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 non-reservoir chalk has been extensively cemented with average fractional gross porosity of 0.08, and permeability in the nano- to microDarcy range (10 −18 –10 −21 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 sub-Chalk 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.

Abstract Petrographic, SEM, and chemical analyses of closely spaced samples from a core of sandstone and shale (Oligocene Frio Formation, Brazoria County, Texas) reveal a mechanism for secondary porosity development. Maturation of organic and inorganic materials in the shale produced a solvent solution which, upon expulsion, resulted in zoned reservoir quality in the adjacent sandstone. Framework grain dissolution (secondary porosity) originated at the sandstone/shale contact zone (near the solvent source). Aluminum in this zone was not conserved by the process but instead was removed by mobile, shale-derived organic complexers. The production of these complexers (ligands) appears to be essential to the process of framework grain dissolution. Aluminum removal elevated the silica activity and resulted in precipitation of authigenic quartz cement. Secondary porosity was developed to a lesser extent farther away from the shale. Imported aluminum from the contact zone and a failure to complex aluminum adequately resulted in kaolinite precipitation. This sink for silica prohibited quartz precipitation. This general process of framework grain dissolution is probably common in sandstone/shale sequences. In summary, secondary porosity development is accentuated by: (1) high initial permeability, (2) increased relative thickness of shale to sandstone, (3) increased organic content in the shale, and (4) abundant soluble grains (potential secondary pores).

Abstract Framework grain dissolution (FGD) involving feldspars and rock fragments was found to be significant to reservoir properties in sandstones with more than 10% soluble grains. FGD porosity ranged up to approximately 70% and averages about 30% of the visible porosity in a study of some reservoir sandstones. FGD does not appreciably increase reservoir permeability. However, the amount of FGD porosity developed was found to be a function of the sandstone’s initial permeability. We propose that clay and organic maturation in shales produce the necessary water, acid, and complexing agents for FGD. The FGD solvent is expelled into the sandstones where feldspars and rock fragments are dissolved, and the resulting aqueous aluminum is complexed for transport out of the sandstone.