The paleoenvironment of shales can be reconstructed to some extent using the combinations or concentrations of elements that correlate strongly with environmental conditions. In this study, we analyzed rare earth elements (REEs), major elements, and trace elements in the marine-continental transitional shales (transitional shales for short) of the Shan 2³ submember of the Shanxi Formation in the southeastern Ordos Basin. The purpose is to deduce the paleoenvironmental conditions of the shales, encompassing paleoredox, paleoclimate, paleoproductivity, and paleo-provenance. The Shan 2³ submember comprises four sections, namely Shan 2³-1, Shan 2³-2, Shan 2³-3, and Shan 2³-4. The Ba/Al, P/Al, and Cu/Al ratios, along with biogenic barium (Ba_bio), indicate that the paleoproductivity of the submember peaked during the Shan 2³-1 deposition and exhibited a downtrend upward in other sections. Trends in the U_au and the Ni/Co, V/Cr, U/Th, and V/Sc ratios suggest that suboxic conditions prevailed during the Shan 2³-1 deposition, with the oxidation level gradually increasing from Shan 2³-1 to Shan 2³-4. C-value and the Sr/Cu vs. Ga/Rb cross-plot indicate a warm and arid paleoclimate during the Shan 2³-1 deposition, which transitioned to cooler, drier conditions during the deposition of other sections. Indicators sensitive to paleoclimate, such as the K/Rb and Th/U ratios, along with the ICV, PIA, and Chemical Index of Alteration (CIA), highlight elevated weathering from Shan 2³-2 to Shan 2³-4, with Shan 2³-1 exhibiting the weakest weathering during its deposition. As suggested by the REE data, the Zr/Sc vs. Th/Sr cross-plot, provenance discriminant functions, and the cross-plots of Hf vs. La/Th, Th vs. Hf–Co, and ∑REE vs. La/Yb, the sedimentary provenance for the transitional shales of the Shan 2³ submember is of multiple origins, with significant contributions from the Upper Continental Crust (UCC). Discriminant diagrams, including those of Th–Co–Zr/10, Th–Sc–Zr/10, La–Th–Sc, and K₂O/Na₂O vs. SiO₂, suggest that the transitional shales of the Shan 2³ submember were primarily deposited under tectonic settings such as continental island arcs (CIAs) and passive continental margins (PCMs).

Deeply buried (>3500 m) marine shale has become a focus point for the future exploration and exploitation of shale hydrocarbon in China. Low-temperature nitrogen adsorption (LTNA), scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and other experiments were combined to characterize the pore structure and fluid division in deep-marine shale of the southern Sichuan Basin in this study. The results suggest that the deep-marine shale had a relatively developed nanopore network, especially with honeycomb organic pores. These organic pores were largely macropores with good connectivity in three-dimensional space and constituted the major reservoir space of the deep-marine shale gas. Microfractures were predominantly clay-mineral-related fractures, and the development degree of microfractures connected with organic pores was low, which contributed to the preservation of organic pores. Within the deep-marine shale interval, the pore volumes of Section 1 and Section 3 were higher. Pore volume was predominantly contributed by pores above 10 nm, where macropores accounted for a large proportion. Based on a combination of high-speed centrifugation and gradient temperature drying, the pore fluid of deep-marine shale reservoirs was quantitatively classified into four types: clay-bound fluid, capillary-bound fluid, free-flowing fluid, and closed-pore fluid. The clay-bound fluid existed in pores of less than 4.25 nm, which cannot be exploited. Quantitative division of the shale pore system could be realized by using the pore space differences of different types of fluids.

The fractal dimension quantitatively describes the complexity of the shale pore structure and serves as a powerful tool for characterizing the evolution of shale reservoirs. Thermal simulation experiments were conducted on the low-maturity transitional shale from the Shanxi Formation in the Ordos Basin. The initial samples consisted mainly of quartz (39.9%) and clay minerals (49.9%) with moderate-to-good hydrocarbon generation potential. Samples from different thermal maturation stages were analyzed through geochemical, mineralogical, and pore structure experiments to reveal the evolution of mineral compositions and pore structure parameters. The fractal dimensions of the pore structure were calculated using both the FHH and capillary bundle models. Correlation coefficients and principal component analysis (PCA) were employed to explore the factors influencing the fractal dimension and its evolutionary patterns during reservoir development. The results indicate that (1) with increasing thermal maturity, the quartz content gradually increases while the contents of clay minerals, carbonate minerals, pyrite, and feldspar decrease. (2) The evolution of porosity follows five stages: a slow decrease (0.78 < Ro < 1.0%), a rapid increase (1.0% < Ro < 2.0%), a relatively stable phase (2.0% < Ro < 2.7%), a rapid rise (2.7% < Ro < 3.2%), and a slow decline (Ro > 3.2%). The evolution of the pore volume (PV) and specific surface area (SSA) indicates that the proportion of pores in the 5–20 nm and 20–60 nm ranges gradually increases while the proportion of pores smaller than 5 nm decreases. (3) The fractal dimension of shale pores (D₁, average value 2.61) derived from the FHH model is higher than D₂ (average value 2.56). This suggests that the roughness of pore surfaces is greater than the complexity of the internal pore structure at various maturities. The D_M distribution range calculated from the capillary bundle model was broad (between 2.47 and 2.94), with an average value of 2.84, higher than D₁ and D₂. This likely indicates that larger pores have more complex structures. (4) D₁ shows a strong correlation with porosity, PV, and SSA and can be used to reflect pore development. D₂ correlates well with geochemical parameters (TOC, HI, etc.) and minerals prone to diagenetic alteration (carbonates, feldspar, and pyrite), making it useful for characterizing the changes in components consumed during pore structure evolution. (5) Based on the thermal maturation process of organic matter, mineral composition, diagenesis, and pore structure evolution, an evolutionary model of the fractal dimension for transitional shale was established.

