Reservoirs can sometimes be very sensitive to drilling fluids. Typically, the lower the permeability of the rock, the greater the likelihood of experiencing phase interference effects, and as the average diameter of the porous features decreases, the greater the capillary pressure. Often this phase interference effect significantly reduces well productivity and, hence, alternative drilling fluids are used. Moreover, aqueous phase fluids can react with the reservoir rock causing clay swelling, clay flocculation, and fines migration. In an attempt to mitigate the above mentioned deleterious phenomena, alternative, non-aqueous drilling muds are sometimes used. These are designed to be compatible with the reservoir fluids in situ and, because they are hydrocarbon-based, they do not interact with the rock matrix. One of the drawbacks, however, is the mixing that occurs with the oil in situ. When early-time samples are taken, the oil is contaminated with the drilling fluid. This is a near-wellbore and early-time problem that is self-correcting as more fluids are produced from the well. However, for small volume samples (typically bottom hole samples), contamination can seriously distort the properties measured for the sample. The small-volume samples are often very expensive to procure and many of the reservoir development decisions are based on the properties of these small samples. Therefore, these properties need to be accurately measured. How can the contamination be quantified both in terms of mass or mole per cent in the fluid and its impact on the sample properties? This paper describes two technologies developed to achieve this. The first is applicable to synthetic hydrocarbon drilling fluids where the concentration of components is restricted to very few components. The second technique applies to those fluids that contain a more broad distribution of hydrocarbon components. The results indicate that the resolution of contamination can be achieved to within 1 mass% accuracy. Using the degree of contamination with Equation of State methods, the properties of the actual uncontaminated reservoir fluid can be predicted.