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In lots of reports, improvement of shale percolation ability by shale-hydration has been reported, some researchers even regard low hydraulic fluid flowback rate as an advantage; they mainly focused on inorganic pores and fractures because brittleness of inorganic minerals decides the fracturing effects, but organic pores occupy large proportion of shale pores. In order to discover the moisture influence on organic pores, we prepare 4 samples by adjusting water content reaching 9.37%, 35.97%, 61.6%, and 80.45% and observe and quantitatively analyze 10,343 pore changes before and after processing of the 4 samples through SEM and image processing software, respectively, meanwhile, match the incremental water invasion rate curve with the dry pore size distribution curve. We also compare the water invasion mass of normal shale sample and organic partially removed sample. This paper first visually observes and counts the influence of hydration on organic shale pores through analysis of pore number, diameter, kurtosis, median, area, and characteristic lengths; discovers hydration and dehydration jointly cause the expected changes; the whole procedure contains two opposite mechanisms, pore closure or deformation caused by squeeze and enlarged pores or newborn fractures caused by water flush. Based on experimental and analysis results, conclusions are drawn that organic pores can be influenced by moisture, water flush and clay hydration expansion work jointly, and water flush function is weak when moisture is low, but it becomes stronger with the sufficient moisture. Therefore, sufficient soak time is beneficial to development.

In the process of coalbed methane (CBM) mining, with the decreasing of reservoir pressure, stress sensitivity and matrix desorption shrinkage, which could be called self-regulating effect comprehensively, possess great effect on the gas adsorption due to the changing of pore volume. Therefore, it is necessary to modify the simplified local density (SLD) model to investigate the gas adsorption under reservoir conditions for an accurate prediction of CBM production. For the utilization of SLD adsorption model, assume the pores as slit pore. When pressure is lower than critical desorption pressure and keeps falling, the deformations of specific surface area (SSA) and pore width could be studied by the chosen Shi and Durucan (S&D) model. Furthermore, based on the variation relationship and the modification of SLD model, a new adsorption predicting model could be derived with the consideration of stress sensitivity, and matrix desorption shrinkage. In the absence of stress sensitivity and matrix desorption shrinkage, the calculated consequence is relatively smaller than the actual field adsorption data. What’s more, the sensitivity analyses of Poisson’s ratio, pore volume compressibility and critical desorption pressure are conducted with the application of this new model. At the same reservoir pressure, Poisson’s ratio possesses negative relationship with modified adsorption, while pore volume compressibility and critical desorption pressure both possess positive influence on modified adsorption. The main reason is that Poisson’s ratio affects matrix desorption shrinkage negatively, while pore volume compressibility and critical desorption pressure affect matrix desorption shrinkage positively. In spite of the opposite effect of stress sensitivity and matrix desorption shrinkage on pore deformation, matrix desorption shrinkage exhibits a dominant role in self-regulating.

A clear understanding of pore structure of tight oil reservoirs is essential for reservoir evaluation and enhanced oil recovery. This paper presents a multiscale characterization method using a combination of pressure-controlled porosimetry (PCP), micro-computed tomography (micro-CT), and scanning electron microscopy (SEM). Four tight sandstone samples from Chang 7 Formation in the Ordos Basin were collected for petrophysical characterization. Pore-throat size distributions (PTSDs) for these samples were measured via PCP. A high-resolution micro-CT scan (1 μm/pixel) was used to acquire 3D volumetric images of small core plugs to evaluate pore connectivity of these samples. Additionally, high-resolution digital images were obtained through SEM to identify different pore types. SEM analysis shows that pores in tight sandstones could be classified into four types, i.e., residual interparticle pores, grain dissolution pores, clay pores, and micro-fractures. Residual interparticle pores are often coated by fibrous illite and chlorite. Grain dissolution pores are mainly deduced from the dissolution of grain minerals, among them the feldspar dissolution pore is the primary type. According to the PCP experiments, these samples exhibit multiscale pore structures with a wide range of PTSD from 9.2 nm to 500 μm dominated by nanopores. Average mercury intrusion saturation and permeability contribution value of the dominating nanopores are 63.61% and 80%, respectively. Given the unresolved nanopores, CT images were segmented into three phases, including pore space, grain phase, and clay minerals. The results of connectivity analysis demonstrate that macroscopic pores are mostly connected by clay phases, implying that nanopores provide the critical flow paths. This novel multiscale characterization approach provides us a better understanding of complex pore structures of tight sandstones.

