## 5 Discussion
### Reservoir Characteristics and Implications for Oil and Gas Exploration  
During the deposition in the Qigu Formation, large-scale retrogradational shallow-water delta deposits developed extensively, with basin-wide sand distribution. This sedimentary pattern established a robust foundation for hydrocarbon-bearing formations in the study area. The lithology of the Qigu Formation reservoir consisted of conglomera sandstone, coarse-to fine-grained sandstone, siltstone, and argillaceous siltstone. The Qigu Formation exhibited porosity values ranging from 3.02% to 14.2%, with an average of 8.45% (Figure 15A). The permeability values ranged from 0.06 \(\times\) 10\({}^{-3}\) um\({}^{2}\) to 139 \(\times\) 10\({}^{-3}\) um\({}^{2}\), with an average of 6.56 \(\times\) 10\({}^{-3}\) um\({}^{2}\) (Figure 15B). Statistical analysis revealed a positive correlation between porosity and permeability. The Qigu Formation in the Yongjin area is classified as a reservoir with ultra-low to low porosity and permeability (Figure 15C). Reservoir quality is strongly correlated with sedimentary microfacies. Different microfacies types significantly affect the porosity, permeability, and storage capacity of the reservoir [24; 27]. Statistical analyses showed that mouth bar sandstones had the best reservoir properties, followed by subaqueous distributary channel sandstones (Table 3; Figure 15C).  
Different sedimentary microfacies give rise to distinct lithofacies types. Both sedimentary environment and rock composition, including grain size, clay mineral abundance, and argillaceous content, are recognized as key factors controlling the reservoir quality [27; 28; 100; 101]. The sand bodies in the channels were coarse-textured, dominated by conglomeratic and coarse-to-fine-grained sandstones. These facies exhibited high lithic content, poor sorting and rounding, and grain sizes showing wide variation. Secondary porosity was locally developed through dissolution, resulting in moderate reservoir quality overall (Figure 15C) [102; 103]. Mouth bar sand bodies were predominantly composed of medium-to fine-grained sandstones with low lithic content but high concentrations of quartz and other rigid grains [102; 103]. These facies exhibited well-developed porosity, primarily consisting of primary intergranular pores, making them the most favorable sedimentary facies for high-quality reservoir development (Figure 15C). Furthermore, these sand bodies not only form high-quality reservoirs, but also serve as critical migration pathways for long-distance hydrocarbon transport.  
The basal Qigu Formation comprises conglomeratic and medium- to fine-grained sandstones exhibiting pronounced lateral continuity, substantial thickness, and favorable reservoir properties, forming the primary hydrocarbon reservoir [31; 34; 35]. Overlying these sandstones are thick successions of purplish-red siltstones, mudstones, and fine-grained deposits, which act as high-quality seals. Together, they constitute a stable reservoir-seal assemblage. The hydrocarbons in the Qigu Formation are primarily sourced from the Permian Lower Wuerhe Formation [104]. Fault assemblages and inclined reservoir sand bodies provide effective vertical and lateral migration pathways for hydrocarbon movement. The sandbodies of the Qigu Formation demonstrate extensive lateral distribution and interface with multiple hydrocarbon-migration faults, creating highly favorable accumulation conditions [36; 37; 105]. Exploration results confirm high productivity in multiple wells of the Qigu Formation, indicating significant future exploration potential [34; 35]. This study provides a reference and guidance for the exploration and development of hydrocarbon reservoirs in arid climates.