关键词: 高温高压, 油气相态, 可视化PVT模拟, 凝析气藏, 原油, 凝析油, 天然气, 准噶尔盆地

Abstract: Prediction of fluid properties and phase behaviors in oil and gas reservoirs represents a critical technical challenge for deep and ultra-deep petroleum exploration decision-making, reserve estimation, and development strategy design. However, existing phase behavior theories have been established primarily under medium-to-low temperature and pressure conditions, limiting their applicability to ultra-high-pressure and high-temperature reservoirs. At present, phase behavior prediction for deep and ultra-deep reservoirs mainly relies on geological and geochemical methods, which indirectly infer phase characteristics through the analysis of hydrocarbon compositions generated from source rocks at different maturity stages. In this study, a high-pressure and high-temperature (200 MPa and 200 ℃) visual PVT phase behavior analyzer was employed. Natural gas samples and crude oils of different types from the southern margin of Junggar Basin were selected, and their mixtures were prepared at varying gas-oil ratios. Visual PVT simulations were subsequently conducted to investigate oil and gas phase behavior evolution, and the phase behaviors of ultra-deep oil and gas reservoirs in the southern margin of Junggar Basin was further identified. The experimental results at a high temperature of 158 ℃ demonstrate as follows. The condensate oil and natural gas mixtures with gas-oil ratios (GORs) of 2 000 m³/m³, 5 000 m³/m³ and 8 000 m³/m³ exhibit a vaporous gas phase behavior with only minor solid deposition when the pressure exceeds 67 MPa, 61 MPa and 59 MPa, respectively. As the pressure decreases below these thresholds, the systems transform into gas-liquid two-phase states. At 18 MPa, the precipitated liquid oil accounts for 8.87 %, 2.52 %, and 1.41 % of the total oil-gas volume respectively depending on different GORs. The light oil and natural gas mixtures with GORs of 2 000 m³/m³, 5 000 m³/m³ and 8 000 m³/m³ remain in a gas-solid two-phase state at pressures above 130 MPa, transition into a gas-liquid-solid three-phase state within the pressure range of 130-90 MPa, and subsequently convert into a gas-liquid two-phase state when the pressure decreases below 90 MPa. At 40 MPa, the precipitated liquid oil accounts for 45 %, 35 % and 22 % of the total oil-gas volume respectively depending on different GORs. For the ordinary black oil and natural gas mixture with a GOR of 8 000 m³/m³, gas-solid two-phase state with significant solid deposition occurs above 130 MPa . Within the pressure range of 130-90 MPa, the system exhibits a gas-liquid-solid three-phase state, whereas it transforms into a gas-liquid two-phase state below 90 MPa. At 30 MPa, the precipitated liquid oil accounts for approximately 14 % of the total oil-gas volume. Therefore, under high-temperature conditions, pressure exerts a dominant control on the ability of natural gas to dissolve crude oil and on the phase behavior of oil-gas systems. In deep to ultra-deep reservoirs under ultra-high-pressure and high-temperature conditions, oil and gas accumulations with a GOR greater than 2 000 m³/m³ are basically classified as gas-condensate reservoirs characterized by a vaporous gas phase. Ultra-deep oil and gas reservoirs in the southern margin of Junggar Basin, such as the Well Hutan1 and Well Tianwan1 reservoirs, with GORs exceeding 2 000 m³/m³, are identified as vaporous gas-condensate reservoirs under in situ reservoir conditions. The natural gas in these reservoirs has dissolved most hydrocarbons originally present in crude oil, yielding condensate oils with relatively high densities at the surface.

Key words: high temperature and high pressure, oil and gas phase behavior, visualized PVT simulation, gas-condensate reservoir, crude oil, condensate oil, natural gas, Junggar Basin