2D modelling of hydrocarbon migration along and across growth faults: an example from Nigeria

Temis 2D was used to study hydrocarbon migration and fluid distribution in an area of the Niger Delta. In this setting, high pressures are related to a high sedimentation rate, and pressure compartments are delineated by growth faults. A growth fault is regarded as a hydro-mechanically active zone contributing both to a release of high pressures and to hydrocarbon migration from the deep mature source rocks to shallower reservoirs.

Overpressures are generated in confined systems where water flow is extremely low. The most significant parameters causing the generation of overpressures are very low shale permeability and rapid burial. In 2D modelling, pressure calibration is obtained by adjusting cap-rock permeability and by properly simulating reservoir connectivity. The accuracy of fluid flow simulation is highly dependent on lateral transmissibility across reservoirs and/or faults. When pore pressure reaches fracture pressure, the vertical permeability in the model must be increased to simulate release of the excess pore pressure by fracturing. Simulating hydrocarbon migration, which is dependent on both permeability and capillary pressure, from a high-pressure domain to a lower pressure domain without losing the pressure distribution, requires a detailed geological model and a thorough calibration.

In a deltaic system, such as the Niger Delta, a growth fault behaves as a complex zone for fluid flow, due to a relatively low horizontal permeability and a significant transient vertical permeability. In detail, permeability and capillary pressures in the fault zone are dependent on clay content (clay smearing) along the fault, possible cataclasis reducing sandstone permeability, and lithology juxtaposition, forming a complex structure along which fluids have to move. In this approach the fault is considered as a permanent active zone with transient fluid and pressure transfers, implying hydro-mechanical coupling.

The aim of 2D basin modelling is to simulate the geological history of a petroleum system in order to understand and quantify the hydrocarbon generation, migration and trapping. As a control of a correct simulation, the main hydrocarbon-bearing reservoirs must be restored with correct temperature, pore pressure, saturation and gas:oil ratio (GOR). The results of the present simulation show that all these parameters, and particularly pore pressures and GOR, are in accordance with well data. Fluid flow modelling allows vertical migration of the hydrocarbons from the deep overpressured domain to the hydrostatic domain, and a partial lateral transfer between adjacent reservoirs, without full pressure equalization. The model correctly predicts hydrocarbons in the main reservoirs and the appropriate GOR, even though local variations are not well simulated. Abnormally high pressures are maintained within the system even though fluid flow and hydrocarbon migration are simulated in a dynamic mode. The thorough geological description of the fault zone, which allows a detailed input of petrophysical parameters, is the key to such a result.