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Carbonate reservoirs present a complex scenario, as they undergo mechanical compaction and porosity reduction like shales, but with the added complication of diagenetic overprinting. This overprint can increase or decrease porosity and make velocity-porosity-depth relationships inherently unpredictable. However, an integrated approach that extracts variable porosity with various measurements calibrated to actual formation pressure data gives more reliable pore pressure prediction in this heterogeneous carbonate reservoir.

To validate this approach, our study used conventional porosity measurements of neutron, density, sonic, and other open hole logs. We extracted porosity using conventional empirical relationships from density, cross-plot porosity, compressional acoustic, and resistivity data, transforming these porosity trends into pore pressure calibrated with measured formation pressures from formation testing data.

The results showed an excellent match, indicating that the porosity-based pore pressure estimation from conventional logs was a reliable predictor of formation pressure in carbonate reservoirs. Furthermore, combining LWD resistivity ahead of the bit to perform real-time pore pressure prediction is possible.

Our study demonstrates the effectiveness of an integrated approach to predict pore pressures in heterogeneous carbonate reservoirs. By using a combination of various measurements calibrated to actual formation pressure data, our approach provides more reliable and accurate predictions than traditional porosity-based shale pore pressure prediction methods.