Wettability in CO₂-brine-mineral/rock systems is an important parameter influencing CO₂ storage capacities and leakage risks in saline reservoirs. However, CO₂ tends to react with various minerals and rocks at subsurface conditions, thus causing temporal and spatial wettability changes. Although many relevant research works have been published during past years, a thorough overview of this area is still lacking. Therefore herein, reaction-induced wettability changes are reviewed, and the underlying mechanisms are discussed. Current research gaps are identified, future outlooks are suggested, and some conclusions are drawn. The fundamental understanding of reaction-induced mineral and rock wettability changes during CO₂ storage in saline reservoirs is analyzed and the guidance for long-term CO₂ containment security evaluations is provided.

The objective of this study is to construct a refined microscopic transport model that elucidates the transport mechanisms of gas flow within micro-nano pores and fractures. The collective impact of various microscopic transport mechanisms was explained through the apparent permeability model, specifically related to gases such as methane and carbon dioxide, within the shale matrix. The apparent permeability models, taking into account microscopic transport mechanisms such as slippage flow, Knudsen diffusion, transition flow, and surface diffusion, were established individually. Subsequently, the influencing factors on apparent permeability were analyzed. The results demonstrate that the apparent permeability of the shale reservoir matrix is significantly influenced by pore pressure, temperature, pore size, and total organic carbon (TOC). As pressure decreases, the apparent permeability of Knudsen diffusion and surface diffusion increases, while the apparent permeability of slippage flow decreases. In addition, the apparent permeability of the reservoir matrix initially decreases and then increases. With increasing temperature, the apparent permeability of slippage flow, Knudsen diffusion, and surface diffusion all increase, as does the apparent permeability of the reservoir matrix. As pore size increases, the apparent permeability of surface diffusion and Knudsen diffusion decreases, while the apparent permeability of slippage flow and the reservoir matrix increases. Furthermore, an increase in TOC leads to no change in the apparent permeability of slippage flow and Knudsen diffusion, but an increase in the apparent permeability of surface diffusion and the reservoir matrix. The model presented in this paper enhances the multi-scale characterization of gas microflow mechanisms in shale and establishes the macroscopic application of these micro-mechanisms. Moreover, this study provides a theoretical foundation for the implementation of carbon capture, utilization, and storage (CCUS) in shale gas production.

It was deemed important to calculate the thermal recovery production model of tight oil reservoirs after fracturing and packing based on the field data of an oilfield in Bohai Sea, China. The thermal recovery production of a tight oil reservoir after fracturing is demonstrated through theoretical calculation and practical field data on the premise of five hypotheses. Fractures change the fluid flow capacity of the reservoir. Combined with the relevant theories of reservoir thermal production, the dual porosity system in the fractured zone and the single porosity system in the unfractured zone were established. The calculation models of heat loss in the fractured and unfractured zones were derived to determine the thermal recovery heating radius of the reservoir after fracturing and packing. Combined with the pseudo-steady state productivity formula of the composite reservoir, a production calculation model of thermal recovery after fracturing and packing in the tight oil reservoir was established. The results showed that the heating radius of the reservoir after fracturing and packing is smaller than that of the unfractured reservoir, and the additional heat absorption of the fracture system generated by fracturing and packing reduces the thermal recovery effect. The thermal recovery productivity of heavy oil reservoirs is mainly affected by the heating radius. With the increase of fracture density, the heating radius decreases and production decreases. The increase of fracture porosity also leads to the decrease of the heating radius and the production. The calculation result of this model is improved after tight oil reservoir fracturing during the production period, which indicates that the model has a better prediction effect of the production of the tight reservoir after fracturing and packing.

The geological estimated hydrocarbon reserves of the Mesozoic granite buried-hill reservoir in the PL oilfield exceed 200 million tons. During the exploration stage, it was commonly considered that the PL buried-hill reservoir should demonstrate a “layered” edge water reservoir mode, because of weathering and tectonics. However, during a later stage, the formation of water was found at structurally high locations, which does not fit the intuition. Therefore, a suitable model is still lacking. Based on the comprehensive information of thin-section, core plug, well logging, and seismic data, etc., the buried-hill of the PL oilfield was re-divided into three northeast–southwest-trending zones. In this model, the reservoir is layered, with each layer having the characteristics of bottom water and two kinds of horizontal and vertical seepage. This new model fits the field-drilling test very well. These insights can effectively guide the exploration and development practice for this kind of buried-hill.