Fluid Substitution-Based Reservoir Studies and Seismic Response in ‘Vyshion’ Field, Niger Delta

Abstract

A case study of how fluid substitution affects the seismic waveforms is presented. Direct hydrocarbon prediction on the seismic data is prone to inaccuracy without investigating the impact of fluids on the seismic waveforms since the seismic data is influenced by mineral composition, porosity, salinity, pressure, and other factors in addition to fluid type. The study relies on 3D seismic data and log data gathered from 3 wells. Petrophysical and rock physics models were computed in order to understand the seismic dataset. In the analysis, prolific hydrocarbon intervals were identified. Then, model compressional velocities and densities obtained for various fluid scenarios were generated by using the Gassmann fluid substitution theory. Normalized bulk modulus approach was used to reduce the ambiguities that shales portend on the velocity models. Model synthetics were generated. The synthetic seismograms were compared with the seismic dataset in order to understand how fluid saturation and lithology impacts the seismic data. In the analysis, two major hydrocarbon bearing reservoirs were delineated. Other mapped reservoirs have characteristic indices that make them unsuitable for the fluid modelling. The results show that the model oil velocity model better approximates the field velocity. The density models produced the same kind of results, suggesting that the reservoir fluid is oil. The generated synthetic diagrams show that replacing the in-situ fluid with either gas or oil models has no appreciable impact on the seismic dataset’s amplitude waveform. This is because seismic reflection amplitude only slightly increases each time gas is assumed. By using the seismic data from this field of study, hydrocarbons cannot be directly predicted from amplitude anomalies because the lithology better influences the seismic waveforms than the fluid composition.