The understanding of water adsorption and desorption behavior in the shale rocks is of great significance in the reserve estimation, wellbore stability and hydrocarbon extraction in the shale gas reservoirs. However, the water sorption behavior in the shales remains unclear. In this study, water vapor adsorption/desorption isotherms of the Longmaxi shale in the Sichuan Basin, China were conducted at various temperatures (30 °C, 60 °C) and a relative pressure up to 0.97 to understand the water sorption behavior. Then the effects of temperature and shale properties were analyzed, and the water adsorption, hysteresis, saturation and capillary pressure were discussed. The results indicate that water adsorption isotherms of the Longmaxi shale exhibit the type II characteristics. The water molecules initially adsorb on the shale particle/pore surfaces at low relative pressure while the capillary condensation dominates at high relative pressure. Temperature favors the water sorption in the shales at high relative pressure, and the GAB isotherm model is found to be suitable for describe the water adsorption/desorption behavior. The high organic carbon and full bedding are beneficial to water adsorption in the shales while the calcite inhibits the behavior. There exists the hysteresis between water adsorption and desorption at the whole relative pressure, which suggests that the depletion of condensed water from smaller capillary pores is more difficult than that from larger pores, and the chemical interaction contributes to the hysteresis loop for water sorption. The capillary pressure in the shales can be up to the order of several hundreds of MPa, and thus the desorption of water from the shales may not be as easy as the water adsorption due to the high capillary pressure, which results in water retention behavior in the shale gas reservoirs. These results can provide insights into a better understanding of water sorption behavior in the shale so as to optimize extraction conditions and predict gas productivity in the shale gas reservoirs.

Pore structures determine reservoir storage capacity, control rock transportation characteristics and represent microscopic properties of the rock. Therefore, the characterization and quantification of the pore structures of tight oil and gas reservoir are of primary importance for quality evaluation and the successful production of these unconventional resources. In this study, we obtained X-CT images with two resolutions of the same tight sandstone and studied the pore structures and heterogeneity of tight sandstone using digital rock technology combined with fractal theory. In traditional Euclidean space, digital image analysis shows that the pore structure of tight sandstone is mainly flat, isolated pores that occupy a large number ratio in high-resolution images and a large volume ratio in low-resolution images. Most seepage channels are mainly composed of large pores. The porosity analysis of 2D and 3D suggests that the representative elementary volume of low-resolution digital rock is 300 voxels, and the axial heterogeneity of tight sandstone is stronger than the bulk heterogeneity. In non-Euclidean space, fractal characterization parameters indicate that the fractal dimension (FD) of low-resolution digital rock is 2.6548, that of high-resolution digital rock is 2.6194, and the FD of tight sandstone is insensitive to imaging resolution. The lacunarity of high-resolution digital rock is obviously larger than that of low-resolution digital rock, which suggests that lacunarity can be used to analyze the heterogeneous structures with similar FD of tight sandstone precisely.

The gas transport in shale nanopores is always one of the major concerns in terms of the development of shale gas reservoirs. In this study, the gas flow regimes in shale nanopores were classified and analyzed according to Knudsen number. Then the gas flow model considering Darcy flow, slip flow, transition flow, molecular free flow and adsorption effect was proposed to evaluate the gas flow behavior in shale nanopores. The result shows that the contributions of Darcy flow, slip flow and transition flow in shale nanopores are reciprocal, and are mainly dominated by pore radius and pressure. The adsorption effect greatly influences the total mass flux. The total mass flux will increase as Langmuir pressure and temperature increase while it will decrease with reservoir pressure and the adsorption thickness. These results can provide insights for a better understanding of gas flow in the shale nanopores so as to optimize the production performance of shale gas reservoirs.

Analysis of the in situ stress orientation and magnitude in the No. 4 Structure of Nanpu Sag was performed on the basis of data obtained from borehole breakout and acoustic emission measurements. On the basis of mechanical experiments, logging interpretation, and seismic data, a 3D geological model and heterogeneous rock mechanics field of the reservoir were constructed. Finite element simulation techniques were then used for the detailed prediction of the 3D stress field. The results indicated that the maximum horizontal stress orientation in the study area was generally NEE–SWW trending, with significant changes in the in situ stress orientation within and between fault blocks. Along surfaces and profiles, stress magnitudes were discrete and the in situ stress belonged to the Ia-type. Observed inter-strata differences were characterized as five different types of in situ stress profile. Faults were the most important factor causing large distributional differences in the stress field of reservoirs within the complex fault blocks. The next important influence on the stress field was the reservoir’s rock mechanics parameters, which impacted on the magnitudes of in situ stress magnitudes. This technique provided a theoretical basis for more efficient exploration and development of low-permeability reservoirs within complex fault blocks.

In southern Sichuan Basin, the main production layers are characterized by deeply buried, high stress difference, and complex structural conditions. The Luzhou area is far from large faults, and natural fractures are greatly important for shale gas storage and production. Multi-scale natural fractures control the migration, enrichment, and preservation conditions of shale gas, and facilitate the formation of complex fracture network under the action of hydraulic fracturing. In this study, based on the outcrops, drilling cores, geochemical tests, thin section, and other experiments, the development characteristics of the Wufeng-Longmaxi shale in the Luzhou block, Southern China, are statistically analyzed, and the controlling factors (e.g., tectonic factors, organic matter, mineral components, mechanical properties) are discussed in details. Fractures observed in the outcrops are mainly regional fractures with two groups of orthogonal joints. Similarly, fractures observed in the core are also mainly joints fractures perpendicular to the laminae with three typical features (high-density, high-angle, and unfilled). In detail, steeply dipping fractures (75-90°) account for 78.1% of all fractures, with 85.1% being unfilled, 78.1% having a longitudinal extension less than 4 cm, and 65.1% having a spacing less than 2 cm. In brief, there exist cross-scale similarity among outcrops, cores, and microscopic thin sections, which is critical to the shale gas preservation conditions. Based on this understanding, further research is conducted on the relationship between the fracture density and gas content, which shows that (i) when the fracture density is less than 122 number/m, TOC content and fracture density together positively dominate gas content; (ii) when fracture density exceeds 122 number/m, gas content appears negative with fracture density, and TOC content is not the critical factor anymore. The above study establishes quantitative limits for shale gas preservation in the study block. It may assist in providing references for determining the sweet spot area and further deep shale gas exploration and development in the southern Sichuan Basin.