Downhole fluid analysis (DFA) has been used successfully to delineate reservoir vertical and lateral connectivity and properties of the produced fluids. The DFA tools can measure bulk fluid properties such as gas/oil ratio (GOR), light-end compositions (CO2, C1, C2, C3–C5 and C6+), oil-based mud (OBM) filtrate contamination level, color (optical density) that is linearly related to the heavy ends (asphaltenes and/or resins), live fluid density and viscosity, etc. in real time at downhole conditions.

Because of overbalance of drilling and formation pressures, and miscibility of OBM filtrate with formation hydrocarbons, the sampled hydrocarbon fluid is usually contaminated by OBM filtrate. This OBM filtrate contamination affects an accurate characterization of the reservoir fluid. On the other hand, DFA flowline temperature is slightly different than formation temperature. DFA flowline pressure, however, may be significantly different from formation pressure because the flowline pressure can be below the formation pressure when the DFA sensor is beside the probe/packer or above the formation pressure when it is on the output side of the pumpout within the wireline formation tester. Therefore, decontamination of OBM filtrate on fluid properties and conversion of them from flowline to formation conditions are of great importance to interpret DFA measurements.

A new reliable method has been developed in real time for characterizing downhole reservoir fluids, decontaminating OBM filtrate on the DFA-measured fluid properties and converting the DFA data from the flowline to formation conditions. The method has been validated against laboratory measurements of different types of reservoir fluids and OBM filtrates with successful results. This methodology establishes a powerful approach for conducting decontamination of OBM filtrate on DFA measurements in real time at downhole conditions.