Abstract Dual porosity numerical models are widely adopted in the oil business to model the performance of complex systems characterised by two different porous media. However, for numerical models of a certain complexity due to the large number of active grid-blocks, the dual porosity approach is often computationally unaffordable especially when a compositional formulation must be used.
This paper describes the methodology that was developed to mimic the dynamic performance of a complex triple porosity system by means of a single porosity model. The three porous systems were the matrix blocks, the fracture network and the dissolution karst bodies. The methodology was derived for a complex massive carbonate field not yet producing which is currently envisaged to be developed via miscible gas injection.
The matrix and karst bodies were statically modelled independently from the fracture network system. The characterisation of the fracture network has been driven using a DFN approach by integrating seismic, continuity cube interpretations and well data, such as FMI and mud losses. Due to the lack of dynamic data, the fractures' petrophysical properties were calculated from correlations. The matrix, karst bodies and DFN derived fractures were then up-scaled to a dual porosity model. The dual porosity model dynamic performance was considered as the reference to be matched by an equivalent up-scaled single porosity model.
An innovative procedure to up-scale matrix, fracture and karst properties into the equivalent single porosity model was tested for both a natural depletion and a miscible gas injection scenario. The methodology was firstly evaluated in representative sector models and then extended to the full field model. This methodology resulted to be very efficient being able to reduce the simulation time and model complexity drastically while capturing all the dynamic key performance indicators of the more complex and computationally expensive dual porosity model.
Introduction In the recent years the detailed acquisition of field data and the use of specialist software packages enable geoscientists to characterize the distribution of fractures at different scales and to up-scale the information to field simulation models. Among the different techniques, the use of Discrete Fracture Network (DFN from now on) models is the most advanced one since it allows to model the complexities, heterogeneities and properties of the natural fractures at different scales of investigation. The definition of a DFN or several DFN models requires the joint effort of several disciplines from seismic, to structural geology, from core analysis to petrophyisics. DFN models represent the starting point for an upscaling process with the final aim of performing 3D numerical simulations necessary to understand the dynamic performance of the network. The optimum workflow would require to up-scale the fracture properties in terms of porosity, permeability and spacing to a dual porosity model. In the last 5 years this has become a quite common methodology which finds several applications worldwide.
The field under investigation is envisaged to be developed via miscible gas injection; in order to properly model the complex thermodynamic of such process, a compositional model is required. In addition, the size of such field and the lateral and vertical reservoir heterogeneity require the use of a very large number grid-blocks in the dynamic model. As a matter of fact, the environment of this field can be regarded as a triple porosity system which consist of matrix, fractures and dissolution karst bodies. The DFN approach was adopted to characterize the fracture system. However, the use of the dual porosity option in a compositional model of such complexity is not computationally feasible and is unpractical.
An innovative methodology was investigated for the simulation of the dynamic performance of such complex triple porosity system by means of a single porosity model. This methodology was tested for both a natural depletion and a miscible gas injection scenario.
The methodology consists of defining the petrophysical properties of an "equivalent single porosity model" with performances identical of the more complex and computationally expensive dual porosity one (Figure 1).