Limitations in numerical well rest modelling of fractured carbonate rocks

Abstract

Interpreting well-tests in (fractured) carbonate reservoirs poses significant challenges because these reservoirs often demonstrate triple porosity system (fracture-matrix-vugs) characteristics. However, there is no "unique" triple porosity system: The matrix can behave as a double porosity/dual permeability system whilst the fractures provide the third system; there may be two fracture systems and a single matrix; there may be vugs (macropores), mesopores and micropores to provide very large contrasts in matrix permeabilities. Modelling these systems is challenging because of the need to include heterogeneity for the matrix (or multiple matrices) and fracture(s) and determine the correct coupling between these systems. The typical well test response in fractured systems - the classic double porosity "V" - can provide factors such as ω and λ as a description of fracture-matrix interaction (storativity ratio and the interporosity flow coefficient, respectively). Understanding how these two parameters relate to the description of matrix and fracture properties in triple porosity systems requires exploration of new scenarios in numerical well test modelling (sometimes called "geological well testing"). In this paper, we set out some of the reservoir description, modelling and simulation challenges to provide guidance on how to set up systematic models and determine the appropriate family of geotype (families of closely related pressure derivative response) curves for fractured carbonate systems in order to understand the interpretation of co and X.