Modeling permeability of naturally fractured reservoirs for simulation studies and field development planning is very challenging since the data required for characterizing the magnitude and distribution of reservoir fracture permeability is very limited. Fracture permeability is traditionally measured from cores and/or estimated from well tests. These estimations usually work adequately at well locations for permeability modeling but poorly between wells. Modeling fracture permeability distribution between wells and/or away from wells is a very important step to build a reliable reservoir simulation model for business needs.
This paper presents a new method/workflow for modeling effective permeability of a naturally fractured carbonate reservoir from seismic attributes. The new method directly converts fracture textures and distributions from seismic attributes into permeability for reservoir simulation. Core and log data are used to create fracture regions and the distribution of fracture density; well test data are applied to generate isotropic permeability; and seismic attributes (e.g., ant-tracks, curvature, and anisotropy) are utilized to model the fracture network and permeability anisotropy. New equations are created to calculate effective permeability of the reservoir by scaling up and down between core/well test and seismic data. Two history match parameters (fracture network connectivity and permeability anisotropy) are introduced to assist the history match process within the guidance of seismic and geologic data.
The new method/workflow has been successfully applied to solve the history match challenges of a naturally fractured reservoir in a Middle Eastern field for which no history matched model was achieved before. Applying the new method has significantly improved water movement matches in all producers of the field.