## 5 Discussion
### Origin of Multi-Origin Natural Gas  
The high to over-mature thermal evolution stage provides a critical geochemical basis for identifying the genetic type and source of natural gas [42; 43]. Within the thermal evolution sequence of source rocks, when vitrinite reflectance (Ro) reaches 1.3-2.0%  
Figure 5: A coordinate diagram illustrating \(\delta^{13}\)C\({}_{1}\), \(\delta^{13}\)C\({}_{2}\), and \(\delta^{13}\)C\({}_{3}\) values from natural gas samples collected in the Dixi region of the Junggar Basin. The classification thresholds for distinct genetic categories follow the framework established by [PERSON] et al. (2005) [38], adapted from their original research to reflect local geological conditions. Five genetic classifications are identified: (I) biologically derived methane accumulations; (II) kerogen-derived hydrocarbon gases from sapropelic sources; (III) thermogenic gases originating from humic matter; (IV) mixed thermogenic gas reservoirs; and (V) hybrid gases exhibiting carbon isotope reversal phenomena. (high maturity stage), gas generation from kerogen degradation enters a peak phase, and oil-cracking gas begins to dominate. When Ro exceeds 2.0% (over-mature stage), liquid hydrocarbons are completely cracked into dry gas, and the carbon isotope of methane becomes significantly heavier (\(\delta^{13}\)C1 \(>-30\)%). At this stage, the molecular composition, isotopic fractionation effects, and light hydrocarbon indicators (e.g., benzene/n-hexane ratio) can effectively distinguish oil-derived gas from coal-derived gas while excluding interference from biogenic gases. In addition, residual aromatic compounds and diamond-doids preserved under over-mature conditions provide important geochemical markers for tracing the type of source material and the cracking pathway, thereby offering key indicators for evaluating deep to ultra-deep natural gas resources [44]. As shown in the \(\delta^{13}\)C\({}_{2}\) versus (\(\delta^{13}\)C\({}_{2}\)-\(\delta^{13}\)C\({}_{1}\)) cross-plot (Figure 6), the natural gas samples in the study area are primarily identified as middle to late-stage humic-derived gas, indicating that the associated source rocks have undergone high to over-mature thermal evolution. Based on the \(\delta^{13}\)C\({}_{1}\) and \(\delta^{13}\)C\({}_{2}\) isotopic characteristics of natural gas, the distribution of samples can be compared with different types of kerogen (e.g., Type II and Type III). The diagram (Figure 7) includes the \(\delta^{13}\)C\({}_{1}\)-\(\delta^{13}\)C\({}_{2}\) evolutionary fields associated with various kerogen types from typical basins worldwide, such as the Delaware/Val Verde Basin, Sacramento Basin, and Niger Delta [45]. Most of the natural gas data points from the study area--including formations such as the Carboniferous (C), Permian--Triassic (P-T), Jurassic (J), and Cretaceous (K)--fall within the field corresponding to Type III kerogen  
Figure 6: Scatter diagram illustrating the isotopic relationship between \(\delta^{13}\)C\({}_{2}\) values and (\(\delta^{13}\)C\({}_{2}\)–\(\delta^{13}\)C\({}_{1}\)) differences observed in hydrocarbon gases from the Dixi region of the Junggar Basin. (Figure 7), indicating that the gas is predominantly derived from coal-bearing or humic organic matter. This finding is consistent with previous research on the types and thermal maturity of organic matter in the region, further confirming that the natural gas in the study area exhibits typical characteristics of coal-derived (humic) gas. In addition to carbon isotopic signatures, the compositional characteristics of natural gas and their corresponding ratios also serve as critical indicators for determining gas origin [10; 46]. The distribution and abundance of light hydrocarbons--such as methane, ethane, and propane--reflect their genetic signatures. For instance, high-maturity thermogenic gas typically exhibits heavier carbon isotopic values (e.g., more negative \(\delta^{13}\)C\({}_{1}\) values).