The Carboniferous Benxi Formation in the Ordos Basin holds substantial potential for deep coalbed methane (CBM) development. However, hydraulic fracturing operations commonly induce damage to coal reservoirs, resulting in low gas recovery rates. In this study, systematic experiments were conducted on deep coal rock samples from the Benxi Formation in the Ordos Basin, including supercritical (SC)-CO₂ soaking, three-point bending tests, scanning electron microscopy (SEM), and nuclear magnetic resonance (NMR) analyses. As indicated by the research results, SC-CO₂ exposure exerts a time-dependent, nonlinear influence on the mechanical properties of coal, characterized by an initial short-term enhancement followed by long-term deterioration. Peak load, fracture toughness, and elastic modulus reached relatively high values after 5 days of soaking. With prolonged exposure, however, the pore structure progressively deteriorated due to dissolution, leading to a 25.62% reduction in fracture toughness and a 33.29% reduction in elastic modulus after 20 days. Meanwhile, SC-CO₂ significantly enhances pore connectivity and alters fluid occurrence patterns. Loosely structured coal rocks with well-developed porosity exhibits greater sensitivity, with the total T₂ spectrum area increasing by 40.2%. In terms of failure modes, the fractures of untreated coal rocks were predominantly of brittle vertical penetration with relatively regular propagation paths. After SC-CO₂ soaking, fracture propagation is increasingly controlled by the interplay between bedding development and dissolution-induced weakening. This led to more complex fracture geometries, as evidenced by an increase in fracture fractal dimensions. The most pronounced fluctuations occur in samples with bedding perpendicular to the loading direction, with a maximum fractal dimension increase of 12.8%. SEM observations indicate that SC-CO₂ dissolution induces multiscale damage to the microstructure of coal rocks. At the micrometer scale, calcite dissolution results in localized pore networks. At the hundred-micrometer scale, micro-cracks initiate at dissolution zone boundaries and propagate into through-going fractures. At the millimeter scale, accumulated damage drives micro-crack coalescence along mechanically weakened pathways, ultimately forming complex fracture networks.

Hydraulic fracturing serves as a primary technique for developing tight sandstone oil reservoirs. Investigating the microscopic seepage mechanism and flow dynamics of residual oil helps guide the exploitation of tight oil reservoirs with high water cut. To explore fluid migration patterns and the imbibition-displacement coupling mechanism during fracturing fluid injection, we conduct visual flooding experiments using microfluidic models based on fracture-matrix laser-etched chips (also referred to as the dual-medium microfluidic models). We analyze the movement of the oil-water interfaces, the stripping of oil droplets, and the microscopic distribution of residual oil under the influence of imbibition-displacement coupling. The results indicate that, following the injection of fracturing fluids into a dual-medium microfluid model, the flow process involved fracture fingering, pore-fissure interactive imbibition, and pore displacement. A lower injection rate corresponded to a stronger dominance of imbibition, resulting in a broader sweep range of oil in dead-end pores near the fractured zone. With an increase in the injection rate, the interactive imbibition weakened, leading to a gradual reduction in sweep range and oil recovery, which was primarily attributable to pore oil displacement. The addition of surfactants enhanced the ability of fracturing fluids to strip oil droplets and residual oil clusters adhering to pore walls. Moreover, fracturing fluids containing surfactants significantly impacted residual oil and promoted its drainage. Consequently, a substantial amount of residual oil was stripped from the pore walls. Following fluid breakthrough, residual oil on pore walls continued to be stripped during the stable displacement stage, significantly enhancing the overall flooding effect. Residual oil remained in the imbibition and flooding processes due to variations in wall roughness and the impact of flow rates and pressure across different pores. Based on its morphology and distribution, residual oil can be categorized into six types: spherical, single-wall-adhered membranous, pore-throat columnar, double-wall-adhered membranous, wall-adhered bent columnar, and inter-wall contiguous types. The columnar and membranous types, among others, are extensively distributed.

Supercritical CO₂-water-rock interactions significantly impact the mechanical integrity of heterogeneous conglomerate reservoirs, challenging their suitability for CO₂ sequestration and enhanced oil recovery. To evaluate these microscale mechanical and structural changes, this study uses a combination of micro-scratch testing, scanning electron microscopy, and nuclear magnetic resonance. The results reveal that the micro-scratch method enables the acquisition of a continuous mechanical property profile, addressing the limitation of traditional rock mechanics that only allows discrete point measurements. Importantly, the scratch failure modes significantly depend on the lithology of conglomerate reservoirs: Felsic and quartz conglomerates exhibit sharp grooves with interfacial shear failure, whereas debris-rich variants develop wavy, fragmented paths. CO₂-water exposure reduces the deformation resistance and causes fracture toughness to initially increase and then decline, with the most severe reduction observed in quartz conglomerates. The degradation of mechanical properties is mainly through mineral dissolution and increased porosity. The findings of this study offer key insights for optimizing storage and recovery strategies in complex reservoirs.

Tight Sandy Conglomerate reservoirs in the Mahu Sag, Junggar Basin exhibit extreme heterogeneity, posing significant challenges to the field tests and prediction of the CO₂ sequestration performance following CO₂ flooding. Understanding the mechanisms underlying CO₂-brine-Sandy Conglomerate interactions is crucial to evaluating the CO₂ sequestration performance following reservoir development. Based on CO₂-brine saturation experiments and data from integrated quantitative evaluation of minerals by scanning electron microscopy (SEM), SEM-based quantitative evaluation of minerals (QEMSCAN), micro-CT scanning, and nuclear magnetic resonance (NMR) spectroscopy, we investigate mechanisms underlying CO₂-brine-Sandy Conglomerate interactions and resulting variations in the mineral components, fluid occurrence, and pores in tight Sandy Conglomerate reservoirs of the Mahu Sag. The results indicate that CO₂-brine-Sandy Conglomerate interactions led to the dissolution of rock minerals. This mineral dissolution and subsequent migration resulted in elevated average pore-throat sizes and enhanced pore connectivity in cores. The X-ray diffraction (XRD) analysis reveals that the interactions increased albite and illite contents by 3.20 % and 2.32 %, respectively, while producing minimal impact on quartz content. SEM analysis results demonstrate that CO₂ soaking led to an increase in both the quantity and width of grain-edge fractures, as well as the formation of new lateral fractures. The carbonate and feldspar dissolution generates substantial intragranular micropores and microfractures, with these microfractures propagating along cleavages. NMR experiment results reveal that saturated water primarily occurs as clay-bound water, capillary-bound water, and movable water in the cores. CO₂ soaking contributes to the enhanced content and expanded distribution range of saturated water in the pores, with movable water in macropores changing the most significantly. The research results highlight the complexity of CO₂ interactions in Sandy Conglomerate reservoirs, which is of great significance for guiding the field test effectiveness of CO₂ storage after flooding in the Mahu Sag Sandy Conglomerate reservoirs.