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Mercury intrusion porosimetry (MIP) has been utilized for decades to obtain the pore size, pore volume and pore structure of variable porous media including inorganic rocks and organic rock (e.g., shales and coals). Diffusivity and permeability are the two crucial parameters that control gas transport in coals. The main purpose of this work is to derive the CH 4 effective gas diffusivity and permeability in different rank coals with vitrinite reflectance of 0.46-2.79% R o,m by MIP. Furthermore, regular CH 4 diffusivity and permeability measurements are conducted to compare with the results of the derived CH 4 diffusivity and permeability with MIP data. In this work, CH 4 diffusivity and permeability of different rank coals are acquired with established equations, which are basically in accordance with the experimental values. However, the coal rank (maximum vitrinitere flectance, R o,m) exhibits no significant relation to the effective diffusion coefficient (De) and gas diffusivity (D). The cementation factor (m values) varies from 2.03 to 2.46, which tends to exhibit a semi-consolidated structure for coals compared with other rocks (e.g., dolomite, limestone, sandstone and red brick). The results show that the cementation factor could be an important factor for gas flow in coals. The correlation of CH 4 diffusivity to porosity and permeability of 12 coal samples were explored, and it appears that CH 4 diffusivity exhibits an increasing trend with an increase of permeability, and two different exponential relationships respectively exist in diffusivity versus porosity and permeability versus porosity. Therefore, this study could be conducive to gas sequestration or gas production during enhanced coalbed methane (CBM) recovery.

Quantitative characterization of multiphase methane and investigation of the methane dynamic adsorption process of coals were performed by a low-field nuclear magnetic resonance (NMR) method. Meanwhile, methane diffusion behaviors during the step-by-step pressurization adsorption process were evaluated by three diffusion models. The results indicate that the transverse relaxation time (T 2 ) spectra of methane demonstrate two distinct peaks of adsorbed methane (P1, T 2 < 2.5 ms) and porous mediumconfined methane (P2) at a low-pressure step (∼1.0 MPa), and the third peak of bulk methane (P3) obviously appears when the pressure >2.0 MPa. The integrated T 2 amplitude of adsorbed methane increases quickly during the first 2 h (>75% of total) and then gradually reaches a maximum value in the last 4 h during the initial pressure step of ∼1.0 MPa, whereas it reaches >90% of total amplitude in 1 h as the pressure is increased step-by-step. According to the strong linear relationship between the adsorbed methane volume and the integrated T 2 amplitude, the real-time methane adsorption volume can be determined, and adsorption isotherms from the NMR method are found to be mostly overlapped with those of the volumetric method. Moreover, the effective diffusion coefficient of the unipore model (10 −6 to 10 −5 s −1 ) coincides with the micropore diffusion coefficient of the bidisperse model and the slow diffusion coefficient of the multiporous model, which is generally 1−3 orders of magnitude less than the macropore diffusion coefficient (10 −3 to 10 −2 s −1 ) and the fast diffusion coefficient (10 −2 s −1 ) or transitional diffusion coefficient (10 −4 to 10 −3 s −1 ). The dynamic changes in diffusion parameters with pressure may be related to the comprehensive effects of methane diffusion mechanisms and coal matrix swelling under different adsorption pressures.

Exploring the compressibility of the deeply buried marine shale matrix and its controlling factors can help achieve efficient petroleum production. Taking ten sets of deeply buried marine shale core samples from Ning228 wells in the Yanjin area as an example, the matrix compressibility and pore characteristics of deeply buried marine shale reservoirs were investigated by applying mercury intrusion porosimetry (MIP) and nitrogen adsorption/desorption isotherms at a low temperature of 77 K. Mathematical models (based on MIP and nitrogen adsorption/desorption isotherms) were established to analyze the effects of TOC, mineral components, and pore structure on matrix compressibility. The relationship between the compressibility coefficient and the brittleness index was also established. The results show that the compressibility of the shale matrix is significant when the mercury injection pressure ranges from 8.66 to 37 MPa. For deeply buried marine shale, the matrix compressibility is in the range of 0.23 × 10−4–22.03 × 10−4 MPa−1. The influence of TOC and minerals on matrix compressibility is mainly reflected in the control effect of pore structure. High TOC content decreases the overall shale elastic modulus, and high clay mineral content enhances shale stress sensitivity, resulting in a significant matrix compressibility effect. For the effect of pore structure on compressibility, the pore content in shale has a positive effect on matrix compressibility. In addition, the pore-specific surface area is critical to the effective variation of shale matrix compressibility, indicating that the complexity of the shale pore structure is a key factor affecting matrix compressibility.

