Mineral wettability is a crucial factor that determines the distribution of oil and water at the pore scale and, thus, influences oil reserves and recovery efficiency at the reservoir scale. Adding surfactants is one of the most common methods used to modify mineral wettability. However, previous studies on modifying mineral wettability via surfactants were mainly performed under room-temperature conditions, which do not represent the high-temperature reservoir conditions. A systematic investigation of the effects of temperature and surfactant on wettability in mineral-oil-water systems is still lacking. Therefore, in this study, the impact of temperature (25 °C vs 50 °C), surfactant type (cetyltrimethylammonium bromide [CTAB] vs sodium dodecyl sulfate [SDS]), and concentration (0-0.2 wt %) on the wettability of three representative minerals (including quartz, mica, and calcite) was systematically investigated via water contact angle (θ) measurements in an oil environment. It is demonstrated that as the temperature increased, in the presence of CTAB (0.024 wt %), quartz and mica became more oil-wet, while calcite became more water-wet. In the presence of SDS (0.2 wt %), quartz, mica, and calcite became more water-wet. At 50 °C, with the increased CTAB concentration, quartz, mica, and calcite became more oil-wet and then became more water-wet. At 50 °C, for quartz and mica, they become strongly oil-wet (quartz: 140°; mica: 163°) at the specified CTAB concentration (0.006 wt %), while they remained water-wet (quartz: 34° ∼ 60°; mica: 33° ∼ 50°) in all SDS systems. This work provides a fundamental understanding of wettability modification of various minerals via surfactants at oil reservoir conditions, thus aiding in efficient oil extraction in various geological reservoirs.

A capillary high-pressure optical cell (HPOC) combined with a confocal Raman system was used in this study of high-pressure methane/brine contact angles on a quartz surface. The contact angle was determined from the shape of the methane/brine/quartz interface; it increased with fluid pressure from 41° to 49° over a pressure range of 5.7–69.4 MPa. A linear relationship between the contact angle and the Raman shift was also observed. The experimentally measured contact angle was more accurately applied in calculations of capillary resistance than the empirically estimated 0°, and it provides an important parameter in the study of gas migration and production processes. For a natural gas reservoir, pore-throat capillary resistance was 33% lower than the traditionally accepted value, and low capillary resistance is conducive to deeply buried tight gas reservoirs becoming more gas saturated. As burial depth increases, capillary resistance initially decreases and passes through a maximum before decreasing again, rather than increasing linearly with depth. Our results provide critical parameters for gas reservoir production, modeling, and resource assessment. This non-destructive method may be useful for predicting contact angles through measurement of the Raman shift of the HPOC and fluid inclusions in the reservoir.