The heterogeneities of complex reservoirs are expressed in terms of multi-scale pore structure, different pore type and multiple occurrence mode. Fluid transport mechanisms notably differ from that in conventional sandstone reservoir. Conventional core scale experimental methods are not applicable to complex reservoirs because of nanoscale pore size and strong heterogeneity. Investigating pore scale fluid flow is the key to reveal flow mechanisms while the current pore scale modelling framework fails to consider the multi-scale structure, multiphase fluid-rock interaction and confined phase change. This work leverages the recent advances in pore scale modeling methods of fluid transport in complex reservoirs. The developing trend of multi-scale digital rock construction, flow experiments and simulation methods are elaborated in detail. The mentioned pore scale modeling methods in this work form the future research paradigm for understanding fluid transport mechanisms in complex reservoirs.

The displacement of residual oil by water flooding in porous media is an important mechanism of enhanced oil recovery in many sandstone reservoirs. Nonetheless, our basic understanding of the influence of complex pore geometries of natural porous media on fluid distribution is still incomplete. Herein, two-phase flow simulations were performed to investigate the pore-scale dynamics of imbibition in a heterogeneous sandstone rock sample. Furthermore, the relationship between residual oil distribution and pore structure parameters was quantitatively characterized based on a pore-throat segmentation method. The findings suggest that the pore-scale displacement and snap-off processes have a strong dependence on the coordination number and aspect ratio. The entrapment and remobilization of oil clusters were also analyzed under continuous and discontinuous displacement modes. In addition, a new quantitative method to evaluate the displacement potential and mobilization pattern of remaining oil was presented and discussed. Statistical analysis revealed that the development of sub-pathways and the suppression of snap-off are responsible for the decrease in residual oil saturation with increasing capillary number during water injection. Moreover, the connected residual oil clusters trapped in pores with high coordination number prefer to be displaced and produced. Finally, the displacement modes with different capillary numbers under different initial oil distributions were evaluated to explain the effect of pore structure. By incorporating these correlations of displacement events with pore-throat geometry, existing predictive models can be improved, which could be helpful for the fine tapping of highly disconnected remaining oil in sandstone reservoirs.

Capillary trapping is an important strategy to prevent CO₂ from escaping. Meanwhile, under immiscible conditions, CO₂ may travel upwards by gravity. Studying the long-term effects of gravity and layered heterogeneity on CO₂ transport is crucial for ensuring CO₂ storage security in aquifers. In this work, fluid flow experiments driven by inertial force and gravity are conducted in a specially constructed layered sandstone. Whether driven by inertial force or gravity, the variation in CO₂ distribution in the high-permeability layer is consistently the most significant factor. In the low-permeability layer, the saturation and capillary pressure distribution of CO₂ clusters vary less and the geometric shapes are also more complex, thus the CO₂ capillary trapping in this layer is more stable. This work demonstrates that the low-permeability layer can effectively prevent CO₂ from escaping upwards when the permeability ratio between layers approaches two.

The scientific and engineering challenges of research on porous media have gained substantial attention in recent decades. These intricate issues span different disciplines and fields, manifesting in natural and industrial systems like soils, oil and gas reservoirs, tissues, plants, etc. Meanwhile, digital core analysis technology has rapidly developed, proving invaluable not just in oil and gas reservoirs development, but also in geothermal energy, carbon and hydrogen storage. The China InterPore Chapter and the Research Center of Multiphase Flow in Porous Media at China University of Petroleum (East China) have established a conference platform for global scholars to exchange ideas and research in porous media utilizing digital core analysis technology. The 6^th International Conference on Digital Core Analysis & the 2023 China Interpore Conference on Porous Media was successfully held in Qingdao from July 5 to 7, 2023. The conference facilitated discussions among 150 participants, including over 20 invited experts from academia and industry, and the recent advances in research of fluid flow in porous media using digital core analysis technology were thoroughly presented.

This report summarizes the recent findings on gas transport mechanisms in shale gas reservoir by pore network modelling. Multi-scale pore network model was developed to accurately characterize the shale pore structure. The pore network single component gas transport model was established considering the gas slippage and real gas property. The gas transport mechanisms in shale pore systems were elaborated on this basis. A multicomponent hydrocarbon pore network transport model was further proposed considering the influences of capillary pressure and fluid occurrence on fugacity balance. The hydrocarbon composition and pore structure influences on condensate gas transport were analyzed. These results provide valuable insights on gas transport mechanisms in shale gas reservoir.

