Hydraulic fracturing and leakage can be controlling factors for hydrocarbon leakage in overpressured sedimentary basins over geological time. Knowledge of the lateral flow properties of major faults is needed to simulate how pressure generation and dissipation can influence the sealing potential of cap rocks. The hydraulic fracture processes in the cap rock need to be evaluated to quantify timing and the amount of hydraulic leakage.

To address these issues, we use a single-phase simulator, which calculates pressure generation resulting from mechanisms, such as shale compaction and drainage, and mechanical and chemical compaction in sandstones. Pressure dissipation and lateral flow are simulated between different pressure and stress compartments defined by major fault patterns at the top reservoir level. An empirical model for the minimum horizontal stress is applied to the Griffith–Coulomb failure criterion and the sliding criterion to estimate hydraulic fracturing.

Only minor changes, if any at all, in the amount and timing of hydraulic fracturing and leakage in the modeled pressure compartments are present when the coefficient of internal friction and frictional sliding are varied. When varying fault permeability, low fault permeabilities give early leakage, whereas high permeabilities result in late or no hydraulic fracturing and leakage. Our simulations also suggest that leakage in one pressure compartment influences the neighboring compartments, and large compartments control the leakage pattern in surrounding areas. The amount of cumulative leakage depends on the timing of leakage and size of the compartment. Uncertainties of timing and leakage for different compartments can be estimated using the pressure measured in the wells today as calibration. The uncertainty in the estimates can be used as guidelines for possible hydrocarbon leakage risks.