Our current understanding of the geochemical processes responsible for the creation of commercial accumulations of oil and gas can be reduced to simple rules and equations to allow the petroleum geologist to use geochemistry to estimate--before drilling--the likely volumes and compositions of oil and gas delivered to the trap.

In most sedimentary basins, oil is expelled from source rocks between 120° and 150°C, whereas most gas and gas condensate are released between 150° and 230°C. When the initial potential of source rocks exceeds 10kg/MT, oil expulsion efficiencies are between 60 and 90%.

Expelled oil and gas migrate as petroleum-rich phases driven by fluid potential gradients. Most flow is laterally updip in beds with effective horizontal permeabilities greater than 1 md. In lower permeability rocks, the petroleum fluids move vertically, up or down, along the path of least resistance (i.e., the most permeable or thinnest beds) separating them from a high-permeability lateral carrier bed. The residual saturations of petroleum left behind along the migration pathway are of the order of a few percent of the porosity.

Geochemical analysis of source rocks helps determine the yields and compositions of petroleum fluids expelled in the catchment area of a prospect. These fluid masses are converted to volumes from knowledge of the phase relations and densities of petroleum fluids. Evaluation of the total volume of rock through which the petroleum potentially can migrate and the mean porosity of the rocks that constitute the migration pathway allow migration losses to be assessed. These losses constrain both the range of migration of petroleum fluids away from the mature source rock and the volumes of petroleum remaining for entrapment in the prospect.