Gas-bearing potential in marine shales is governed by lithofacies-scale mineralogical heterogeneity and its coupling with organic-matter enrichment. We analyzed 40 core samples from the Lower Silurian Longmaxi Formation in the Zheng’an area, northern Guizhou (wells AD-2, AD-3, and AD-4), using whole-rock XRD, total organic carbon (w(TOC) %), and in situ gas content (cm3/g). A normalized quartz–clay–carbonate ternary diagram was applied to classify samples into siliceous shale (S), clay-rich shale (CM), calcareous shale (C), and mixed shale (M), and further into subfacies (e.g., S-1, S-2, and CM-1). Most samples plotted within the siliceous–clay transition field. Against this compositional background, w(TOC) mainly ranged from 4% to 6%, with the 4–5% bin accounting for 57.5%; well AD-4 showed a relatively stable distribution, whereas wells AD-2 and AD-3 exhibited stronger vertical variability. In situ gas content varied systematically with lithofacies: CM displayed higher and more concentrated values (maximum 4.78 cm3/g), whereas S was more dispersed, with persistently low values in the continuous S-2 interval (minimum 0.15 cm3/g). Favorable intervals were associated with the continuous development of CM-1 and S-1, whereas S-2 required interval-specific assessment under an overall low-carbonate background.
Li et al. (2026) studied this question.