CO₂ flooding has broad application prospects in the long term owing to the booming of industries involving carbon capture，utilization，and storage amid the vigorous implementation of the“carbon peaking and carbon neutrality”policy.As low- and ultralow-permeability reservoirs have complex pore spaces and structures，the conventional water flooding development is invariably faced with difficult water injection and low oil recovery. In contrast，CO₂ flooding offers a variety of oil displacement mechanisms and can well solve the problem of difficult water flooding development.In this paper，PVT fitting was carried out based on information on crude oil composition and experimental data on constant composition expansion and a component model with seven pseudo-components was constructed according to the conditions of the low-porosity and low-permeability reservoirs in Block A，Shengli Oilfield. The initial miscibility pressure obtained was 30.1 MPa，and the multi-contact miscibility pressure was 26.6 MPa. This paper proposed an empirical formula for calculating the gas injection rate of CO₂ flooding with gas channeling as the constraint for the first time. The engineering parameters of CO₂ flooding reservoirs in Block A were optimized with the homogeneous component model. The optimal injection-production parameters were thereby determined as a five-spot well pattern，a well spacing of 250 m，a gas injection rate of 20 t/d，and a production pressure of 26.0 MPa. Furthermore，the injection-production parameters of different development modes were optimized，and the development modes were respectively depletion development，water flooding，CO₂ huff and puff，continuous CO₂ injection，and water-alternating-gas（WAG）. The optimization results of different development modes were comparatively analyzed. The results showed that continuous gas injection had certain advantages. Finally，the dominant physical property area in the southwest of Block A was selected as a pilot development area to predict the effect of a continuous gas injection development scheme for a well group according to the optimization results. The results revealed that the recovery of the well group was 15.1% in 10 a and 22.4% in 20 a.