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.

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.

The Mahu Sag in the Junggar Basin holds significant potential for oil and gas exploitation and development. However, the strong reservoir heterogeneity therein leads to a rapid decline in oil and gas production. Presently, the pre-CO₂ fracturing, gas flooding, sequestration (PCFS) synergistic technology is commonly employed for enhanced oil recovery from glutenite reservoirs. This study aims to investigate the impact of CO₂-water-rock interactions on pore structures during pre-flushing CO₂ fracturing, as well as CO₂ migration patterns in the process of gas flooding. Using a glutenite core taken from the Mahu Sag, we perform CO₂ soaking experiments, high-precision micro-computed tomography (micro-CT), and volume of fluid (VOF) method-based numerical simulations of two-phase flow in 3D digital cores. The results indicate that CO₂-water-rock interactions facilitate the dissolution-derived expansion of the pore structure, and the originally isolated channels converge into sheets, increasing the sweep range of CO₂ clusters. Meanwhile, this process induces secondary mineral precipitation and expansion, which can block or restructure pathways for fluid flow and, accordingly, change the flow paths and velocity of fluids in the pore structure. These, thereby, hinder the formation of the preferential flow pathways. Nevertheless, compared to the negative impact of secondary mineral precipitation and expansion, the pore space expansion under CO₂ soaking-induced dissolution is greater in positive effect. Specifically, the permeability is improved, so does the seepage capacity of pore structures. CO₂ clusters in different flow channels exhibit different morphologies (like convex or concave) at the displacement front. In the representative elementary volume (REV) models before and after CO₂ soaking, the dimensionless parameters (i.e., capillary number C_a, contact angle θ, and viscosity ratio M) exert varying degrees of influence on the displacement efficiency. Specifically, in the REV model after CO₂ soaking, exhibiting a relatively higher degree of porosity evolution, the displacement efficiency is more sensitive to changes in the dimensionless parameters. This indicates that the PCFS synergistic technology is more effective in the exploitation of reservoirs with higher-degree porosity development.

The deep eastern edge of the Ordos Basin is rich in coalbed methane, presenting great potential for development. Meanwhile, CO₂ imbibition is an important method to increase production. To study the CO₂-water-rock interactions and microstructural damage characteristics before and after supercritical carbon dioxide immersion in deep coal rocks, CO₂ imbibition experiments were conducted on these rocks by using nuclear magnetic resonance and scanning electron microscopy imaging techniques. The results showed that CO₂ imbibition leads to pore dilatation and reveals the key role of coal rock anisotropy on imbibition efficiency under different physicochemical conditions. Specifically, the immersion of CO₂ produces cracks due to the brittle action of the coal rock, as well as calcite dissolution that exacerbates crack production and expansion. Due to adsorption of CO₂, part of the coal rock becomes swollen, which leads to detachment and changed the physical properties and surface characteristics of the coal rock.

Spontaneous imbibition is an essential mechanism for recovering oil from low-permeability fractured water-driven reservoirs. To accurately capture the migration interface of oil-water two-phase flow under these conditions, this study employs phase field theory coupled with Cahn-Hilliard and Navier-Stokes equations. We conduct a numerical pore-scale investigation on countercurrent imbibition in low-permeability fractured porous media. The results show that pore-scale spontaneous imbibition can be divided into four stages. In the first stage, oil-water film is formed when oil contacts with water, and this contact line moves under the action of capillary force. In the second stage, the oil film at the end of the oil cluster ruptures to form isolated oil droplets. In the third stage, these oil droplets are surrounded by water and gradually transported outward. In the final stage, oil droplets accumulate in the fractures and are collectively expelled from the matrix. In the process of oil droplet migration, the phenomenon of sticking occurs under the influence of water extrusion and the internal structure of the matrix, which leads to the formation of residual oil. The increased complexity of open boundary and fracture development strengthens the imbibition effect by elevating the degree of spontaneous imbibition pore utilization, thus improving the oil utilization efficiency. The above findings can provide a numerical modeling reference for the study of spontaneous imbibition in fractured porous media, and at the same time, has some guiding significance for the development of low-permeability reservoirs.

The recovered fracturing fluid is generally high in salinity (close to 200 kppm), which is related to the diffusion of salt ions from shale reservoir to the fracturing fluid. However, it is not clear about the diffusion capacity of salt ions in different types. In this paper, the shale, tight volcanic and sandstone are selected as comparative study and a series of tests are carried out for the porosity, permeability and mineral composition. The results show that the shale immersing in fracturing fluid will cause ions dissolution and diffusion, which will increase the salinity of the fracturing fluid. The solution salinity increases rapidly in the early stage and gradually slows down in the later stage. The salinity of the fracturing fluid has a linear relationship with the square root of time, so the slope of the curve can be used as a characteristic parameter to evaluate the ion diffusion rate. The process of dissolution and diffusion of salt ions will induce the expansion of micro-cracks, increasing the contact area between the fracturing fluid and shale and enhancing the solution salinity. The ion diffusion rate is positively related with the content of clay minerals and carbonate. The soluble ions include mainly ${\mathrm{SO}}_{\mathrm{4}}^{\mathrm{2}\mathrm{-}}$, ${\mathrm{Ca}}^{\mathrm{2}\mathrm{+}}$, ${\mathrm{Na}}^{\mathrm{+}}$ and ${\mathrm{K}}^{\mathrm{+}}$. The ${\mathrm{Na}}^{\mathrm{+}}$/ ${\mathrm{Cl}}^{\mathrm{-}}$ ratio is closely related to the content of clay minerals and carbonate minerals. It has a positive correlation with content of illite and chlorite, and a negative correlation with carbonate minerals, suggesting NaCl source from illite and chlorite. This study is significant for understanding the salinity characteristics of recovered fracturing fluid and evaluating the fracture network shape.

After fracturing operations, a large amount of fracturing fluid is retained in shale fracture network, resulting in low flowback efficiency. This has been attributed to the imbibition of fracturing fluid into matrix pores. However, it is unclear how the imbibition mechanism is involved, what are its governing laws and controling parameters in fracture networks? Based on the three-dimensional water imbibition theory of matrix blocks, a fracture network model is established, and a number of dimensionless controling parameters are proposed and analyzed for flowback efficiency. The results show that the imbibition characteristics of fracturing fluid in fracture network are mainly determined by two dimensionless numbers; namely, dimensionless imbibition time, fracture width, and imbibition capacity. The dimensionless imbibition time characterizes the contact time between the fracturing fluid and shale formation, which negatively correlates to the flowback efficiency. The dimensionless fracture width is the ratio of the fracture width to the rock length, which is inversely proportional to the flowback efficiency. Smaller value of the dimensionless fracture width corresponds to larger contact area of fracturing fluid and shale, leading to a lower flowback efficiency. The dimensionless imbibition capacity depicts the capacity of shale reservoirs to imbibe fracturing fluid, which has a negative linear correlation with flowback efficiency. In addition, dimensionless time and fracture width are related to the fracturing operations, and are enhanced by increasing the shut-in periods and proppant concentration. Therefore, the flowback efficiency can be controlled by changing fracturing operations. The predictive method of the flowback efficiency established here is of great significance for reservoir damage analysis and flowback regime optimization.