The microstructure of shale reservoirs refers to the distribution of mineral–organic matter, pore–fracture features, diagenetic processes, and their interrelations. The comprehensive and accurate analysis of the shale microstructure plays a critical role in formulating a reasonable development plan and optimizing measures to enhance oil or gas recovery. To explore the microstructure characterization, the mineral and organic matter compositions as well as the pore types and distributions of organic-rich shale reservoirs were investigated using a series of advanced techniques, including focused ion beam–scanning electron microscopy and atomic force microscopy. This review establishes a model of pore distribution of the layered structure of shale reservoirs based on ideal shale laminae model. Among them, quartz and carbonate laminae can be classified as grain laminae clay minerals and organic matter and pyrite can be combined into organic matter aggregate due to the symbiotic relationship between pyrite, organic matter and clay minerals. Microcracks of diverse diagenetic origins can be classified together. This review also systematically summarizes the microcharacterization techniques and different characteristics of organic-rich shale reservoirs, thereby paving the way for the establishment of shale cross-scale characterization techniques.

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Studies on pore structure characterization and its interaction on hydrocarbon retention are the key to understanding shale oil and gas occurrence and accumulation mechanism. To evaluate the evolution of organic pores in marine shales, samples with high organic matter (5.74%) and low thermal maturity (0.67%) were collected from the Neoproterozoic Xiamaling Formation (Pr 3 x) in the Xiahuayuan region, Hebei province, northern China. Samples underwent a thermocompression simulation experiment, and the pore development and pore structure heterogeneity during shale thermal evolution were studied by using multiple techniques, including CO 2 and N 2 physisorption, mercury intrusion porosimetry, and field emission scanning electron microscopy. Meanwhile, the interaction mechanism between pore structure and hydrocarbon retention was revealed by the extraction of residual oil and fractal analyses. Results demonstrated that there is a two-stage interaction relationship between residual hydrocarbons and pore structure: (1) before 400 °C (R o = 1.25%), the pore structure mostly restricts the expulsion of hydrocarbons and (2) after 400 °C, the pore structure is primarily controlled by hydrocarbon expulsion and retention. Mesopores at 2−50 nm in diameters have the greatest effect on hydrocarbon retention, followed by macropores (>50 nm) and micropores (<2 nm). Residual hydrocarbons affect shale porosity by occupying a large amount of mesoporous space in shales, and the effect of pore surface heterogeneity on hydrocarbon retention is greater than that of pore structure heterogeneity. This study provides insights into pore structure evolution of a marine shale along the thermal maturity to further improve the pore development model for effective petroleum production.

Exploring the relationship between formation pressure and shale pore evolution is helpful for the enrichment and development of marine shale gas accumulation theory. The thermal evolution experiment was carried out on the Xiamaling Formation (Pr3x) lowly matured marine shale, which has a similar sedimentary environment to the Longmaxi Formation (S1l) highly matured marine shale. Comparative experiments of open and semi-closed pyrolysis and multiple pore structure characterization techniques, including CO2 and N2 physisorption, mercury intrusion porosimetry, and field emission scanning electron microscopy, were conducted. The marine shale pore evolutionary model under formation pressure is proposed by characterizing pore evolution, and hydrocarbon expulsion and retention for shales under and without formation fluid pressures. The results show that the existence of formation pressure increases the percentage of quartz and reduces the content of clay minerals. The change in formation pressure has no obvious effect on the maturity evolution of shale samples. With the increase of formation pressure, the pore morphology of shale gradually changes from narrow slit pores to ink bottle-shaped pores. The retained hydrocarbons in shale mainly occupy the mesopore space, and the existence of formation pressure promotes hydrocarbon expulsion, especially the hydrocarbon expulsion in the mesopore. In addition, formation pressure improves pore connectivity, especially in the high-over mature stage of shale. With the increase of formation pressure, the micropore volume decreases slightly, the mesopore volume increases significantly, and the macropore volume changes have two stages.