This work considers the influence of multiphase flow (oil and gas) in well testing analysis of non-flowing wells: For example, Drill Stem Test (DST) and Slug Test. The problem is solved by a two-dimensional (r-z), variable bubble-point, black oil simulator that incorporates the typical DST inner boundary condition. Initially, the oil in the reservoir is in equilibrium condition at the initial reservoir pressure which is considered greater or equal to the initial oil bubble-point pressure. A sequence of flow and/or buildup periods can be imposed at the reservoir sandface to simulate a non-flowing well test condition. Inertial, friction, and multiphase flow effects in the wellbore are neglected. Comparisons with analytical methods (developed for single phase flow of a fluid of small and constant compressibility) traditionally used to obtaining reservoir parameters (eg., transmissibility) are made to determine how good or bad these methods are in the presence of more than one phase flowing in the porous medium. During flow periods significant discrepancies are obtained, whereas in buildup flow periods these discrepancies are less significative. Explanation to these multiphase flow effects on the determination of reservoir parameters are given in detail, and justify why, usually, reservoir parameters obtained from flow tests do not match results obtained from build up periods in well test analysis.