Pore structure plays a critical role in evaluating shale “sweet spots”. Compared to marine shale, lacustrine shale has more diverse lithofacies types and greater heterogeneity in pore structure due to frequently changing environmental conditions. Using methods such as mercury intrusion porosimetry (MIP), field emission scanning electron microscopy (FE-SEM), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD), this study investigates the micropore structures and heterogeneity of different lithofacies in the Jurassic Dongyuemiao Member lacustrine shale. Image processing and multifractal theory were employed to identify the controlling factors of pore structure heterogeneity. The key findings are as follows. (1) Based on mineral content and laminae types, the lithofacies types of Dongyuemiao lacustrine shale are classified into four types: shell–laminae mixed shale (SLMS), silty–laminae clay shale (SLCS), clast–laminae clay shale (CLCS), and clay shale (CS). (2) Based on genesis, shale reservoirs’ pore and permeability space are categorized into inorganic pores, organic pores, and micro-fractures. Inorganic pores consist of inter-particle pores and intra-particle pores. Pore size distribution curves for all four lithofacies exhibit two main peaks, with pore sizes concentrated in the ranges of 2–10 nm and 50–80 nm. Mesopores and macropores dominate, accounting for over 80% of the total pore volume. Mesopores are most developed in CLCS, representing 56.3%. (3) Quartz content is positively correlated with the multifractal dimension, while clay content shows a negative correlation. Higher quartz content, coupled with lower clay content, weakens pore structure heterogeneity. A negative correlation exists between total organic carbon (TOC) and the multifractal dimension, indicating that higher organic matter content enhances organic pore development and increases microscopic heterogeneity. (4) Porosity heterogeneity in SLMS is effectively characterized by D₀-D_max, while in the other three lithofacies, it is characterized by D_min-D₀. Permeability across all lithofacies correlates with D₀-D_max. In CS, SLMS, and SLCS, permeability is positively correlated with D₀-D_max, with higher values indicating greater permeability heterogeneity. In CLCS, permeability is negatively correlated with D₀-D_max, such that lower values reflect stronger heterogeneity.

The Xixiangchi Formation is a significant replacement stratum for natural gas production of deep marine carbonate in the Sichuan basin, which is mainly composed of grain shoal. Basic characteristics and corresponding major controlling factors of the Xixiangchi reservoir are of great importance for hydrocarbon exploration, but the diagenesis sequence and evolution of the reservoir are poorly understood because of their complexity. Based on core and thin-section observations, cathodoluminescence (CL), scanning electron microscopy (SEM), and microbiologically induced calcium carbonate precipitation (MICP) data, it is suggested that the Xixiangchi reservoir is comprised of medium crystalline dolostone and grain dolostone in the Central Sichuan basin, with an average porosity of 3.6% and 2.2%, respectively. The corresponding pore-throat type is an intercrystalline pore with a flaky throat and a dissolved intergranular pore with a necking throat. The majority porosity ranges from 2% to 4% (with a distribution frequency of 64.9%), but the permeability distribution is relatively scattered (with a distribution frequency between 10% and 30%). The capillary pressure curve of medium crystalline dolostone is characterized by coarse skewness, relatively flat plateaus, low displacement pressures, and high mercury saturation at relatively low injection pressures. The capillary pressure curve of grain dolostone is characterized by fine skewness, which exhibits relatively poor connectivity and a small value of median pore radius. The deposition of intraplatform grain shoals determines the original property of the Xixiangchi Formation reservoirs. Destructive diagenesis, including compaction and multistage cementation, decreases the physical properties of the Xixiangchi reservoir. Constructive diagenesis, including Caledonian supergene karstification and late-stage burial dissolution, tremendously improves the reservoir quality.

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.