To investigate the mechanism by which the rheological properties of drilling fluids affect the stability of the wellbore in brittle mud shale, this study systematically examines the influence of drilling fluids with different rheological properties on the hydration dispersion and rock strength of brittle mud shale through a series of laboratory experiments, including thermal rolling tests and uniaxial compressive strength tests on core samples. The results reveal that for weakly dispersible brittle mud shale, the rheological properties of drilling fluids have a minor effect on hydration dispersion, with rolling recovery rates consistently above 90%. However, the rheological properties of drilling fluids significantly influence the strength of brittle mud shale, and this effect is coupled with multiple factors, including rock fracture intensity index, soaking time, and confining pressure. Specifically, as the viscosity of the drilling fluid increases, the reduction in rock strength decreases; for instance, at 5 MPa confining pressure with an FII of 0.46, the strength reduction after 144 h was 69.8% in distilled water (from an initial 133.2 MPa to 40.2 MPa) compared to 36.3% with 3# drilling fluid (from 133.2 MPa to 88.7 MPa, with 100 mPa·s apparent viscosity). Both increased soaking time and confining pressure exacerbate the reduction in rock strength; a 5 MPa confining pressure, for example, caused an additional 60.9% strength reduction compared to 0 MPa for highly fractured samples (FII = 0.46) in distilled water after 144 h. Rocks with higher fracture intensity indices are more significantly affected by the rheological properties of drilling fluids. Based on the experimental results, this study proposes a strength attenuation model for brittle mud shale that considers the coupled effects of fracture intensity index, soaking time, and drilling fluid rheological properties. Additionally, the mechanism by which drilling fluid rheological properties influence the strength of brittle mud shale is analyzed, providing a theoretical basis for optimizing drilling fluid rheological parameters and enhancing the stability of wellbores in brittle mud shale formations.

The water produced from coalbed methane (CBM) wells contains abundant geochemical information; therefore, analyzing the geochemical information available therein is of great significance for the efficient exploitation of CBM wells. Based on the geochemical characteristics of water from four CBM wells in eastern Yunnan, this paper analyzes the relationship between the geochemical characteristics of the produced water and gas production. The results indicate that the underground environment in which water is produced in the four CBM wells in the study area exists in a closed state. The water sourced from wells L-1 and L-2 is of the Na-Cl-HCO₃ type, whereas the water sourced from wells L-3 and L-4 is of the Na-HCO₃ type. Gas production is approximately positively correlated with high concentrations of HCO₃⁻, up to concentrations of 2800 mg/L, beyond which gas production decreases. Both D drift and ¹⁸O isotope drift in the produced water are beneficial for the production of CBM. The trace element content of the well water is influenced by the trace elements found in the coal seams and surrounding rocks, especially at peak trace element contents. The dissolved inorganic carbon isotope (¹³C_DIC) in the well water is affected by microbial methanogenesis and carbonate dissolution, and gas production is high when ¹³C_DIC is approximately −4‰.

To investigate the factors of pore–fracture structure heterogeneity in middle rank coal reservoirs, middle rank coal samples collected from the deep coal seams in the northern part of the Kuqa area in the Tarim Basin are analyzed. Firstly, according to the maximum vitrinite reflectance (R_o,max), all the samples are divided into two types, Type A and B (A: R_o,max is larger than 1.2%; B: R_o,max is smaller than 1.2%). Secondly, the full-scale pore–fracture system was characterized using a combination of three experiments: high-pressure mercury intrusion testing, low-temperature CO₂ adsorption testing, and low-temperature nitrogen adsorption testing. Subsequently, multifractal theory was applied to evaluate pore structure heterogeneity and investigate its governing factors. The results are as follows: (1) Type A samples exhibit superior micropore development, whereas Type B samples show a higher degree of mesopore and macropore development. Both types of samples display a “bimodal” distribution across the full-scale pore. Type A pore structure is affected by R_o,max and macerals, with mineral components having a minor impact, while Type B is regulated by all three factors. (2) The coal samples exhibit distinct multifractal characteristics. Type A pore structure heterogeneity is higher than that of Type B. This heterogeneity in Type A is dominated by the differences in the development and distribution of small-scale pores (micro- and mesopores), whereas in Type B, it is governed by the full-scale pore system distribution.