Micro- and nano-scale pores develop in shale reservoirs, and the associated pore structure controls the occurrence state, gas content, seepage capacity, and micro-migration and accumulation mechanisms of shale gas. For this study, we mainly conducted tests, using field emission-scanning electron microscopy, of the isothermal methane adsorption of powder-sized samples under high temperatures (60–130 °C) and pressures (0–45 MPa), along with methane-saturated nuclear magnetic resonance tests of plug-sized samples under different temperatures (60–100 °C) and pressures (0–35 MPa). These samples were from Longmaxi shale cores from strata at different burial depths from the Zhaotong, Weiyuan, and Luzhou areas. As the burial depth increases, organic pores transform from complex networks to relatively isolated and circular pore-like structures, and the proportion of organic matter-hosted pores increases from 25.0% to 61.2%. The pore size is influenced by the pressure difference inside and outside the pores, as well as the surface tension of organic matter in situ. As the burial depth increases to 4200 m, the main peak of the pore size first increases from 5–30 nm to 200–400 nm and then decreases to 50–200 nm. This work establishes an NMR method of saturated methane on plug-sized samples to test the free gas content and develop a prediction model of shale reservoirs at different burial depths. The gas content of a shale reservoir is influenced by both burial depths and pore structure. When the burial depth of the shale gas reservoir is less than 2000 m, inorganic pores and microfractures develop, and the self-sealing ability of the reservoir in terms of retaining shale gas is weak, resulting in low gas content. However, due to the small pore size of organic pores and the low formation temperature, the content of adsorbed gas increases, accounting for up to 60%. As the burial depth increases, the free gas and total gas content increase; at 4500 m, the total gas content of shale reservoirs is 18.9 m³/t, and the proportion of free gas can be as high as 80%. The total gas content predicted by our method is consistent with the results of the pressure-holding coring technique, which is about twice our original understanding of gas content, greatly enhancing our confidence in the possibility of accelerating the exploration and development of deep shale gas.

To mitigate the exploration and development risks, it is necessary to have a deeper understanding of the formation mechanism and gas-bearing control factors of low-resistance shale reservoirs. This study focuses on typical shale gas wells (including low-resistivity wells) in Luzhou area, and identification criteria for low-resistance shale reservoirs are redefined as resistivity less than 10 Ω·m and continuous formation thickness greater than 6 m. At the macro scale, low-resistivity shale reservoirs are characterized by high clay mineral content and high water saturation with low gas content. At the micro scale, the main pore size is less than 10 nm, with a small total pore volume but a large specific surface area. Shale reservoirs close to the Class II fault have high water saturation and strong compaction, which hinders the mutual transformation between minerals, resulting in low-resistivity shale with high clay mineral content, small pore volume, and pore size, which promotes the enhancement of reservoir conductivity. The gas content of low-resistivity shale reservoirs is lower, because the distance from the Class II fault is closer, resulting in high water saturation and strong diagenesis, which is not conducive to pore development and shale gas accumulation. When the water saturation exceeds 40%, the pore volume of shale reservoirs rapidly decreases to as low as 0.0074 cm³/g. In order to reduce the risk of exploration and development of the area, the well location deployment needs to be more than 2.8 km away from the Class II fault.

Currently, the Longmaxi shale in the Sichuan Basin is the most successful stratum of shale gas production in China. However, because Longmaxi shale mostly has high over-maturity, a low-maturity sample cannot be obtained for gas generation thermal simulations, and as a result, a gas generation model has not yet been established for it. Therefore, models of other shales are usually used to calculate the amount of gas generated from Longmaxi shale, but they may produce inaccurate results. In this study, a Longmaxi shale sample with an equivalent vitrinite reflectance calculated from Raman spectroscopy (EqVR_o) of 1.26% was obtained from Well Yucan 1 in the Chengkou area, northeast Sichuan Province. This Longmaxi shale may have the lowest maturity in nature. Pyrolysis simulations based on gold tubes were performed on this sample, and the gas generation line was obtained. The amount of gas generated during the low-maturity stage was compensated by referring to gas generation data obtained from Lower Silurian black shale in western Lithuania. Thus, a gas generation model of the Longmaxi shale was built. The model showed that the gas generation process of Longmaxi shale could be divided into three stages: (1) First, there is the quick generation stage (EqVR_o 0.5–3.0%), where hydrocarbon gases were generated quickly and constantly, and the generation rate was steady. A maximum of 458 mL/g TOC was reached at a maturity of 3.0% EqVR_o. (2) Second, there is the stable stage (EqVR_o 3.0–3.25%), where the amount of generated gas reached a plateau of 453–458 mL/g TOC. (3) Third, there is the rapid descent stage (EqVR_o > 3.25%), where the amount of generated gas started to decrease, and it was 393 mL/g TOC at an EqVR_o of 3.34%. This model allows us to more accurately calculate the amount of gas generated from the Longmaxi shale in the Sichuan Basin.

