Empirical Analysis of Fracture Characterisation and Dual-Porosity Model Calibration in the Nkalagu Limestone Formation, Ebonyi State, South East Nigeria

Natural fracture networks in the Nkalagu Limestone Formation in Ebonyi State, South East Nigeria, provide the dominant permeability pathways in this carbonate sequence and fundamentally control well productivity in hydrocarbon accumulations associated with these carbonates. This study presents an empirical characterisation of the fracture network and calibrates a dual-porosity model using an integrated data set from outcrop analogues and borehole measurements. Fracture orientations, apertures, and spacings were measured from systematic scanline surveys at four outcrop exposures of the Nkalagu Formation accessible in Ebonyi State quarry operations. Borehole image log analysis from two exploration wells intersecting the subsurface equivalent interval provided subsurface fracture intensity and orientation data. Dual-porosity model calibration was performed using the Warren and Root model applied to pressure transient data from extended production tests of both wells. Interporosity flow coefficient and storativity ratio values were estimated from derivative analysis and confirmed by multi-rate flow data. Matrix porosity and permeability from laboratory core measurements were 8.3 percent and 0.45 millidarcy respectively, while total system permeability derived from well test analysis was 34 millidarcy, confirming fracture-dominated flow. Discrete fracture network simulation using derived fracture statistics reproduced the anisotropic permeability tensor consistent with observed well test results. The calibrated dual-porosity model provides a predictive reservoir characterisation framework for development planning in the Nkalagu carbonate play. Keywords: fracture characterisation, dual-porosity model, Nkalagu Limestone, Ebonyi State, carbonate reservoir.