No abstract

No abstract

No abstract

A high magnitude of overpressure is a characteristic of the deep, sub-Chalk reservoirs of the Central North Sea. The Upper Cretaceous chalk there comprises both reservoir and non-reservoir intervals, the former volumetrically minor but most commonly identified near the top of the Tor Formation. The majority of nonreservoir chalk has been extensively cemented with average fractional gross porosity of 0.08, and permeability in the nano-to microDarcy range (10 218 -10 221 m 2 ), and sealing properties comparable to shale. Hence deeply buried chalk is comparable to shale in preventing dewatering and allowing overpressure to develop. Direct pressure measurements in the Chalk are restricted to the reservoir intervals, plus in rare fractured chalk, but reveal that Chalk pressures lie on a pressure gradient which links to the Lower Cenozoic reservoir above the Chalk and the Jurassic/Triassic reservoir pressures below. Hence a pore pressure profile of constantly increasing overpressure with increasing depth is indicated. Mud weight profiles through the Chalk, by contrast, show many borehole pressures lower than those indicated by these direct measurements, implying wells are routinely drilled underbalanced. The Chalk is therefore considered the main pressure transition zone to high pressures in subChalk reservoirs. In addition to its role as a regional seal for overpressure, the Base Chalk can be shown to be highly significant to trap integrity. Analysis of dry holes and hydrocarbon discoveries relative to their aquifer seal capacity (the difference between water pressure and minimum stress) shows that the best empirical relationship exists at Base Chalk, rather than Base Seal/Top Reservoir, where the relationship is traditionally examined. Using a database of 65 wells from the HP/HT area of the Central North Sea, and extending the known aquifer gradients from the Fulmar reservoirs via Base Cretaceous to Base Chalk, leads to a risking threshold at 5.2 MPa (750 psi) aquifer seal capacity. Discoveries constitute 88% of the wells above the threshold and 36% below, with 100% dry holes where the aquifer seal capacity is zero (i.e. predicted breached trap). This relationship at Base Chalk can be used to identify leak points which control vertical hydrocarbon migration as well as assessing the risk associated with drilling high-pressure prospects in the Central North Sea.

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.