A scaled physical model was constructed to simulate gravity- and capillary-controlled flow of oil into a water-saturated sand during secondary hydrocarbon migration. The model provided both visualization of the flow patterns and estimates of hydrocarbon transport rates and efficiencies.

The dimensions and physical properties of the model were designed so the balance of gravity, capillary, and viscous forces was the same in the model as in the geologic system. The physical model was a sand pack between glass plates; the pack was 52 cm high, 100 cm long, 2.5 cm thick, and inclined at a 5° dip; its porosity was 42%, and its permeability was 7.0 × 10^-10 m² (710 d). It modeled a geologic carrier bed 27 m thick with 20% porosity and 9.9 × 10^-14 m² (100 md) permeability overlying a source rock. A dyed oil was injected into the lowest corner at a rate of 1 cm³/day, and it exited the highest corner at atmospheric pressure. Oil movement was followed both visually and by ultrasonic velocity measurements.

The behavior of fluids in the model led us to the following conclusions for oil transport through water-wet, homogeneous carrier beds. The rate-limiting step in charging a trap is not secondary migration, but rather the rate of oil release from the source rock. High hydrocarbon loss may occur during vertical migration (when the carrier bed lies above the source) because of extensive dispersion. Losses during lateral migration are probably minimal because flow is concentrated below the top seal.