Abstract Magmatic activity can severely alter the thermal structure of a sedimentary basin, with variable effects on the petroleum system. The Namibe Basin of Angola (Cretaceous South Atlantic rift) contains well-exposed magmatic and petroleum system elements and allows integrated assessment of how magmatic activity can modify the petroleum system. The basin was affected by syn-rift and post-rift magmatic events, and bitumen is observed within both the Pre- and Post-Salt stratigraphical sections. In the Pre-Salt, fluorescent bitumen has a lacustrine signature and is associated with calcite and quartz cements. Onshore Pre-Salt units are thermally immature, and therefore the source rock that generated the Pre-Salt bitumen is likely located offshore. Hydrocarbons migrated or re-migrated via magmatically driven fluids, reaching the present-day onshore. Closer to magmatic units, non-fluorescent pyrobitumen was instead observed, evidencing hydrocarbon cracking processes following emplacement. In the Post-Salt, bitumen is in situ and shows marine-like signatures compatible with an immediate Post-Salt source rock depositional environment. In the immediate Post-Salt, units with very high total organic carbon values (TOC; up to 13.8%) and excellent source rock properties (hydrogen index >600 mgHC g −1 TOC) have reached thermal maturation. Within the Namibe Basin these Post-Salt source units lie in proximity to major Turonian–Coniacian–Santonian volcanic centres and associated shallow intrusions, which are likely to have caused thermally forced maturation processes and generation of the Post-Salt hydrocarbons. This paper demonstrates the importance of an integrated field, petrographic and geochemical approach in unravelling the influence of magmatic activity on basin thermal structure and petroleum systems.

Abstract The Elgin–Franklin complex contains gas condensates in Upper Jurassic reservoirs in the North Sea Central Graben. Upper parts of the reservoirs contain bitumens, which previous studies have suggested were formed by the thermal cracking of oil as the reservoirs experienced temperatures of >150°C during rapid Plio-Pleistocene subsidence. Bitumen-stained cores contaminated by oil-based drilling muds have been analysed by hydropyrolysis. Asphaltene-bound aliphatic hydrocarbon fractions were dominated by n -hexadecane and n -octadecane originating from fatty acid additives in the muds. Uncontaminated asphaltene-bound aromatic hydrocarbon fractions, however, contained a PAH distribution very similar to normal North Sea oils, suggesting that the bitumens may not have been derived from oil cracking. 1D basin models of well 29/5b-6 and a pseudo-well east of the Elgin–Franklin complex utilize a thermal history derived from the basin's rifting and subsidence histories, combined with the conservation of energy currently not contained in the thermal histories. Vitrinite reflectance values predicted by the conventional kinetic models do not match the measured data. Using the pressure-dependent PresRo ® model, however, a good match was achieved between observed and measured data. The predicted petroleum generation is combined with published diagenetic cement data from the Elgin and Franklin fields to produce a composite model for petroleum generation, diagenetic cement and bitumen formation.

Abstract This study gives valuable insights into the microstructure and pore space characteristics of 17 compositionally variable Visean shale samples from the Ukrainian Dniepr-Donets Basin (the ‘Rudov Beds’). The representative imaging area varies considerably (from 10 000 to >300 000 µm 2 ) as a function of the mineralogy and diagenetic overprinting. The pores hosted in organic matter (OM) are restricted to secondary solid bitumen. Based on high-resolution maps from broad ion beam scanning electron microscopy combined with organic geochemical and bulk mineralogical data, we propose that the amount of OM-hosted porosity responds to the availability of pore space, enabling the accumulation of an early oil phase, which is then progressively transformed to a porous solid bitumen residue. The type of OM porosity (pendular/interface v. spongy) is reflected in the individual pore size distributions: the spongy pores are usually smaller (<50 nm) than the pendular or OM–mineral interface pores. The OM-hosted porosity coincides with differences in the composition of the extract, with high amounts of extractable OM and saturated/aromatic compound ratios indicative of abundant porous solid bitumen. The average circularity and aspect ratio of the mineral matrix pores correlate with the corresponding values for the OM-hosted pores, which show a preferred bedding-parallel orientation, suggesting that compaction influenced both types of pore.