## 1 Introduction  
The coexistence of mixed-source natural gases with differing properties is a common phenomenon in natural gas reservoirs. This mainly includes mixtures of gases from different source rocks, as well as mixtures from the same source at different stages of thermal evolution [1, 2, 3]. Because mixed-source natural gas exhibits integrated characteristics from multiple origins, it is challenging to determine its genesis, source, and the contribution of each component based solely on its geochemical properties. Compared with crude oil, natural gas has a relatively simple composition and lacks diagnostic compoundssuch as biomarker molecules used for oil-source correlation. This simplicity significantly increases the difficulty of accurately assessing the mixing ratios of natural gas from different sources [4; 5]. However, natural gas in discovered fields often exhibits characteristics of multi-source origins and mixed-source reservoir formation across different geological periods [6; 7]. Therefore, it is essential to address the specific challenges associated with identifying the origins of multi-source natural gas, particularly in geologically complex basins where gases from different source rocks may be thermally evolved, migrated, or mixed at various stages. These complexities hinder the effectiveness of traditional qualitative assessments. As such, quantitative calculation of source contributions is critical for accurately determining the proportion and influence of each gas source, which in turn supports the reliable reconstruction of gas accumulation processes and source-reservoir relationships. A wide range of studies have identified thermogenic gas [8; 9], biodegradable gas [10], and mixed gases [11] using molecular composition, stable isotope ratios, and thermal maturity modeling [12]. It is now well established that the natural gas in sedimentary basins originates from diverse sources, including thermogenic cracking of kerogen or oil [13], microbial degradation [14], and complex mixing processes [15]. Globally, the formation of large-scale gas accumulations is often associated with oil cracking under high-temperature, high-pressure conditions in deep reservoirs [16]. However, field observations frequently reveal coexisting gas types within a single reservoir, including oil-cracked, coal-derived, and mixed gases [17]. In geologically heterogeneous settings, this genetic diversity further complicates exploration and increases uncertainty [18]. Scholars have attempted to study the geochemical characteristics of mixed-source natural gas and calculate the mixing ratio of natural gas using geochemical indicators such as carbon isotopes and light hydrocarbons. However, on the one hand, these studies are generally aimed at binary natural gas mixed-sources (i.e., two natural gas mixed-sources with different properties). For multi-source natural gas mixed-sources, there are still deficiencies in the simplicity of the research methods and the scope of application [19; 20]. On the other hand, the identification diagrams established by these studies are rather complex, making it difficult to apply the theory to the actual identification of the proportion of mixed-sources of natural gas [17]. As one of the most important hydrocarbon-bearing basins in China, the Junggar Basin has yielded numerous discoveries of shallow oil and gas accumulations [21; 22]. However, deep hydrocarbon exploration in the basin remains in its early stages. In the Dixi area, two sets of humic-type source rocks are present: the Upper Carboniferous Batamayineishan Formation and the Lower Carboniferous Dishuiquan Formation. Previous studies generally suggest that both source rock intervals have contributed to gas accumulation in the region [23]. However, the effectiveness of the Dishuiquan Formation source rocks remains speculative due to limited good penetration in the Dinnan Uplift and the poor imaging quality of available seismic data [24; 25].