An integrated technical study was conducted for a field development project in west Hungary. This study offers a better solution for estimating petrophysical properties and fracture facies vertically along the well and laterally for 3D static and dynamic models of naturally fractured reservoirs in carbonate rocks.

More than 30 wells with 40 years of production history were used in order to build reliable static and dynamic models. The fracture class/facies plays an essential role in the spatial distribution of petrophysical properties during 3D reservoir modeling. It was defined by integrating conventional logs, image logs, drilling parameters, and production or well test data. Three fracture facies are defined as macrofracture (including permeable subseismic fault), microfracture, and host rock. Subsequently, the fracture class’s spatial distribution is guided by seismic attributes of fault likelihood combined with the geological concept of the fault and damage zone.

As a result, the established fracture classes along the wells are validated by static and dynamic subsurface data. A spherical self-organizing map (SOM) was also implemented for predicting the open-fracture location in wells having limited subsurface data. Moreover, fracture lateral distribution follows the distribution of the fault zone of the fault core, high damage zone, low damage zone, and host rock. The higher the fault displacement, the wider the damage zone and fault core formed. Macrofractures and microfractures frequently appear around the fault core and high damage zone. While only microfractures are dominantly present in the low damage zones, in contrast, the unfractured class is dominantly distributed in the host-rock area. Also, the lithologies are considered in distributing the fracture class because the rock mechanic properties and the number of fractures are strongly controlled by rock compositions. Once the fracture class is distributed, porosity, permeability, and water saturation are modeled in the three-dimensional (3D) geocellular model. Finally, this fracture class also plays a role as a rock typing for reservoir simulation. The saturation height model is built using the fracture class distribution resulting in the initialization, history-matching process, and production forecast from 20 wells showing excellent quality.

As a novelty, this study offers a better understanding of fracture distribution and accelerates the history-matching process with a more confident result of the production forecast. In the absence of advanced technologies, like image logs and production logging (PLT) measurements, this study still effectively assists us in recognizing the fracture presence and its quality in both well-depth interval and 3D spatial space, and successfully guided us in proposing new infill drilling with strong confidence and delivering on the high end of expected results.

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