Composite Surfactant Formulation Mitigates Water-Locking in High-Temperature and High-Salinity Tight Sandstone Gas Reservoirs

Retained water associated with water-locking can restrict gas production in heterogeneous tight sandstones, and the activity and phase stability of many surfactant treatments are reduced under high-temperature, high-salinity (HTHS) conditions. In this study, a composite surfactant formulation, CSF-1, designed to lower gas–brine capillary resistance and adjust sandstone wettability under representative reservoir constraints, is reported. Its performance was evaluated using thermal aging, surface tension and contact angle measurements, geochemical compatibility tests, laser diffraction, SEM/EDS, and core flooding combined with stagewise low-field nuclear magnetic resonance (LF-NMR). CSF-1 remained macroscopically homogeneous after aging at 170 °C in 188.314 g/L hypersaline brine and retained low gas–brine surface tension when measured at 25 °C after aging. In core flooding tests, CSF-1 increased the apparent gas permeability from 0.203 to 0.388 mD relative to the SFW-saturated water-locked state, corresponding to a 91.1% improvement. One- and two-dimensional NMR measurements provided comparative relaxation domain evidence that CSF-1 promoted the removal and redistribution of relatively mobile and weakly restricted fluid signals and reduced residual signal clustering. The shortest T2 relaxation domains were less affected. The absence of replicate core flooding and associated LF-NMR runs, together with the non-equivalent Ref-S comparison, precludes a statistically rigorous cross-agent performance ranking. These results support the laboratory water-locking mitigation potential under the tested conditions, without implying calibrated pore-size-resolved removal or field-scale confirmation.