Phase Evolution History of Deep-Seated Hydrocarbon Fluids in the Western Junggar Basin: Insights from Geochemistry, PVT, and Basin Modeling

Clarifying the phase evolution history of hydrocarbon fluids helps formulate exploration and development strategies. The discovery of the Xinguang Gas Field marks a significant breakthrough in the Western Junggar Basin. However, the phase evolution history of this gas field remains unclear, which hinders the formulation of subsequent exploration strategies. This study employs a comprehensive approach, combining organic geochemistry, fluid inclusions, basin modeling, and PVT testing and simulation, to investigate the characteristics and phase behavior of deep-seated hydrocarbon fluids in this gas field. It also examines the charging history, compositional evolution, and temperature and pressure histories of the reservoir, thereby clarifying the phase transition process of hydrocarbon fluids in the Xinguang Gas Field. This study finds that the deep-seated reservoir fluids in the Jiamuhe Formation (Fm.) of the Xinguang Gas Field exhibit low densities of 0.77 to 0.83 g/cm3, high gas-to-oil ratios (GORs) of 1014.41 to 13,054.77 m3/m3, high methane contents of 91.16% to 92.74%, and retrograde condensation characteristics. Additionally, the reservoir temperature and pressure exceed the critical point and the saturation pressure at reservoir temperature, indicating a supercritical condensate gas phase. The present condensate gas in the Xinguang Gas Field is a mixed hydrocarbon from two charging events. Initially, during the Middle–Late Triassic period, both Block 1 and the Xinguang Gas Field were charged with mature oil. Later, from the Late Cretaceous to Early Neogene periods, a secondary charging of highly mature oil and gas occurred in the Xinguang Gas Field, while the reservoir in Block 1 remained largely unchanged. In the co-evolution of reservoir fluid composition, temperature, and pressure, the phase transitions of the hydrocarbon fluids in the Xinguang Gas Field passed through several stages, including liquid black oil (231.9–80.3 Ma), liquid volatile oil (80.3–79.1 Ma), vapor–liquid two-phase volatile oil (79.1–78.3 Ma), vapor–liquid two-phase condensate gas (78.3–69.1 Ma), and supercritical condensate gas (69.1 Ma–present).