Migration of Oil and Gas

The oil and gas phases is simulated as a multi-component system obeying phase equilibrium laws. The oil and gas phases can alternatively be modeled as a black oil model, with the gas phase being methane and the oil phase being selected as a heavy hydrocarbon component dis-regardless of subsurface pressure and temperature. The fluid components in the multi-component system are selected by the user from a database, which besides from 24 hydrocarbon compounds also includes carbon dioxide, hydrogen sulphide, nitrogen, and oxygen. The source of these non-hydrocarbon compounds is the kerogen, which dependent of kerogen type contains various concentrations of oxygen, sulphur, and nitrogen (Behar & Vandenbroucke, 1987).

The conservation of mass for the fluid components is given by a time-space partial differential equation. The momentum balance for the oil and gas phase is based on combining Navier-Stokes equations with Stokes's law for quantifying the viscous drag from the rocks. These equations are similar to Darcy's law combined with a Kozeny-Carman permeability model and the concept of relative permeability.

In the multi-phase model, the wetting character of the fluid system is determined by the phase equilibrium. Alternatively the three-phase flow system in a compacting sedimentary basin is considered a drainage system in which the dominant wetting phase is brine. The relative permeability is dependent on the sorting of grain sizes and evaluated based on fluid dynamic calculations of the hydraulic radius similar to Kozeny-Carmans permeability derivation. This results in relative permeability relations for both the dominant wetting phase and the none-dominant wetting phase, which are comparable to the empirical relations proposed by Corey (1954).