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<p>Understanding pore-scale hydrocarbon gas–water–oil three-phase flow in reservoir-type underground gas storage (UGS) remains limited, particularly under repeated seasonal injection-withdrawal cycles at elevated pressure and temperature. This gap limits mechanistic interpretation of injectivity evolution, pressure hysteresis, and working-gas loss in oil reservoirs converted to UGS. The present study develops an HPHT microfluidic visualization platform to observe three-phase dynamics in a sandstone-pattern micromodel at 85&#xa0;°C under cyclic pressures of 10–29 MPa. The protocol reproduces key stages of UGS construction and operation, enabling real-time tracking of interfaces, phase redistribution, and connectivity. Weakly water-wet/mixed-wet conditions create persistent capillary heterogeneity, leading to capillarity-controlled fingering, snap-off, and immobilized oil films and ganglia during waterflooding, which subsequently constrain gas accessibility. During graded gas injection, intermittent pore-scale invasions and gas–water reconfiguration rapidly establish preferential gas pathways that dominate injectivity and cushion-gas development. Concurrently, sustained gas–oil contact promotes interphase mass transfer (gas dissolution into oil), manifested by oil swelling and enhanced oil mobility that locally assists remobilization and pathway evolution along the pressure trajectory. During withdrawal, wetting-phase re-imbibition partially collapses gas pathways, while flow reversal induces interfacial shear that redistributes wall-attached liquid films, together promoting irreversible gas trapping and connectivity hysteresis. In the first cycle, bulk gas saturation increases from ~ 40 to ~ 72%, while oil displacement efficiency (used solely as a diagnostic for three-phase redistribution) rises from ~ 12 to ~ 23% during injection and reaches ~ 26–27% at early withdrawal. These pore-scale observations provide mechanistic constraints for optimizing pressure windows and maximizing working-gas recovery in reservoir-type UGS systems.</p>

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Microfluidic Investigation of High-Pressure High-Temperature Pore-Scale Hydrocarbon Gas–Water–Oil Three-Phase Flow in Reservoir-Type Underground Gas Storage

  • 期刊论文

  • 发表日期：

    2026年4月11日

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  • Qian Zhang,
  • Dewen Zheng,
  • Jieming Wang,
  • Lei Shi,
  • Chun Li,
  • Huayin Zhu

摘要

Understanding pore-scale hydrocarbon gas–water–oil three-phase flow in reservoir-type underground gas storage (UGS) remains limited, particularly under repeated seasonal injection-withdrawal cycles at elevated pressure and temperature. This gap limits mechanistic interpretation of injectivity evolution, pressure hysteresis, and working-gas loss in oil reservoirs converted to UGS. The present study develops an HPHT microfluidic visualization platform to observe three-phase dynamics in a sandstone-pattern micromodel at 85 °C under cyclic pressures of 10–29 MPa. The protocol reproduces key stages of UGS construction and operation, enabling real-time tracking of interfaces, phase redistribution, and connectivity. Weakly water-wet/mixed-wet conditions create persistent capillary heterogeneity, leading to capillarity-controlled fingering, snap-off, and immobilized oil films and ganglia during waterflooding, which subsequently constrain gas accessibility. During graded gas injection, intermittent pore-scale invasions and gas–water reconfiguration rapidly establish preferential gas pathways that dominate injectivity and cushion-gas development. Concurrently, sustained gas–oil contact promotes interphase mass transfer (gas dissolution into oil), manifested by oil swelling and enhanced oil mobility that locally assists remobilization and pathway evolution along the pressure trajectory. During withdrawal, wetting-phase re-imbibition partially collapses gas pathways, while flow reversal induces interfacial shear that redistributes wall-attached liquid films, together promoting irreversible gas trapping and connectivity hysteresis. In the first cycle, bulk gas saturation increases from ~ 40 to ~ 72%, while oil displacement efficiency (used solely as a diagnostic for three-phase redistribution) rises from ~ 12 to ~ 23% during injection and reaches ~ 26–27% at early withdrawal. These pore-scale observations provide mechanistic constraints for optimizing pressure windows and maximizing working-gas recovery in reservoir-type UGS systems.