Abstract The main source of oil production in Vietnam is from naturally fractured basement reservoirs (NFBR). The SN reservoir, which is situated offshore Vietnam in Mekong basin, consists of fractured/weathered granite and granodiorite rocks and fully encased by highly over-pressured shales, which act both as seal and source rock. To date, the existing reservoir simulation models have failed to give an adequate history match without invoking the presence of a giant aquifer, something which is not supported by the existing dynamic and geological data. Furthermore, in the original simulation models, zero capillary pressure (Pc) was assumed and a single set of relative permeability (kr) curves and endpoints was assigned for the whole reservoir. These assumptions are open to question as the porosity (Φ) and permeability (k) varies by several order of magnitude for micro- to macro-fractures of this NFBR. In this work, we have investigated a number of possible alternative sources of energy to achieve a satisfactory history match including (i) increasing the STOOIP by increasing overall pore volume (PV) of the reservoir and (ii) using different values of rock compressibility (Cr) and (iii) accounting for rock compaction (porosity reduction by fracture closure) due to reservoir pressure (Pr) reduction during production. We found that modelling porosity reduction by compaction together with a minor aquifer gave the best history match and is geologically coherent We also considered using a dual rock-type model, with microporosity zones (Φ<1%) consisting of a network of microfractures and weathering, developed along the macroporosity network which coincides with the major basement faults which criss-cross the granite basement. Microporosity zones were assigned non-linear kr curves with appropriate end points and Pc, while macroporosity zones were assigned diagonal kr curves and zero Pc. Dual rock-type models gave improved history matches. A comprehensive sensitivity study on variations in kr curves and their endpoints showed that these greatly affect reservoir flow behaviour. Finally we investigated variations in Pc but found that it had negligible effects in our models.