Reservoir quality evaluation of the Narimba Formation in Bass Basin, Australia: Implications from petrophysical analysis, sedimentological features, capillary pressure and wetting fluid saturation

The evaluation of reservoir quality was accomplished on the Late Paleocene to Early Eocene Narimba Formation in Bass Basin, Australia. This study involved combination methods such as petrophysical analysis, petrography and sedimentological studies, reservoir quality and fluid flow units from derivative parameters, and capillary pressure and wetting fluid saturation relationship. Textural and diagenetic features are affecting the reservoir quality. Cementation, compaction, and presence of clay minerals such as kaolinite are found to reduce the quality while dissolution and secondary porosity are noticed to improve it. It is believed that the Narimba Formation is a potential reservoir with a wide range of porosity and permeability. Porosity ranges from 3.1% to 25.4% with a mean of 15.84%, while permeability ranges between 0.01 mD and 510 mD, with a mean of 31.05 mD. Based on the heterogenous lithology, the formation has been categorized into five groups based on permeability variations. Group I showed an excellent to good quality reservoir with coarse grains. The impacts of both textural and diagenetic features improve the reservoir and producing higher reservoir quality index (RQI) and flow zone indicators (FZI) as well as mostly mega pores. The non-wetting fluid migration has the higher possibility to flow in the formation while displacement pressure recorded as zero. Group II showed a fair quality reservoir with lower petrophysical properties in macro pores. The irreducible water saturation is increasing while the textural and digenetic properties are still enhancing the reservoir quality. Group III reflects lower quality reservoir with mostly macro pores and higher displacement pressure. It may indicate smaller grain size and increasing amount of cement and clay minerals. Group IV, and V are interpreted as a poor-quality reservoir that has lower RQI and FZI. The textural and digenetic features are negatively affecting the reservoir and are leading to smaller pore size and pore throat radii (r35) values to be within the range of macro, meso-, micro-, and nano pores. The capillary displacement pressure curves of the three groups show increases reaching the maximum value of 400 psia in group V. Agreement with the classification of permeability, r35 values, and pore type can be used in identifying the quality of reservoir. (c) 2023 Sinopec Petroleum Exploration and Production Research Institute. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).