II reservoirs in Chang 8₂ are more developed，and strong carbonate cementation reduces the connectivity of pore throats，which is not conducive to oil and gas charging.