Most porous naturally fractured reservoirs present a dual-timescale flow-system, due to a two-scale heterogeneity (typically stagnant and high storativity versus flowing and low storativity domain). This duality cannot be modelled explicitly, nor homogenised in reservoir simulation models. When the only flowing domain is the fracture network, and when the accumulation lies in porous low permeable matrix blocks, the exchange rate between the two domains drives the recovery of such reservoirs. So called dual- porosity simulation models must incorporate an adequate transfer function between fracture and matrix, that accurately represents the recovery mechanisms for an optimal reservoir management.
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