Deep shale gas reservoirs are vital for the future development of China’s natural gas industry. Presently, China has achieved preliminary industrial exploitation in this regard, as evidenced by the successful drilling of several high-yielding wells, the delineation of the second gas production growing area with estimated gas-in-place of around one trillion cubic meters and gas production of around ten billion cubic meters, and innovative breakthroughs in research on shale gas enrichment pattern together with exploration and exploitation technologies. These have facilitated the large-scale, effective shale gas production growth in China. Meanwhile, the United States has achieved industrial exploitation of four major deep shale gas blocks, leading to constant rise of the shale gas production from deep reservoirs reaching 313.2×10⁹ m³ in 2021, which accounts for up to 41 % of its total natural gas production. Through systematical summary, we determine six major shale gas enrichment characteristics for deep marine reservoirs: (1) deepwater shelf deposits in a strong reducing environment, which are favorable for organic matter enrichment and preservation; (2) high-quality reservoirs with stable thicknesses and a continuous distribution in large scale; (3) prevalent ultra-high pressure with good sealing capacity of faults; (4) well-developed organic pores and fractures, resulting in favorable reservoir physical properties; (5) superior gas-bearing property of deep shales where shale gas resources are available; and (6) a high proportion of free gas in deep shales, leading to high single-well production in the initial stage. Despite these characteristics as well as advancements in the exploration and exploitation of deep shale gas reservoirs in China, three challenges are posed in the study along with corresponding countermeasures for profitable shale gas extraction from deep reservoirs. Prospects show that deep marine shale gas reservoirs in the Sichuan Basin hold discovered shale gas in place of (3～5)×10¹² m³, suggesting potential gas production growth of (30～50)×10⁹ m³. It is suggested to persist in tackling key problems, and accurately build a “transparent geological body” for shale reservoirs by adhering to the philosophy of maximizing producing reserves. Furthermore, we should focus on the optimal engineering techniques and production systems to maximize single-well estimated ultimate recovery (EUR), to continually reduce exploitation costs and consistently surpass current shale gas production limits, with the ultimate purpose of driving further progress in China’s shale gas industry.

Due to the existence of fracturing fluid and formation water in shale gas reservoirs, the coexistence of gas and water in nanopores is prevalent. The pore water in the reservoir, on the one hand, affects gas flow behavior and permeability. On the other hand, it blocks pore throats and occupies adsorption sites on the pore surface, consequently reducing the gas adsorption capacity. The occurrence of pore water in shale reservoirs holds significant importance for shale gas resources exploration and development. In this paper, the shale from the Longmaxi Formation, Sichuan Basin was selected as the research target. The content and micro-distribution behavior of pore water were evaluated through centrifugation-nuclear magnetic resonance experiment and theoretical model. The results demonstrated that the content of free water would be underestimated by the experiment, with 2.55%-6.80% lower than that calculated by theoretical model. Moreover, due to the limitations of nuclear magnetic resonance experiment, the adsorbed water in mesopores and macropores might be mistakenly identified as that in smaller pores. As a result, the theoretical model is more applicable for characterizing the micro-distribution behavior of pore water than the origin nuclear magnetic resonance data.

Temperature and pressure conditions of deep shale are beyond experiment range, and the amount of adsorbed gas is difficult to determine. To predict the adsorbed gas content of deep shales under formation conditions, isothermal adsorption experiments and model building were conducted on shale samples from Longmaxi Formation in China. A temperature-dependent adsorption model based on the Langmuir equation is proposed, which can be well-fitted by observed isotherms with a high correlation coefficient. Based on the fitted parameters at 303.15 K, the isothermal adsorption curves at 333.15 K, 363.15 K, and 393.15 K are predicted, showing a good agreement with experimental curves available. Compared with previous prediction methods, the biggest advantage of the proposed method is that it can be carried out only based on one-time isothermal adsorption experiment. Based on the predictions, the downward trend of the excess adsorption curves will slow down under high temperature and pressure conditions, and when the pressure reaches a certain level (> 80 MPa), the temperature has little effect on the excess adsorption capacity. While for absolute adsorption, the gas adsorption reaches saturation much slowly at high temperature, it can also reach saturation under formation pressure. Under the burial depth of marine shale, temperature plays a major role in controlling the adsorbed gas, resulting in the decrease of adsorbed gas content in deep shale, and its ratio will further decrease as the depth increases.

Understanding the methane adsorption mechanism is critical for studying shale gas storage and transport in shale nanopores. In this work,we conducted low-pressure nitrogen adsorption (LPNA),scanning electron microscopy (SEM),and high-pressure methane adsorption experiments on seven shale samples from the Longmaxi formation in Sichuan basin. LPNA and SEM results show that pores in the shale samples are mainly nanometersized and have a broad size distribution. We have also shown that methane should be not only adsorbed in micropores (< 2 nm) but also in mesopores (2-50 nm) by two hypotheses. Therefore,we established a novel DA-LF model by combining the micropore filling and monolayer coverage theories to describe the methane adsorption process in shale. This new model can fit the high-pressure isotherms quite well,and the fitting error of this new model is slightly smaller than the commonly used D-A and L-F models. The absolute adsorption isotherms and the capacities for micropores and mesopores can be calculated using this new model separately,showing that 77% to 97% of methane molecules are adsorbed in micropores. In addition,we conclude that the methane adsorption mechanism in shale is: the majority of methane molecules are filled in micropores,and the remainder are monolayer-adsorbed in mesopores. It is anticipated that our results provide a more accurate explanation of the shale gas adsorption mechanism in shale formations.