Phase behavior and reservoir fluid classification of the deep Permian Jiamuhe formation gas condensate in Zhongjia area, Junggar Basin

Significant breakthroughs have recently been achieved in deep Permian Jiamuhe Formation petroleum exploration within the Zhongguai Uplift on the northwestern margin of the Junggar Basin, exemplified by the high commercial flow obtained from well ZJ14. However, the complex and poorly understood hydrocarbon phase behavior in this area constrains exploration and development planning. This study systematically investigates the phase characteristics and evolution of formation fluids from the Jiamuhe Formation in well ZJ14, integrating high-pressure high-temperature (HPHT) fluid property experiments, phase behavior modeling, and multiple empirical identification methods. Experimental results reveal that: (1) The formation fluid exhibits a producing gas‑oil ratio of 7621 m3/m3, a dew‑point pressure of 44.29 MPa, nd a substantial pressure difference between initial reservoir pressure and dew-point pressure of 7.71 MPa; a pronounced retrograde condensation occurs when the pressure falls below the dew point, posing a potential impact on gas‑well productivity. (2) The wellstream composition is characterized by “enrichment in light hydrocarbons and scarcity of heavy hydrocarbons”, with a C1 content of 90.50% and a C5+ content of 3.50%, indicating a high‑maturity, near‑critical rich‑gas‑condensate system that provides the material basis for oil‑rim formation. (3) Integrated identification using multiple methods consistently confirms that the reservoir is a gas‑condensate system with an oil rim; discrepancies in oil‑rim scale estimation from different methods reflect the heterogeneity in oil‑rim distribution, and the fluid composition lies near the phase boundary between gas‑condensate and volatile‑oil systems, suggesting a high risk of retrograde condensation during production. (4) Temperature significantly influences phase behavior, with lower temperatures leading to increased dew‑point pressure and aggravated retrograde condensation; therefore, attention should be paid to near‑wellbore cooling effects during development, and measures such as gas injection for pressure maintenance are recommended to mitigate retrograde‑condensation damage and enhance overall reservoir recovery. The findings provide important insights for phase‑behavior identification and development‑strategy formulation in this area and analogous deep gas‑condensate reservoirs.