In wireline formation testing and sampling, a difficult and long standing challenge is the differentiation between mud filtrate and formation fluids, especially in oil-based mud (OBM) (diesel/water mixture) and multiphase formation fluids (oil/formation water) environments. This challenge can cause ambiguities during the interpretation of downhole fluid properties and determination of the contamination levels before sampling. Often, during the sampling process, fluid mixing increases fluid property sensor noise and causes difficulties with accurate fluid identification and contamination levels. Consequently, noisy sensor readings are attributed to the transitional phase of sampling and pertinent information is ignored. This paper presents several examples where fluid mixing has occurred. A high-resolution volumetric densitometer is used to accurately identify fluid properties. It monitors the change of frequency of a vibrating tube immersed in the fluid sample. Because of the high accuracy of this technique, it is also possible to determine additional fluid properties, such as density, water salinity, and fluid compressibility. Furthermore, new processing methods are illustrated, which provide a clearer understanding of flow behavior and allow more accurate estimates of fluid contamination. The examples are verified using fluid volumetrically maintained at the reservoir pressure and temperature (PVT) lab results comparing the downhole real-time fluid property measurements and interpretation with the actual fluid samples recovered.


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