Modelling the Central North Sea pressure history

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High pore pressures in compartmentalized Mesozoic reservoirs in the Central North Sea are a challenge to predict using conventional porosity-based methods applied to shale mudrocks. Porosity and effective stress relationships, which work well in young and rapidly deposited basins such as Tertiary deltas, are not readily applicable to older, high-temperature sediments, and cannot be applied to non-reservoir chalk carbonates in which diagenesis is the principal control on porosity change. Basin modelling offers an alternative and complementary approach to conventional pressure prediction. New compaction and fluid flow relationships have been applied in commercial basin modelling software to model a 74 km 2D profile across the Central North Sea extending from the Fulmar Field in Block 30/16 across the Judy-Joanne High (Block 30/7) to the UK-Norwegian border in Block 30/8. The resulting models also tested chemical compaction simulation as a way to handle porosity change in non-reservoir chalks. The models were calibrated using porosity and permeability data collected as part of the study. When rock property data were satisfactorily matched, predicted pore pressures were compared with pore pressure measurements from multiple reservoirs in several boreholes. The model results closely match actual pressures from thin base-Tertiary reservoirs, which are likely to be close to their equilibrium with overlying shale mudrocks. The models underestimate the pore pressures in the deeply buried Mesozoic reservoirs. We interpret the deep pressures in relation to the contribution to overpressure from compaction disequilibrium (principally Tertiary sediment loading) relative to other, fluid inflation processes, such as gas generation. Future modelling, incorporating new data on fluid volume change when kerogen generates gas or oil cracks to gas, is now necessary to examine the magnitude of overpressure from these secondary sources.