Characteristic Forced and Spontaneous Imbibition Behavior in Strongly Water-Wet Sandstones Based on Experiments and Simulation

Forced and spontaneous imbibition of water is performed to displace oil from strongly water-wet Gray Berea (~130 mD) Bentheimer (~1900 sandstone core plugs. Two nonpolar oils (n-heptane Marcol-82) were used as a non-wetting phase, with viscosities between 0.4 32 cP brine (1 M NaCl) for the wetting phase viscosity 1.1 cP. Recovery was measured both modes, pressure drop during forced imbibition. Five tests using low or high injection rates, viscosity. Seventeen experiments at four different viscosities. By varying viscosity, rate capillary advective forces allowed dominate, giving trends that could be captured modeling. Full numerical simulations matched experimental observations consistently. The findings this study provide better understanding recovery behavior in systems. A strong positive favorable mobility ratio resulting relative permeability main features explaining observations. Complete achieved breakthrough curves identical when plotted against injected volume. Analytical solutions indicate changes linearly time negligible. Positive assist imbibition, reducing needed inject water, but yielding jump front reaches outlet. At rate, are repressed linear trend end points clearer than data. Increasing by factor 80 only increased scale five, consistent constraining rate. predicted more sensitive higher oil-to-water ratio, part total follows square root time. Our piston-like displacement reasonable approximation unless has much water.