The application of basin modeling is commonly aimed at constraining prospect risk of source rock effectiveness and charge presence. The simulation of compositional petroleum generation and multiphase fluid migration of miscible and compressible fluids adds the ability to predict petroleum value, i.e., fluid phase and properties, in undrilled traps. This functionality was implemented in Institut Franais du Ptrole's (IFP) 2-D Temispack program and applied successfully in a case study that was aimed at reconstructing gas-oil ratio (GOR) and liquid petroleum density at surface conditions (API) for two North Sea fields, the low-GOR Ninian oil field and the high-GOR Huldra condensate field.

In both fields, the Upper Jurassic Kimmeridge and Heather Formations do overlay the middle Jurassic Brent reservoir/carrier beds and contain source rock intervals with kerogen of Type II (IFP classification) or of class B (BP classification). The modeling study links the low-GOR Ninian oil to the petroleum composition migrating from the half graben west of the field where secondary cracking is not significant. The petroleum fluid at Huldra, a condensate, is derived from a local deep kitchen to the east where all source rocks are mature and secondary cracking is providing the high gas fraction of the trapped petroleum. In both fields, the GOR is closely linked to the cracking reactions of heavy components (nitrogen, sulfur, oxygen organic compounds [NSO], C₁₄₊ aromatics) and late gas generation from kerogen cracking. The molecular weight of the C₁₄₊ components determines the API. Most importantly, the pressure-volume-temperature (PVT) behavior of the fluids during migration indicates that a single-phase petroleum flow is by far the dominating process. A significant three-phase migration may occur only at depths less than about 3 km.