Abstract
Over 6,000 meters thick terrigeneous sediment (mainly shale/ siltstones/lithologies) of campano – Maastrichtian age has been recorded in the Anambra basin. These shale/siltstones lithologies have been reported to be rich in organic matter and had fulfilled other relevant condition for hydrocarbon source rock potential. However, only few patches of hydrocarbon shows have been documented elsewhere in the basin. This work attempts to critically evaluate the hydrocarbon source potential of the organic rich shale sediments in the basin. A sample set of 40 ditch cuttings of manly shale lithologies retrieved at different depths intervals from 2 well were subjected to standard geo-chemical and organic petrography investigations. The samples were analyzed for the total carbon content (TOC), extract yield, organic matter types and organic maturity level. As screening criteria, all the sample set were subjected to TOC measurement (LECO). The TOC values range from 0.81-1.40% (AKU2) and from 0.82-1.81% (AMA.1) most of the samples meet up with minimum required TOC value ().5%) for a siliciclastic sediments to be hydrocarbon prone. Extract yield range from 30.0 to 180.5 ppm (AKU2) and 30.0 to 128ppm (AMA 1). The Rock-Eval Pyrolysis data HI vs OI revealed that the samples fall within types II & III kerogen. This corroborates with the results of the maceral analysis. The maceral composition is mainly vitrinitic and liptinitic of terrestrial origin, which are over 65 volume percent. The shales are moderately rich in organic matter. Extract yields and the bitumen ratio (mg HC/g TOC) revealed that these samples are at immature stage of Hydrocarbon generation. This is also supported by Tmax values of between 430-4900C.KEY WORDS:- Terrigeneous, Campano – Maastrichtian, Vitrinit, Liptinite, Rock-Eval.
Highlights
Anambra basin is a cretaceous depocenter containing thick sequences of elastic sediment ranging from bituminous shales lignites through sandstone and marl and it’s Paleo-geographical strategic positioning as the proto-Niger Delta provides and ideal ground for geochemical evaluation of shales as oil/gas prone source rock
The plot of Hydrogen index against temperature maximum (T-max), which gives the vitrinite reflectance measure indicate that the shale samples could only generate dry-gas
Rock-Eval pyrolysis results revealed that shales of Nkporo has Hydrogen index of more than 200 which implies that significant oil can be generated from the shale
Summary
Anambra basin is a cretaceous depocenter containing thick sequences of elastic sediment ranging from bituminous shales lignites through sandstone and marl and it’s Paleo-geographical strategic positioning as the proto-Niger Delta provides and ideal ground for geochemical evaluation of shales as oil/gas prone source rock. Various published work e.g Ekweozor and Gormly [1983) Petters and Ekweozor (1982) have revealed that the Campano-Maastrichtian Nkporo shale exhibit characteristics of potential hydrocarbon source system for a series of oil/gas and condensate shows found within Ajali sandstone. The study area is roughly a triangular Sedimentary basin. The southern boundary coincides with the Northern boundary of the Niger Delta basin. The studied area is within Anambra basin, it covers an area of approximately 218 square kms bounded by Latitudes 5.50 and 6.50 north and longitude 6.50 and 7.50 east.
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