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 Central Sumatra basin contains the Pematang-Sihapas(!) petroleum system, the most prolific petroleum system in southeastern Asia. A chronostratigraphic framework based on well logs and cores provides insights concerning the occurrence of seals, reservoirs, and the distribution of hydrocarbons. Oil sourced from lacustrine lithofacies of the Pematang Group ( i.e. , the Brown Shale) in the underlying rift sequence migrated vertically until reaching a thick paleosol horizon (representing the 25.5 Ma sequence boundary). Thereafter, oil migrated toward the eastern margin of the basin charging the giant Minas and Duri fields. Erosional truncation (incised valley development) of paleosols and faults provided “windows” for migration of oil into overlying Miocene (Sihapas Group) marine, sandstone reservoirs. Well log correlations and core data reveal the common presence of incision along the 25.5, 22, 21, and 17.5 Ma sequence boundaries. Oil accumulated preferentially in basal transgressive sandstones. Approximately 80 percent of the recoverable oil resides in the lower part of the 21 Ma depositional sequence. These well sorted, medium-grained sandstones (Bekasap Formation) record deposition in estuarine (presumably macro-tidal) settings. Marine sandstones within the overlying 16.5 and 15.5 Ma depositional sequences are oil-saturated; however, they are very fine-grained and have inherently low permeability. The regional top seal for Sihapas reservoirs is formed by calcite-cemented, glauconitic shales and siltstones (Telisa Group) that record the maximum Miocene transgression. Relatively small oil accumulations in the underlying alluvial-fluvial and lacustrine sandstones of the Pematang Group are sealed by paleosols. The permeability of the fluvial reservoirs is degraded by poor sorting and pervasive authigenic kaolinite. In distinct contrast, Sihapas sandstones have undergone minimal diagenesis. This newly developed sequence stratigraphic framework has dramatically improved the understanding of the correlation and distribution of Miocene hydrocarbon reservoirs and seals in Central Sumatran oil fields.

Abstract The northern (NKR) and central (CKR) segments of the Kenya Rift are among the most important areas of the East African rift system for hydrocarbon prospecting because they offer the oldest and longest lived sedimentary basins and they are a crossover area between Ce-nozoic and Cretaceous rifts. During the 1970s and 1980s, the interest of oil companies focused in the Turkana depression and the northeastern region of Kenya. Seismic reflection surveys and several exploration wells enabled the identification of several deeply buried basins: (1) In the NKR, three strings of north–south-oriented half grabens, the oldest known basins being of Cretaceous?–Paleogene to middle Miocene age; (2) In the CKR, two north–south half grabens, the Baringo-Bogoria Basin (Paleogene–Present), and the Kerio Basin (Paleogene–upper Miocene). All basins are filled by up to 8 km (5 mi) thick sediments of alluvial, fluviodeltaic, or lacustrine origin and volcanics of late Eocene to Neogene age. New studies have focused on reservoir and/or source rock quality in several of these basins. In terms of hydrocarbon potential, arkosic sand stones in CKR or NKR demonstrate a fair to good reservoir quality, with porosity up to 25%. Strong changes in terms of diagenetic alteration relate to deformation events or change in sediment source as a result of tectonic activity and hydrothermal fluid circulation associated with volcanism. High-quality source rocks were deposited in freshwater lake environments under a tropical climate. Such environments have been identified during the Paleogene in the NKR and lower Neogene in the CKR. The combination of reservoir and source rock characteristics results in a provisional classification of each studied basin, in terms of very high to medium potential for hydrocarbons.