Continuous permeability predictions in heterogeneous reservoirs using Vshale and microstructure calibrated free-fluid models (a combined study of a Niger Delta field and the tight gas sandstone of the southern North Sea)

The well-established free-fluid model from NMR technique provides continuous permeability values that closely match with core permeabilities better than most theoretical models especially when it is core calibrated for field specific use. However, only few wells have NMR logs in a field while marginal fields may not have any due to economic reasons. This study explored means of achieving one of the overriding objectives of most marginal field operators, which is to reduce the overall cost of production to the attainable minimum. The free-fluid model was modified into two simple and cost-effective models in order to optimize its applicability to predict permeability in the absence of NMR data. The two new models, which were developed for the single and double porosity systems analyzed in this study, consist of calibration parameters that can be empirically determined to account for variation in reservoir quality based on the rock type profile per field. A non-matrix parameter, α , was introduced into the model derived for tight gas sandstone being regarded as a double-porosity formation. This inclusion represents the permeability contribution of natural fractures or any crack-like pores to the different flow units. By using the alternative version to the known free-fluid model, continuous permeability curves that match experimental results were predicted without NMR logs.