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It is common practice to complete wells with Down Hole Gauge equipments (DHG) in order to measure pressure and temperature.Predicting well behavior requires good quality well test data. Despite having quality (measured) well test data, the engineer can still arrive at an incorrect conclusion if liquid accumulation in the wellbore due to lower than minimum flow rate (Turner rate) occurs. This is especially true for wells where the DHG is installed at a considerable distance from the productive zone.Normally, it is expected that DHG pressure increases while WHP decreases as liquid accumulates in the wellbore. However, liquid accumulation may be difficult to identify if the liquid level is lower than the DHG. Liquid accumulation in the wellbore will give an additional back pressure to the reservoir which reduces the well production rate.In simulating well behavior, the engineer needs to have flow rate and pressure data at the reservoir datum. Since the DHG location is higher than the reservoir depth, the Flowing Bottom Hole Pressure (FBHP) is estimated by extrapolating the test data to the desired reservoir datum. Software packages perform this calculation with the following data inputs: Gas and Liquid rate Wellhead pressure and Temperature, Downhole pressure and DepthMatching the well test data with the available tubing correlations in the simulation package will guide the engineer to choose the appropriate correlation that best matches the test data and enable calculation of the FBHP at reservoir depth.Correlations available in software package always assume that the fluid ratio (gas, oil and water) in each segment of the tubing is similar from the end of tubing up to the wellhead. If liquid accumulation occurs below the DHG depth, the estimation of the FBHP at reservoir depth will be incorrect.