Mobility is a crucial metric for assessing sweet spots of continental shale oil. However, due to the complexity of shale oil reservoirs characteristics and the lack of systematic analyses of factors influencing mobility, the difference in shale oil mobility under multiple lithofacies control remains unclear, causing significant challenges for mobility evaluation and sweet spot prediction. This study examines continental shales of the Fengcheng Formation in the Mahu Sag, employing scanning electron microscopy (SEM), nitrogen adsorption (NA), nuclear magnetic resonance (NMR), spontaneous imbibition (SI), and contact angle measurements (CAM) to investigate the pore structure, connectivity, and wettability properties of different lithofacies shale. Quantitative analyses of shale movable oil content and saturation were conducted using multistep temperature pyrolysis (MTP) and NMR centrifugation techniques. Furthermore, the influence of reservoir characteristics, geochemical characteristics, and lamination development on shale oil mobility were discussed. Results indicate that larger pore diameter, higher imbibition slopes, and lower fractal dimensions of movable fluid pores (D₂) correspond to higher movable oil saturation. Organic matter exerts a dual effect on shale movable oil content. When the TOC is below a threshold, the movable oil content gradually increases with TOC. Laminations exhibit favorable reservoir properties and light oil enrichment, enhancing shale oil mobility. Massive siltstone (MS) develops interconnected intergranular pores with the best pore structure and connectivity, the lowest D₂ values, and the highest shale oil mobility. Laminated felsic shale (LFS) and laminated calcareous shale (LCS) exhibit moderate mobility, where the development of microfractures enhances fluid flow by connecting isolated pores into pore-fracture networks. In contrast, massive felsic shale (MFS) and bedded felsic shale (BFS) primarily develop intragranular dissolution pores with more complex structures and poorer connectivity, resulting in weaker mobility. A more accurate approach for assessing shale oil mobility has been presented, taking into account both total oil content and movable oil saturation. More importantly, this study establishes a comprehensive conceptual model illustrating the potential relationships among shale lithofacies, reservoir characteristics, and movable oil flow space in the study area. This research not only provides a systematic approach for assessing shale oil mobility but also deepens the understanding of flow mechanisms of continental shale oil, offering theoretical guidance for optimizing sweet spots in the Fengcheng Formation shale oil reservoirs of the Mahu Sag.

Through the long development processes of reservoir sedimentation and diagenesis, acidic and alkaline fluids play key roles in controlling deep reservoir development. However, the ways in which deep fluids control and transform the reservoir under complex fault conditions remain unclear. In this study, a 2D model was established based on a typical sub-salt to intra-salt vertical profile in the Qaidam Basin, China. Based on measured data, multiphase flow reaction and solute transport simulation technology were used to analyze fluids flow and migration in the intra-salt and sub-salt reservoirs, determine the mineral dissolution, precipitation, and transformation in the reservoir caused by the deep fluids, and calculate the changes in reservoir porosity. Results show that deep fluid migrates preferentially along dominant channels and triggers a series of fluid–rock chemical reactions. In the first stage, a large amount of anhydrite precipitated in the fault as a result of upward migration of deep saline fluid, resulting in the formation of anhydrite veins and blockage at the base of the fault. In the second stage, organic acids caused minerals dissolution and a vertical channel was opened in previously blocked area, which promoted continuous upward migration of organic acids and the formation of secondary pores. This study clarifies the transformative effects of deep alkaline and acidic fluids on the reservoir. Moreover, the important fluid transport role of faults and their effect on reservoir development were determined.