In this paper, the methane adsorption behaviours in slit-like chlorite nanopores were investigated using the grand canonical Monte Carlo simulation method, and the influences of the pore sizes, temperatures, water, and compositions on methane adsorption on chlorite were discussed. Our investigation revealed that the isosteric heat of adsorption of methane in slit-like chlorite nanopores decreased with an increase in pore size and was less than 42 kJ/mol, suggesting that methane adsorbed on chlorite through physical adsorption. The methane excess adsorption capacity increased with the increase in the pore size in micropores and decreased with the increase in the pore size in mesopores. The methane excess adsorption capacity in chlorite pores increased with an increase in pressure or decrease in pore size. With an increase in temperature, the isosteric heats of adsorption of methane decreased and the methane adsorption sites on chlorite changed from lower-energy adsorption sites to higher-energy sites, leading to the reduction in the methane excess adsorption capacity. Water molecules in chlorite pores occupied the pore wall in a directional manner, which may be related to the van der Waals and Coulomb force interactions and the hydrogen bonding interaction. It was also found that water molecules existed as aggregates. With increasing water content, the water molecules occupied the adsorption sites and adsorption space of the methane, leading to a reduction in the methane excess adsorption capacity. The excess adsorption capacity of gas on chlorite decreased in the following order: carbon dioxide > methane > nitrogen. If the mole fraction of nitrogen or carbon dioxide in the binary gas mixture increased, the mole fraction of methane decreased, methane adsorption sites changed, and methane adsorption space was reduced, resulting in the decrease in the methane excess adsorption capacity.

We mainly focus on the Permian, Lower Cambrian, Lower Silurian, and Upper Ordovician Formation; the fractal dimensions of marine shales in southern China were calculated using the FHH fractal model based on the low‐pressure nitrogen adsorption analysis. The results show that the marine shales in southern China have the dual fractal characteristics. The fractal dimension D ₁ at low relative pressure represents the pore surface fractal characteristics, whereas the fractal dimension D ₂ at higher relative pressure describes the pore structure fractal characteristics. The fractal dimensions D ₁ range from 2.0918 to 2.718 with a mean value of 2.4762, and the fractal dimensions D ₂ range from 2.5842 to 2.9399 with a mean value of 2.8015. There are positive relationships between fractal dimension D ₁ and specific surface area and total pore volume, whereas the fractal dimensions D ₂ have negative correlation with average pore size. The larger the value of the fractal dimension D ₁ is, the rougher the pore surface is, which could provide more adsorption sites, leading to higher adsorption capacity for gas. The larger the value of the fractal dimension D ₂ is, the more complicated the pore structure is, resulting in the lower flow capacity for gas.

Shale reservoirs are characterized by low permeability and natural fractures. In the process of reservoir development, the working fluid enters the reservoir. This may result in the formation of new fractures or expansion of natural fractures. When shale reservoirs are exploited, the fluid pressure in the fracture or pore is reduced. This destroys the stress balance of the reservoir, produces stress sensitivity damage, and reduces the reservoir permeability. Organic-rich shale from the Yanchang Formation, Chang 7 Member of the Ordos Basin, was selected for core flow experiment with helium. The effects of the type of brine, salinity, and soaking time on the stress sensitivity of an organic-rich shale reservoir were investigated. The acoustic characteristics were also investigated to study the effect of interactions between water and shale on stress sensitivity. The experimental results demonstrate that the interactions of water and shale increase the permeability of shale and reduce its stress sensitivity. Furthermore, when the permeability of the shale is excessively low, the stress sensitivity is high. In the acoustic studies, a higher attenuation coefficient of the acoustic wave corresponds to a larger variation in the shale structure and thus a larger permeability of the shale and smaller stress sensitivity coefficient. Whereas there is no apparent effect of the salt water type on the stress sensitivity, higher salinity levels cause higher stress sensitivity. After reacting with 15000 mg/L brine, the stress sensitivity coefficient of shale did not decrease significantly compared with that before action, all of which were above 0.97. However, after reacting with distilled water or 5000 mg/L brine, the stress sensitivity coefficient of shale decreased significantly, and all of them decreased to less than 0.9. Longer water exposures, corresponding to an increased duration of water-shale interactions, result in higher impacts on the stress sensitivity of shale. After 6 hours of shale-brine interaction, the stress sensitivity coefficient of shale is as high as 0.93, while after 48 hours of shale-brine interaction, the stress sensitivity coefficient of shale is reduced to 0.88. This study provides a highly effective reference with regard to the influence of the working fluid on the reservoir during drilling operations and the study of reservoir characteristics after fracturing.

The problem of wellbore stability in hard brittle shale formations is an important research topic in the exploration and development of shale gas. To solve this problem, the adaptability of the plugging drilling fluid to wellbore stability in the hard brittle shale of the tertiary Dongying formation in Bohai Bay Basin, China, was investigated. The results show that the clay content of the hard brittle shale in the study block is as high as 39.2% on average, with great possibility for hydration. The pore structure in the shale is dominated by micron-scale fractures and pores. A dense structure was formed on the surface of the shale after being immersed in plugging drilling fluid, and the matrix permeability of the shale was reduced by 91.1% and the fracture permeability by 98.7%. The water content increment of the shale after immersion was merely 0.75%, which reduced the probability of hydration greatly. Compared with the field-inhibitive drilling fluid, the plugging drilling fluid improved the uniaxial compressive strength of shale by 28%, which is more conducive to maintaining the wellbore stability. The seepage stress aggravates the risk of wellbore instability, while the hydration stress does not, but both increase the risk of rock instability at positions away from the well wall. The plugging drilling fluid affects the seepage stress and hydration stress by reducing the shale permeability and water content. With the decrease of permeability and water content, the potential instability zone of a wellbore becomes smaller.