Abstract: Junlian coalbed methane (CBM) block at the southern edge of Sichuan Basin is the first successfully developed commercial block in the south, and the CBM wells have the output characteristics of “high average daily production, high cumulative production, and long stable production period”, but the coal reservoirs have the anomalous special characteristics of “high ash content, high gas content, and high gas saturation”. To investigate the origin and source of gas in the Junlian Block of southern Sichuan, a study was conducted using gas produced from 29 CBM wells and coal samples from 4 coal mines as research objects. The study involved coal petrology, carbon isotope analysis, fluid inclusion analysis, gas composition analysis, and carbon-hydrogen isotope experiments. Combined with regional tectonic evolution and basin simulation results, the study systematically revealed the genesis types, gas sources, and migration patterns of CBM in the study area, and established a CBM accumulation model for the region. The results show that: the average carbon isotope value of coal rocks in the Leping Formation is −23.1‰, the maceral group is dominated by the vitrinite, followed by the inertinite, without the liptinite, and the hydrocarbon source rock is mainly the type III (humic) kerogen. The output gas component is dominated by CH₄, with very low heavy hydrocarbon content, and belongs to extremely dry gas, with δ¹³C₁ averaging −34.1‰ and δ¹³C₂ averaging −31.2‰, which manifests positive carbon isotope composition sequence, and the δD₁ value averaging −131.3‰. The output gas is thermogenic gas of high-over-mature stage, the gas type is oil-type gas, and the hydrocarbon source rock is sapropelic kerogen, which is inconsistent with the conclusion that the coal stratum is humic kerogen. Combined with the geological background of the study area, through the comparisons of regional gas-source rock, it is believed that the gas produced from Upper Permian Leping Formation is a mixture of self-generated and self-stored CBM and downgraded and upgraded shale gas. The microfracture cross-cutting relationship, the oriented alignment direction of inclusions and the bimodal characteristics of homogeneous temperature indicate that the CBM formation process is divided into two phases, namely the Early Cretaceous hydrocarbon peak and the Late Cretaceous tectonic uplift. Basin simulation results show that Longmaxi Formation shale gas was transported upward along the faults during Yanshanian period uplift, and was captured by the coal beds of Leping Formation, forming a mixed gas reservoir of the “down-generation and up-storage” type, and the high gas content in the coal beds is attributed to the supplementation of the shale gas and the strong sealing ability of the coal strata.