Abstract: How to Turn the Geological Image of a Fractured Reservoir into a Dual-Porosity Model

CACAS, M.C., S. SARDA, B. BOURBIAUX, and J.C.SABATHIER

Both characterization and simulation of naturally fractured reservoirs benefited from major advances in the recent years. On the one hand, techniques of data integration and 3D imaging are available to build representative geologic images of fracture networks. On the other hand, multi-purpose dual-porosity simulators have been developed to deal with any scenario of reservoir exploitation. However, the "sugar lump" representation of the fractured medium used in these simulators is actually very far from geologic images. Hence, the reservoir engineer remains faced with the difficulty of parameterizing the dual-porosity model, and particularly of finding correct input data for equivalent fracture permeabilities, and equivalent matrix block dimensions.

New and systematic methodology and software have been developed to compute those equivalent hydraulic parameters:

1. A tensor of equivalent fracture permeability is derived from 3D flow computations in the actual fracture network using a resistor network method;

2. The equivalent block dimensions in each layer are derived from the identification of a geometrical function based on capillary imbibition.

They have been validated on simple fracture networks from reference fine-grid simulations with a conventional reservoir simulator. Their efficiency to process actual complex geological image is also demonstrated..

With such a methodology and linking software, the reservoir engineer can build a representative dual-porosity model from the geologic images resulting from field fracturing data information. This optimal use of geological data will improve the reliability of dual-porosity reservoir production forecasts.

AAPG Search and Discovery Article #90942©1997 AAPG International Conference and Exhibition, Vienna, Austria