Liquid imbibition in tight rocks: The role of disjoining pressure

Modelling wettability of tight rocks is challenging due to their complex pore networks, sub-micron pore throats, and organic pores. The experimental results show oil-wet behavior of dry core plugs. Assuming different flow paths for oil and water imbibition, the ratio between oil and brine capillary pressure calculated using imbibition profiles is from 0.67 to 1.76, while that calculated by Young-Laplace model is around 0.5. The higher oil imbibition cannot be completely explained by the conventional Young-Laplace model. Therefore, we apply Derjaguin, Landau, Verwey, and Overbeek (DLVO) theory to evaluate intermolecular forces among oil, water, and rock surface by calculating disjoining pressure (Pi(d)). For liquid imbibition in dry samples, the Fla calculations show that the attraction between rock and oil is stronger than that between rock and water, explaining the higher oil imbibition into the core samples. The ratio between oil and brine capillary pressure calculated by the augmented Young-Laplace equation, which considers Pi(d), is closer to that calculated using the imbibition data. The excess oil imbibition is also due to hydrocarbon coating on inorganic pores and different flow paths for oil and water. The attraction between rock and oil increases if we consider more percentage of pores coated by residual hydrocarbon. To explain the water imbibition into oil-saturated core plugs, we evaluate the stability of the oil and water films covering the rock surface. The calculated Pi(d) profiles suggest that quartz is more water-wet compared with other minerals. The thin water film covering quartz becomes more stable as the film thickness increases, helping oil production from oil-saturated pores composed of quartz. We also calculate Pi(d) for brine with different salinities. Generally, for a rock surface-water-oil system, Pi(d) increases by decreasing water salinity, suggesting more stable water film.