The microstructure characteristics of the reservoir are closely related to the seepage capacity of the reservoir. Compared with conventional reservoirs and low permeability reservoirs, the tight oil is stored in a smaller nanoporous space. The microscopic pore structure of reservoir is the geometrical shape, size, distribution, and interconnected relationship of porosity and throat. The experiment was conducted on several tight rock samples taken from the Chang 7 formation in Xunyi county of Ordos Basin, China. Based on nano-CT scanning and advanced image processing technology Avizo, we build a three-dimensional comprehensive pore and throat network model. In the result of our study, reservoir space types are dissolution pores with mineral particles inside in the pore network model. Then, the pore throat morphology in the forms of small globular and tubular with SEM was explained. There is a big difference in quantity distribution at different locations, which is limited to the permeability of samples. Pore types are mostly round tubular and long tubular, while isolated pores account for a significant proportion. Through making and analyzing the three-dimensional structure of interconnected pores, obtained their specific forms and the division of connectivity types.

Injection of CO2 into shale reservoir is regarded as one potential scenario for CO2 sequestration and enhanced gas recovery (CS-EGR). In this work, a realistic molecular model of kerogen in Chinese Silurian marine black shale was generated using molecular dynamics (MD) simulations. The competitive adsorption of CH4 and CO2 was simulated by the grand canonical Monte Carlo (GCMC) method under different reservoir pressures, temperatures, geological depths, CO2 mole ratios, and moisture contents of kerogen model. Results show that CO2/CH4 adsorption selectivity decreases with increasing reservoir pressure, indicating that CS-EGR can be more efficient if CO2 injection is conducted at the late development stage. The temperature has a negative effect on the selectivity, which indicates that thermal stimulation has an adverse effect on the efficiency of CS-EGR. Also, the selectivity decreases with increasing geological depth, suggesting that shallow shale formations are more suitable for CS-EGR. At low pressures, the selectivity increases with increasing CO2 mole ratio, while at high pressures, the selectivity decreases with the increase of CO2 mole ratio. This result suggests that CO2 mole ratio should be dynamically adjusted with the production so as to adapt to the changing reservoir pressure. At higher pressure condition, both the amounts of CO2 sequestration and CH4 desorption increase with the increase of CO2 mole fraction. However, the adsorption stability of CO2 weakens with increasing injection amounts of CO2. Moreover, the adsorption selectivity decreases initially, and then increases with the moisture content of kerogen. Thus, the performance of CS-EGR may be improved by increasing the kerogen moisture content for Silurian shale gas reservoirs. This study gains enhanced insights on the effect of reservoir pressure, temperature, geological depth, CO2 mole ratio, and kerogen moisture content on CO2/CH4 competitive adsorption, and the results can provide applicable guidances for CS-EGR in shale gas reservoirs.

Knowledge of pore structure and adsorption capacity provides guidance for better studying the origin, hydrocarbon distribution, and productivity of shale gas reservoir. In this study, pore structure characteristics of six shale core plugs with different maturity from the Lower Silurian Longmaxi formation in south China were investigated using the Rock-eval analysis, X-ray diffraction, total organic carbon (TOC) content test, and scanning electron microscope (SEM) observation. To further investigate the influence of maturity, the adsorption behavior of gas shale was experimentally measured, with the maximal pressure being 20 MPa. Rock-eval analysis indicates that Ro is 0.67~1.34%. SEM results show that organic matter (OM) pores are abundant in high-maturity shale sample. The OM pores are mainly irregular to elliptical in shape, the size is 8~100 nm. The TOC content is 0.16~4.21% and shows a positive correlation with the BET surface area. A negative relationship exists between TOC content and average pore diameter, which indicates that abundant nanometer pores are related to the OM. A noticeable characteristic in the pore size distribution curve is that the content of micropores (pore width