We present a case study from a naturally fractured reservoir in the Middle East, where matrix provides the main porosity in the system, but fractures account for most of the permeability. Fracture data was only available from cores and image logs for 3 wells. The lack of extensive data precluded the application of standard fracture modeling workflows. However, well pressure test and well interference test data were available for over 15 wells, which provided the best measure of the impact of fractures on reservoir properties.

Fracture modeling was performed to quantify the contribution of fractures to permeability and porosity in the reservoir. Results were obtained through a combination of standard fracture modeling workflows using the scant data available, and geostatistical simulation techniques to calibrate the results with well test data. The uncertainty related to the lack of detailed fracture data was quantified by proposing alternative scenarios.

Fracture permeability in the field is dominated by seismic scale faults and their associated deformation zones. Different scales of fracturing (small fractures, fault deformation zones and sub-seismic faults) are required to accurately honor the permeability estimated from well tests and the observations from well fracture data.

Three scenarios, each with calibrated fracture permeability and porosity, were generated in under 5 days, ready for use in simulation. The methodology used makes it possible to update and modify the modeling scenarios interactively during the history matching process.

Fracture modeling is a task often left to the specialized geologist and requires significant amounts of fracture data. However, a rapid assessment of the impact of natural fractures on reservoir behavior can be made by the non-specialist modeler during early phases of exploration or field development, leaving advanced modeling to stages in which more data and time are available.

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