SOURCE:

Faculty: Physical Sciences
Department: Applied Geophysics

CONTRIBUTORS:

OBASI, ARISI IKENNA
PROF. A.G. ONWUEMESI

ABSTRACT:

This work analyzed gravity data and compared it with existing geothermal gradient, well and elevation data over the Anambra Basin, with the intention to enhance the understanding of the subsurface geology of the study area and its petroleum potential. Method of study involved data acquisition and reduction, generation of Bouguer gravity map, separation of regional and residual anomalies, application of continuation filters, which were carried out using the Oasis Montaj software, and cross – correlation of gravity data with well, elevation and geothermal gradient data sets. The interpretation of the Bouguer gravity anomalies ranged from visual inspection of the graphs and profiles to more complex methods that involved modelling of the subsurface layers. Sediment thickness in the basin ranged approximately from 1.8 km to 7 km. The highest density value areas (≥ 30 mal) are associated with igneous rocks; the intermediate density values (11 – 29 mgal) are associated with Cretaceous sedimentary rocks, while the lower density areas (< 11 mgal) are associated with Tertiary rocks. The boundary of the Anambra Basin has been inferred along Umueze – Nteje – Agoaliji axis in the southwestern to the southern part, Obolo Afor – Obolo Eke axis in the northeastern part, and Adoru - Ekwuroko – Ukehe axis in the northern part. Contrary to earlier view which suggested the Afikpo Basin as part of the Anambra Basin considering the fact that they were both result of the same Santonian thermo-tectonic event and there is really no physical separation or barrier between the two areas, this study has established that the Afikpo Basin is a distinct basin from the Anambra Basin with physical barriers separating them and should be accorded the status of an inland sedimentary basin in Nigeria. A correlation of gravity and well data indicated that only the intermediate density zone (11 – 29 mgal) has hydrocarbon. Major hydrocarbon reservoirs in this basin occurred within the sediments of Coniacian Awgu Formation and Campano – Maastrichtian Nkporo Group. Regional dip is southwards and has favoured hydrocarbon generation and distribution towards the southern part of the basin. Reservoirs occur at greater depths towards south. Geothermal gradient for the wells which have yielded hydrocarbon ranged from 46 – 60 0C/km. The geothermal gradient in the study area is hydrodynamically controlled.