Tight reservoirs represent a significant component of unconventional resources, yet their development is challenged by multiscale and highly heterogeneous pore-throat systems that govern fluid flow. To address this, we integrated MIP, NMR and micro-CT scanning to capture the multi-scale pore structure. Micro-CT analysis reveals that tight sandstones are dominated by micro- and nano-pores, with pores smaller than 10 μm in radius accounting for over 95% of the total pores. Pore morphology classification is not limited by CT scanning resolution: small throats are predominantly regular and plate-like, while macropores exhibit more complex and irregular geometries. MIP data indicate a triple-segment fractal dimension for the throat system, reflecting strong heterogeneity in large throats and weaker heterogeneity in medium and small throats. The pore surfaces are smooth and stable, and permeability is primarily controlled by throats within the 0.1–0.4 μm radius range, whose sorting coefficient shows a logarithmic relationship with permeability. Building on these insights, the core contribution of this study is a novel full-scale pore-throat characterization method that incorporates a dynamic shape factor to quantify throat geometry. By integrating MIP and NMR data within this new framework, we successfully derived the complete pore-throat distribution. Results show that plate-like throats are mainly distributed between 0.0015 μm and 1.23 μm, while the critical radius of plate-like pore is about 1 μm. In contrast, heterogeneous pores exhibit radii exceeding 15 μm, with a peak around 40 μm. The accuracy of the full-scale distribution was validated using a modified Kozeny-Carman model, which predicts permeability within less than 10% error compared to experimental measurements. This study provides a robust and accurate workflow for pore structure characterization, advancing the quantitative evaluation of tight sandstone reservoirs and enhancing our fundamental understanding of fluid transport mechanisms.

In the development of shale gas reservoirs, hydraulic fracturing is followed by an imbibition (or soaking) stage, during which the fracturing wetting fluid migrates into the reservoir matrix. As a consequence, laboratory imbibition experiments have been performed in shale samples. However, these tests were generally conducted at atmospheric pressure and thus only involved spontaneous imbibition, which does not correspond to in-situ reservoir conditions. This study addresses this limitation by conducting forced imbibition experiments in shale samples at different flow and confinement conditions while measuring the nuclear magnetic resonance T₂ relaxation spectra at regularly increasing times. It was observed that increasing the initial pressure difference between the upstream and downstream ends of the sample (hereafter called the differential pressure) significantly improved gas displacement efficiency by promoting greater water migration into the shale pore space. Moreover, it was found that decreasing the confinement (i.e., by lowering the effective pressure) further enhanced the imbibition displacement efficiency, which reaches a maximum when the effective pressure approaches zero and spontaneous imbibition occurs. Reducing the effective pressure leaded to a substantial increase in the water intake and the formation of micro-cracks, as confirmed by post-mortem scanning electron microscopy images. These results emphasize that the differential pressure and effective pressure are key factors influencing the imbibition efficiency and the related microstructural changes in shale rocks. The study highlights the importance of replicating in-situ pressure conditions in future research and provides valuable insights for optimizing gas recovery strategies in shale gas reservoirs.

The microscopic heterogeneity of pore-throat structures in tight sandstone is a crucial parameter for understanding the transport mechanism of fluid flow. In this work, we firstly developed the new procedure to characterize the pore size distribution (PSD) and throat size distribution (TSD) by combining the nuclear magnetic resonance (NMR), cast thin section (CTS), and constant-rate mercury injection (CRMI) tests, and used the permeability estimated model to verify the full-scale PSD and TSD. Then, we respectively analyzed the fractal feature of the pore and throat, and characterized the heterogeneity of pores and throats. Finally, we elaborated the effect of the pore and throat heterogeneity on the gas-phase seepage capacity base on the analysis of the simple capillary tube model and gas-flooding experiment. The results showed that (1) The PSD and TSD of the tight sandstone sample ranged from 0.01 to 10 μm and from 0.1 to 57 μm, respectively, mainly contributed by the micropores and mesopores. Meanwhile, the permeability estimated by the PSD and TSD was consistent with the experimental permeability, and relative error was lower than 8%. (2) The PSD and TSD exhibited multifractal characteristics, and singularity strength range, Δα, could be used as the indicator for characterizing the heterogeneity of pore and throat. Furthermore, the throat of the sample showed stronger heterogeneity than that the pore. (3) The throats played an important role for the fluid transport in the tight sandstone, and the effect of the throat heterogeneity on the gas-phase seepage capacity was different under the lower and higher injection pressure. The macropores and micropores maybe respectively become the preferential migration pathways at the lower and higher injection pressure. In the end, the identification plate was established in our paper, and could be described the relationship among the throat heterogeneity, injection pressure, permeability and flow path of the gas phase in the tight sandstone.