LAUSR

Abstract Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36–51%, and the earlier Miocene samples have a porosity of around 18–35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234–1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to