Carbonate reservoirs develop many different types of microfractures that play an important role in increasing the effective reservoir space and permeability. Thus, the qualitative and quantitative characterisation of the effect of microfractures on permeability in rocks is essential. In this study, a quantitative method for evaluating the impact of different microfracture parameters on carbonate rock permeability was proposed. Lattice Boltzmann simulations were carried on two carbonate digital cores with different types of artificially added microfractures. Based on the simulation results, a partial least squares regression analysis was used to investigate the impact of microfractures on the permeability of the cores. Increases in the fracture length, aperture, and density were found to linearly increase the permeability of the carbonate rocks, and as the fracture length increased to penetrate the whole core, an exponential increase in permeability was observed. Additionally, the effect of microfractures on the digital core permeability was more significant in cores with high permeability compared to that in low-permeability cores. Although both fractures and matrix permeability contribute to the permeability of the digital cores, the former were found to have a greater effect on the permeability.

In-situ conversion is proposed applicable for low-medium maturity shale oil reservoir. However, parallel chemical kinetic reactions and evolution of shale pores during in-situ conversion make the numerical simulation a challenging problem. Although shale is typical multiscale and heterogeneous media, few models in previous studies take the difference between organic and inorganic system into consideration, which cannot simulate fluid flow accurately. In this paper, a multi-continuum model, considering coupled thermal-reactive compositional flow, is developed to simulate in-situ conversion process in low-medium maturity shale oil reservoir. The reaction of kerogen and hydrocarbon is quantified using kinetic reaction model. The evolution of fluid composition and shale properties are also incorporated. The accuracy of multiple-interacting-continua model and compositional model are demonstrated by comparing with commercial software and analytical solution. Then, the typical hexagon vertical well heating pattern is simulated and the feasibility is evaluated from an economic aspect. Finally, a series of case studies are conducted to investigate the impact of operation parameters on shale oil production.

Research on the scientific and engineering problems of porous media has drawn increasing attention in recent years. Digital core analysis technology has been rapidly developed in many fields, such as hydrocarbon exploration and development, hydrology, medicine, materials and subsurface geofluids. In summary, science and engineering research in porous media is a complex problem involving multiple fields. In order to encourage communication and collaboration in porous media research using digital core technology in different industries, the 5 ${}^{\mathrm{th}}$ International Conference on Digital Core Analysis & the Workshop on Multiscale Numerical and Experimental Approaches for Multiphysics Problems in Porous Media was held in Qingdao from April 18 to 20, 2021. The workshop was jointly organized by the China InterPore Chapter, the Research Center of Multiphase Flow in Porous Media at the China University of Petroleum (East China) and the University of Aberdeen with financial support from the National Sciences Foundation of China and the British Council. Due to the current pandemic, a hybrid meeting was held (participants in China met in Qingdao, while other participants joined the meeting online), attracting more than 150 participants from around the world, and the latest multi-scale simulation and experimental methods to study multi-field coupling problems in complex porous media were presented.

Formation damage caused by well drilling, completion, oil testing, oil recovery, and stimulation seriously affects oil and gas production, the evaluation of which plays an important role in the process of oilfield development. Thus, it is necessary to study formation damage mechanism from micro scale. In this study, two sets of displacement experiments were conducted using two sandstone samples and two chemical reagents. Each set was divided into three processes: first formation water injection, reverse chemical reagents injection and second formation water injection. According to the results of displacement experiments, the permeability changes of two sandstone samples were analyzed and the formation damage rates of different experimental processes were calculated respectively. In addition, we analyzed the formation damage of the two samples from the macroscopic aspect according to the changes of inlet pressure curves. We compared the pore structure changes of sandstone samples at different experiment processes by computed tomography (CT) images, and found the particle migration phenomenon. Based on the core sensitive regions observed by CT images, the pore network models of the sensitive regions were extracted to quantitatively characterize the change of pore structure parameters (pore radius, throat radius, coordination number and tortuosity). Finally, we designed a two-dimensional microscopic seepage channel model according to the real core structure. The flow rule of solid particles in fluid was simulated by finite element method, and the reason of reservoir clogging was analyzed. Through this study, we found that the injection of chemical reagents increased the inlet pressure and led to the decrease of core permeabilities. There was a negative correlation between the export rate of particle migration and matrix deformation degree.

To investigate the distribution characteristics of remaining oil after polymer flooding, the core samples of different stages of water flooding and polymer flooding were scanned and imaged based on CT scanning technology. The oil, water and rock were divided into three phases by image analysis method, and the corresponding digital cores were constructed. Through the qualitative and quantitative analysis of the two-dimensional image and three-dimensional structure at the same position, the quantitative characterization of the micro-residual oil distribution in different displacement stages is finally realized. The results show that, the polymer flooding can significantly improve the sweep efficiency, which can increase the oil recovery by 11.45% compared with water flooding. The remaining oil in the pore is mainly network and multiple, and mainly network distribution at the stage of water flooding. After adding polymer, the proportion of multiple remaining oil increases significantly and becomes the main occurrence state of remaining oil. Affected by Jamin effect, multiple residual oil in the pore is difficult to be recovered because it cannot pass through the throat. The radius of this part of remaining oil is usually 1.34 $\sim$1.5 times that of the throat radius.