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As the exploration of hydrocarbons moves into more complex and deeper basinal settings the need to understand the effect of high temperatures and high pressures on reservoir quality and rock properties becomes even more important. The fluvial channel sandstone reservoirs of the Skagerrak Formation in the Central North Sea exhibit anomalously high porosities and permeabilities considering their depth of burial (>3500 m below sea floor). Despite the complex depositional setting, diagenetic history, high overpressure and temperatures encountered in the Skagerrak Formation, hydrocarbons are currently being produced. The Skagerrak Formation reservoirs used in this study have encountered overpressures of >40 MPa and temperatures up to ∼185 °C at present day maximum burial. To identify the role played by the high pressure and high temperature encountered in the reservoir sandstones a multidisciplinary approach involving petrographic, fluid inclusion, and burial history modelling studies has been adopted. Our interpretation of the results is that the generation of shallow overpressure in these fields limited mechanical compaction and also played an important role in minimizing pressure solution in the chemical compaction regime as evidenced by reduced quartz cementation. Fluid inclusions found in the quartz overgrowths indicate late-stage development with temperatures of formation in the range 130 to 170 °C coincident with late-stage deeper burial. Hydrocarbon emplacement occurred after quartz cementation and has had little to no effect on porosity preservation. The formation of well-developed authigenic chlorite (>70% surface coating) and, to a lesser extent illite clay coats with burial had a positive effect on porosity preservation even though permeability was marginally reduced in the illite-rich sandstones. A schematic porosity and quartz cement evolution model has been developed which allows for pre-drill prediction of reservoir quality in the Heron Cluster and provide valuable insights for other complex high-pressure high-temperature reservoirs.

We present a model that explains the patterns of sandstone burial diagenesis in certain oil reservoirs, in which petroleum migration and burial cementation were synchronous. The coincidence of these two processes controls the chemistry and distribution of major burial cement phases across the field, which in turn controls the distribution of reservoir quality, causing a rapid decline of porosity and permeability with depth. Such a rapid poroperm deterioration is observed in many North Sea sandstone oilfields; we highlight the Magnus Sandstone Member of the Magnus Oilfield, northern North Sea as a type example of such a reservoir. The two most significant elements of the synchronous cementation and migration model are that burial cementation in the reservoir occurs over a restricted time interval, probably less than 10 Ma and that rapid and widespread fluid circulation is not invoked to explain the concentrations of cements observed. We speculate that cementation takes place at, and in a series of zones below, the oil-water contact which descends as oil fills the reservoir, with little change to the bulk chemistry of the reservoir formation waters through time.