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

Abstract

Abstract This study explores Low-Tension-Gas (LTG) flooding as a hybrid low-tension surfactant and nitrogen gas-enhanced oil recovery method for a high-temperature (90-100°C), heterogeneous (permeability 0.06 µD-1180 mD), sandstone reservoir. 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 core floods, and fluid properties were ascertained from lab experiments. A 0.6-acre pilot-scale model in UTCHEM, based on field data and geostatistics, was used to simulate the LTG process. The comprehensive field scale sensitivity study indicates an additional oil recovery factor (RF) between 11-18% 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. An optimal chemical injection design involves 1 wt% surfactant concentration within 1 pore volume 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 lab 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 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 for challenging reservoir conditions.