Predicting Oligocene reservoir potential in the deep-water Western Niger Delta : an integrated basic modelling and diagenetic study

Abstract

This study presents a multidisciplinary integrated approach undertaken in predicting the reservoir potential of an untapped deeper Oligocene succession located offshore of the western Niger Delta. The shallower Miocene sands are known to have excellent reservoir quality with porosities exceeding 30 % and permeability in the Darcy range. The study revealed a distinctive geometry in the deep marine depositional systems around mud diapirs. Unlike shallower Miocene reservoirs that are characterised by highly amalgamated channel systems, the Oligocene systems’ depositional pattern shows a transition from a confined channel to a weakly confined lobate morphology, particularly when the channel system approaches depressions flanked by mud diapirs. High seismic reflection amplitudes suggest they are sand-rich and possibly hydrocarbon bearing. SEM Photomicrographs reveal a rare presence of quartz overgrowth in the Middle Miocene interval that increases in volume to less than 3% in the Lower Miocene reservoirs, suggesting that the deeper Oligocene reservoirs that are buried under higher temperature conditions are likely to have significant quartz cement. Wireline log evaluation from the single well that penetrated part of the Oligocene succession supports this claim, with estimated reservoir properties, particularly porosity and permeability, being significantly lower in the Oligocene sands compared to the shallower Miocene reservoirs. Of the 7 units of Oligocene sands encountered in this well, 3 sand units are noted to be thin bedded, highly compacted with low porosity. Results from basin modelling reveal that the Oligocene reservoirs have been subjected to maximum temperatures greater than 70˚ C from Early Miocene to present day and have had around 13 % of the pore space occluded by quartz cement. The results of this integrated approach suggest that the potential Oligocene reservoir within the vicinity of the study area is likely to have its reservoir quality partially compromised by quartz cementation. However, by considering the time of charge versus the time of significant quartz cementation, it is likely that no more than 7% of the Oligocene pore space is cemented. In all 4 modelled hydrocarbon accumulations, peak hydrocarbon saturation was attained between 15 and 8Ma, predating the onset of significant quartz cementation below 7Ma.