Simulation of Low-Tension-Gas Flood in a High-Temperature and Heterogeneous Sandstone Reservoir

Summary This study explores low-tension-gas flooding (LTG) as a hybrid low-tension surfactant and nitrogen gas-enhanced oil recovery (EOR) method for a high-temperature (90–100°C) and heterogeneous (permeability 0.06 µd–1180 md) sandstone reservoir. A significant research gap exists in developing EOR technologies tailored for reservoirs with extreme heterogeneity and high temperatures. This study addresses this gap by integrating laboratory and simulation studies to model phase behavior, foam quality, and recovery factors (RFs) and then upscale these findings to a pilot scale. We began with history matching two corefloods, an outcrop, and a reservoir core, employing the in-house UTCHEM simulator. Flow parameters were derived from these corefloods, and fluid properties were ascertained from laboratory experiments. A 0.6-acre pilot-scale model in UTCHEM, based on field data, was used to simulate the LTG process. The comprehensive field scale sensitivity study indicates an incremental oil recovery (IOR) factor (RF) between 11% and 18% from LTG injection, influenced primarily by residual oil saturation to waterflood, injection rate, LTG slug size, and surfactant concentration. Gravity segregation between gas and microemulsion phases, affected by reservoir vertical heterogeneity, emerged as a critical factor. A lower kv/kh ratio led to a more stable front with a moderate gas override. Based on the technical feasibility of this study, an optimal chemical injection design involves 1 wt% surfactant concentration within 1 pore volume (PV) of LTG slug. Higher injection rates resulted in increased oil recovery and shorter pilot duration, though constrained by field operational limits. Adjusting foam quality during LTG injection affected gravity segregation, necessitating further laboratory experiments for correlation with gas mobility reduction. Foam shear thinning could enhance field foam injectivity without significantly impacting cumulative oil recovery. Increasing the injection rate within allowable injection bottomhole pressure (BHP) is recommended for field implementation to prevent fracture induction. This is the first study that extensively explores the impact of reservoir and design parameters for LTG injection under challenging reservoir conditions, integrating key uncertainty analysis to ensure robustness in the proposed EOR strategy.