A tight conglomerate reservoir is a kind of unconventional reservoir with strong heterogeneity, and CO₂ injection is an economical and environmentally friendly method to enhance tight oil recovery. Supercritical CO₂ is a very promising fluid medium for unconventional reservoir development due to its gas–liquid dual properties. In this study, the production effects of supercritical CO₂ and non-supercritical CO₂ in tight conglomerate reservoirs were quantitatively analyzed by huff and puff simulation experiments conducted under reservoir conditions (formation pressure 37 MPa, temperature 89 °C). Also, the influencing factors of CO₂ huff and puff production, including injection volume, soaking time, and throughput cycles, were investigated. The results showed that supercritical CO₂ improves the recovery by 4.02% compared with non-supercritical CO₂. It could be seen that supercritical CO₂ plays a positive role in improving tight conglomerate reservoirs. The optimal injection volume, soaking time, and throughput cycles were determined to be 0.50 PV, 2 h, and 3 cycles, respectively. This paper provides an important basis for the study of supercritical CO₂ production in tight conglomerate reservoirs.

Carbon dioxide (CO₂) flooding is a promising method for developing low-permeability heterogeneous glutenite reservoirs (LPHGRs) featured with low natural energy. Herein, the focus of this work was to study the microscopic oil displacement mechanism of CO₂ in LPHGRs. First, the micropore structure and mineral composition of LPHGRs were analyzed, and the effect of CO₂ on low-permeability reservoirs was then studied. Also, the mechanism of CO₂ displacement in low-permeability reservoirs on a pore scale was analyzed using nuclear magnetic resonance technology in different dimensions. The experimental results showed that the mineral composition of the rock mainly included quartz, feldspar, and clay minerals. The core pores were poorly developed and highly heterogeneous. The clay and other mineral particles produced by the dissolution reaction of rocks and minerals migrated and deposited with formation fluid to damage the reservoir. On the contrary, it also improved the pore structure, increased pore space, and increased reservoir permeability. The miscible interaction between CO₂ and crude oil formed a stable displacement front, which enabled crude oil to be well displaced from the macropores and medium pores. However, this interaction generated negligible effects on the small pores. The experimental results provided important indicators for CO₂ development in LPHGRs.

Tight sandy conglomerate reservoirs exhibit poor physical properties, strong heterogeneity, and significant development challenges due to low permeability. Understanding the interaction of CO₂ with such formations is critical for enhanced oil recovery (EOR). Experimental studies on the interaction mechanisms among CO₂, formation water, and tight sandy conglomerate were conducted. The results indicate that under the reservoir conditions of 89 °C and 37.0 MPa, the solubility of CO₂ in the formation water is significantly influenced by temperature, pressure, and salinity. After dissolving in formation water, CO₂ forms carbonic acid, which triggers dissolution reactions of minerals such as feldspar under acidic conditions. This leads to a reduction in feldspar mineral content and a 0.31% decrease in core mass. Concurrently, the rock's microscopic surface becomes rougher with numerous dissolution pores and cavities emerging. The average pore-throat radius increases, and the displacement pressure decreases. These alterations improve the rock's pore structure by enlarging pore-throat dimensions, creating additional flow channels for oil and gas migration. Consequently, the permeability increases by 7.4-11.0%, thereby enhancing the production capacity of tight sandy conglomerate reservoirs.