Micro-pores and micro-fractures constitute the most vital reservoir spaces and seepage pathways for shale gas. Conducting an in-depth study of pore-fracture combination types within shale gas reservoirs is beneficial for understanding shale gas enrichment and exploitation. In this study, we conducted a joint experiment involving MICP and WM impregnation on the main gas-producing layer of Longmaxi formation shale reservoir from five shale gas wells in the Luzhou area. This study achieved the visualization of MICP experiments, enabling a quantitative classification of pore volume and micro-fracture volume within the shale reservoir. A Q_P-F parameter system for classifying pore-fracture combination types has been established to evaluate pore-fracture connectivity, which are categorized into three types. The strongly connected pore-fracture type (SCPFT) shale gas reservoir in the study area has the characteristics of high porosity, high gas content and strong pore-fracture connectivity, which is the preferred target for shale gas exploration and development. Moderately connected pore-fracture type (MCPFT) and weakly connected pore-fracture type (WCPFT) shale gas reservoirs exhibit significant variations in porosity and gas content, coupled with weak pore-fracture connectivity. Despite some of these reservoirs possessing high porosity and gas content, they fail to achieve high production rates. Therefore, during the development of these two types of shale gas reservoirs, it is imperative to enhance and optimize fracturing techniques to create a more intricate fracture network structure, thereby enabling the release of shale gas trapped in poorly connected pores. This research holds significant theoretical and practical implications for identifying optimal shale gas development zones and improving gas recovery efficiency.

The phenomenon of pressure-solution (PS) is widespread in deep marine shale reservoirs of the Longmaxi Formation in the Sichuan Basin, affecting pore development. However, systematic reports on the study of PS in shale reservoirs are yet to be seen. This study performed large-field scanning electron microscopy, mineral quantitative identification, low-pressure gas adsorption, and high-pressure mercury injection experiments on shale cores from the Longmaxi Formation. The pore structure characteristics and the PS process of deep shale reservoirs were clarified, a semi quantitative analysis method for PS was constructed, and the influence of PS on pore development was explored. Our results demonstrate that PS is widely present in deep gas shale reservoirs, primarily manifesting in the form of mineral transformation and fusion, particularly involving clay and quartz minerals. This process alters the mineral composition and particle size of the shale reservoirs. A semi-quantitative analysis method for PS and the action strength parameter Q_P has been established, based on the mineral composition and particle size of shale reservoirs. This parameter exhibits a positive correlation with burial depth, water saturation, and quartz content. The primary effect of PS on pore development is that, as mineral transformation results in an elevation of quartz content and an increase in particle size, pore dimensions undergo compression and subsequently diminish. This underscores why shale reservoirs containing over 70% quartz are unfavorable for pore development. Therefore, when the water saturation in the Longmaxi Formation shale reservoir exceeds 40% and the quartz content surpasses 70%, significant risks are present in the exploration and development of shale gas.

The geochemical properties of fracturing flowback fluids indirectly indicate the fracturing efficiency of the reservoir, the interaction between the reservoir and injected water, and the preservation of oil and gas, thereby offering robust data support for identifying fracturing flowback fluid sources, assessing fracturing effects, and proposing stimulation strategies. In this study, the ion characteristics, total salinity, and stable isotope ratio of fracturing flowback fluids of the Z202H1 and Z203 wells in Western Chongqing were measured. The findings suggest that with the extension of flowback time, the geochemical properties of fracturing flowback fluids evolve toward higher salinity and heavier stable isotope ratios, ultimately stabilizing. Upon comparing the water–rock reaction intensity and the rate of total salinity increase in the fracturing flowback fluids, it is concluded that fracturing flowback fluids contain a mixture of formation water. Because water–rock reactions elevate the total salinity of fracturing flowback fluids, we introduce the Water–Rock Reaction Intensity Coefficient (I_R) to denote the intensity of these reactions. Based on the I_R value, the binary mixture model for fracturing fluids in fracturing flowback fluids was adjusted. With the increase in flowback time, the content of fracturing fluids in fracturing flowback fluids of Z202H1 and Z203 stabilized at about 55% and 40% respectively. During the same flowback period, the fracturing flowback fluids of the Z203 well exhibit a higher total salinity, a heavier stable isotope ratio, a greater I_R, and a lower fracturing fluid content in fracturing flowback fluids. This suggests that the fracturing effect of the Z203 well is superior to that of the Z202H1 well, leading to a higher production capacity of the Z203 well.