Determination of water occurrence in gas shale reservoirs is vital for understanding the gas storage and migration behavior. Clay, kerogen, and shale samples with different water contents were analyzed based on the 2D NMR technology to decipher the characteristic of water occurrence in different shale compositions. By establishing a new classification method of water in shale, the water absorption characteristics of shale during hydraulic fracturing and the law of water mobilization in shale reservoirs during development are quantitatively analyzed. The results suggest that the water in shale can be classified as mobile water and immobile water, with the boundary T 1 = 0.1 ms. The mobile water can be further divided into clay bound water, capillary bound water, and free water by the T 1 −T 2 map. Most of the water in shale is clay bound water, which is also the most important object in the study of fracturing fluid retention. The influence of free water and clay bound water on the gas−water two-phase flow of shale is greater. Accurate analysis of different types of water in shale can clarify their different effects on methane occurrence and migration. This study overcomes the shortcomings of inaccurate quantitative analysis of water in shale by traditional methods and provides help for the analysis of fracturing fluid retention law and the development effect of gas wells.
Recently, deep shale reservoirs are emerging as time requires and commence occupying a significant position in the further development of shale gas. However, the understanding of pore characteristics in deep shale remains poor, prohibiting accurate estimation of the hydrocarbon content and insights into fluid mobility. This study focuses on the Longmaxi Formation from the Luzhou (LZ) region, southern Sichuan. Scanning electron microscopy (SEM), low-temperature N2/CO2 adsorption, X-ray diffraction, and geochemical analysis were performed to investigate the micro–nanopore size distribution, main controlling factors, and unique pore features distinct from other regions. Results showed that the pores can be classified into four categories, organic matter (OM) pores, intergranular pores, intragranular pores, and microfractures, according to SEM images. The total pore volume is overwhelmingly dominated by mesopores and contributed by pores in the range of 0.5–0.6, 2–4, and 10–30 nm. The specific surface area is primarily contributed by micropores and mesopores in the range of 0.5–0.7 and 2–4 nm. By analyzing the influencing factors extensively, it is concluded that the buried depth, geochemical factors, and mineral composition can impact the pore structure in the overmature deep shales. Specifically, the total organic carbon content plays a more effective and positive role in the development of micropores, mesopores, total pores, and the porosity when compared with vitreous reflectance (Ro). The micropores are inferred to be OM-related. On the contrary, clay mineral is detrimental to the development of micropores and mesopores and the petrophysical properties (porosity and permeability), which may be attributed to the occurrence of chlorite and kaolinite instead of illite. The plagioclase conforms to the same law as clay due to their coexistence. Quartz, carbonate minerals, and pyrite can barely contribute to the pores. Eventually, the compared results suggest that the Longmaxi Formation of the LZ region are qualified with a superior pore size distribution, complicated structure, and diverse morphology, implying a potential to generate and store hydrocarbons. Overall, this study improves the understanding of complex pore structures in deep shale and provides significant insights into the development and exploration of unconventional resources in the future.
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