Carbon dioxide enhanced oil recovery (CO₂-EOR) technology is used for oil production and CO₂ storage in reservoirs. Methods are being constantly developed to optimize oil recovery and CO₂ storage during the CO₂ displacement process, especially for low-permeability reservoirs under varying geological conditions. In this study, long-core experiments and trans-scale numerical simulations are employed to examine the characteristics of oil production and CO₂ storage. Optimal production parameters for the target reservoir are also proposed. The results indicate that maintaining the pressure at 1.04 to 1.10 times the minimum miscible pressure (MMP) and increasing the injection rate can enhance oil production in the early stage of reservoir development. In contrast, reducing the injection rate at the later stages prevents CO₂ channeling, thus improving oil recovery and CO₂ storage efficiency. A solution-doubling factor is introduced to modify the calculation method for CO₂ storage, increasing its accuracy to approximately 90 %. Before CO₂ breakthrough, prioritizing oil production is recommended to maximize the economic benefits of this process. In the middle stage of CO₂ displacement, decreasing the injection rate optimizes the coordination between oil displacement and CO₂ storage. Further, in the late stage, reduced pressure and injection rates are required as the focus shifts to CO₂ storage.

The tight-tuff heavy oil reservoir exhibits severe heterogeneity and is characterized by high density, high viscosity, and a high wax content, posing significant challenges for its development. While CO₂ huff-and-puff (H-n-P) enhances oil recovery, these reservoirs struggle with low displacement efficiency. This study proposes a method that combines CO₂ with an oil-soluble viscosity reducer to improve displacement efficiency in the H-n-P process for tight-tuff heavy oil reservoirs. It also focuses on evaluating pore utilization limits and optimizing the injection strategy. Core samples and crude oil from the TH oilfield (a tight-tuff heavy oil reservoir) were used to conduct online NMR core flooding experiments, including depletion development, water, CO₂, and HDC (CO₂ combined with an oil-soluble viscosity reducer) H-n-P injection processes. A single-porosity model accurately reflecting its geological characteristics was developed using the GEM component simulator within the CMG numerical simulation software to investigate the optimized schemes and the enhanced oil recovery potential for a tight-tuff heavy oil reservoir in the TH oilfield. This model was utilized to evaluate the impact of various injection strategies on oilfield recovery efficiency. The study was designed and implemented with five distinct injection schemes.

Results showed that oil was produced primarily from large and medium pores during the depletion stage, while water H-n-P, with CO₂ H-n-P, first targeted macropores, then mesopores, and micropores. The lower pore utilization limit was 0.0267 μm. In the HDC H-n-P process, most oil was recovered from water-flooded pores. Still, HDC's lower injection capacity increased the pore utilization limit to 0.03 μm, making micropore recovery difficult. Experimental and modeling results suggest that the optimal development plan for the TH oilfield is one cycle of HDC H-n-P followed by two cycles of CO₂ H-n-P. This strategy leverages HDC's ability to promote water and oil recovery in the early stage and mass transfer and extraction capacity of CO₂ in later cycles.

Additionally, the characteristics of CO₂ and HDC H-n-P processes, pore utilization, and recoverable oil (at the pore scale) were evaluated. The results of this study are crucial for refining the reservoir development plan.

Spontaneous imbibition (SI) is an important mechanism for enhancing oil recovery in low-permeability reservoirs. Due to the strong heterogeneity, and the non-Darcy flow, the construction of SI model for low-permeability reservoirs is extremely challenging. Commonly, traditional SI models based on single or averaged capillary tortuosity ignore the influence of heterogeneity of pore seepage channels and the threshold pressure (TP) on imbibition. Therefore, in this work, based on capillary model and fractal theory, a mathematical model of characterizing SI considering heterogeneity of pore seepage channels is established. On this basis, the threshold pressure was introduced to determine the pore radius at which the wetted phase can displace oil. The proposed new SI model was verified by imbibition experimental data. The study shows that for weakly heterogeneous cores with permeability of 0–1 mD, the traditional SI model can characterize the imbibition process relatively accurately, and the new imbibition model can increase the coefficient of determination by 1.05 times. However, traditional model has serious deviations in predicting the imbibition recovery for cores with permeability of 10–50 mD. The new SI model coupling with heterogeneity of pore seepage channels and threshold pressure effectively solves this problem, and the determination coefficient is increased from 0.344 to 0.922, which is increased by 2.68 times. For low-permeability reservoirs, the production of the oil in transitional pores (0.01–0.1 μm) and mesopores (0.1–1 μm) significantly affects the imbibition recovery, as the research shows that when the heterogeneity of pore seepage channels is ignored, the oil recovery in transitional pores and mesopores decreases by 7.54% and 4.26%, respectively. Sensitivity analysis shows that increasing interfacial tension, decreasing contact angle, oil–water viscosity ratio and threshold pressure will increase imbibition recovery. In addition, there are critical values for the influence of these factors on the imbibition recovery, which provides theoretical support for surfactant optimization.