The Bongor Basin is a typical lacustrine passive-rifted basin situated in the West and Central African Rift System (WCARS). It has experienced two phases of tectonic inversion and features a complex process of petroleum generation and accumulation. A total of 41 crude oil samples from the basin were geochemically analyzed to investigate their compositions of molecular markers. The results show that the oils have similar origins and are likely to belong to the same oil population. However, there are significant differences in geochemical characteristics and physical properties, caused by the secondary alteration. The relative contents and distribution patterns of normal alkanes and acyclic isoprenoids indicate that some of the oils have suffered biodegradation to varying degrees. The samples can be divided into three categories according to their relative degrees of degradation: normal oil, slightly biodegraded oil (PM 1–3), and severely biodegraded oil (PM 5–7). The burial depth of oil reservoirs in this area is the predominant factor impacting on the level of biodegradation. Crude oils in reservoirs with burial depths of less than 800 m are all severely biodegraded, while oils in reservoirs with burial depths greater than 1300 m have experienced no evident biodegradation. In reservoirs with burial depths between 800 m and 1300 m, the biodegradation degrees vary from normal to severely biodegraded. Oil reservoirs with burial depths less than 1300 m and adjacent to major faults are readily subject to biodegradation, while reservoirs with similar burial depths, but a certain distance away from major faults, have suffered no evident biodegradation. Moreover, if primary reservoirs have been modified by tectonic activity after accumulation, the crude oils are more likely to be biodegraded. Faulted anticline traps may create more favorable geological conditions for preservation of crude oil than reverse extrusion anticline reservoirs. This study may provide practical guidance for the assessment and prediction of oil quality in future oil exploration.
Abstract The Lower Cretaceous Manville Group of Upper McMurray Formation is one of the main bitumen reservoirs in Athabasca. In this study, the relationship between reservoirs heterogeneity and bitumen geochemical characteristics were analyzed through core and microscopic observation, lab analysis, petrophysics and logging data. Based on the sedimentology framework, the formation environment of high‐quality oil sand reservoirs and their significance for development were discussed. The results indicate that four types lithofacies were recognized in the Upper McMurray Formation based on their depositional characteristics. Each lithofacies reservoirs has unique physical properties, and is subject to varying degrees of degradation, resulting in diversity of bitumen content and geochemical composition. The tidal bar (TB) or tidal channel (TC) facies reservoir have excellent physical properties, which are evaluated as gas or water intervals due to strong degradation. The reservoir of sand bar (SB) facies was evaluated as oil intervals, due to its poor physical properties and weak degradation. The reservoir of mixed flat (MF) facies is composed of sand intercalated with laminated shale, which is evaluated as poor oil intervals due to its poor connectivity. The shale content in oil sand reservoir is very important for the reservoir physical properties and bitumen degradation degree. In the context of regional biodegradation, oil sand reservoirs with good physical properties will suffer from strong degradation, while oil sand reservoirs with relatively poor physical properties are more conducive to the bitumen preservation.
The Bongor Basin in southern Chad is one of the Cretaceous–Paleogene rift basins developed on the Precambrian crystalline basement and has been confirmed as a petroliferous basin in the last decade. Less than 400 m of Cenozoic unconsolidated sediments are separated by an unconformity from an underlying section of Lower Cretaceous units, in turn separated by another unconformity from underlying Precambrian basement. In addition, there is a locally low-angle unconformity within the Cenozoic section. A synthesis of apatite fission-track analysis data in four wells from the basin reveals two cooling episodes from Late Cretaceous to early Paleocene (beginning between 75 and 60 Ma) and mid-Miocene, respectively. The results suggest that regionally synchronous cooling is a likely scenario. The first exhumation between 75 and 60 Ma affected the whole basin, and the magnitude of uplift and erosion was approximately 1100–1250 m across the whole basin. In contrast, the second exhumation during the Miocene affected mainly the northern part of the basin while the magnitude was weak and could not be detected in the southeast of the basin. Potential trapping structures, for example, fault blocks and synsedimentary anticlines, formed prior to and inverted anticlines as a result of the first cooling phase of exhumation (strong compressional inversion) and were available for hydrocarbon migration and accumulation during the main phase of hydrocarbon generation. The Miocene exhumation was less pronounced and had weak or no impact on the hydrocarbon generation and accumulation.
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