Abstract
This study focuses on the analysis of Lamé’s parameters in clastic rocks of different reservoir quality in the Akau field of the Central Swamp, Niger Delta. Two channel-reservoir models filled with sands of different geological ages and located at different depths were considered to investigate reservoir heterogeneities. The channel sands are of different reservoir quality, differing in their shale content and porosity. Three Gassmann fluid-substitution cases (brine, oil, and gas) were analysed. In each case, compressional- and shear-wave impedances and Lamé parameters were calculated. Interpretation of well-log data was based on crossplots of elastic parameters, allowing differentiation of reservoir sands from shale intervals and other lithofacies. The porosity of the reservoirs ranges from 18–30%; µρ values range from 1.5e+13-2.5e+13 units, λρ values for the oil case range from 1.5e+13–2.0e+13 units, and µρ values for the gas case range from 1.5e+13–1.8e+13 units. The oil case shows µρ values of 1.6e+13 – 1.7e+13 units, which are less than λρ. Changes in porosity with respect to µρ occur at a much faster rate than changes in porosity with respect to λρ. It can be seen that µρ is a more sensitive parameter for fluid detection over a wide range of porosity despite a relatively small range of elastic parameters. As a result, µρ is a more reliable parameter for fluid detection in reservoirs with different sand properties. Combining well-log and 3D pre-stack seismic data collected in the study area enabled high-resolution lithology and fluid characterisation, allowing lithology classification, fluid detection, and separation of fluids in porous reservoir sands. The major lithologies were sand and shale, while the fluids included gas, oil, and brine.