Evaluation of flow rate profile along the wellbore is very important for reservoir characterization, because it indicates the contribution of each inflow point at different depth to the overall production rate. The temperature and pressure sensors in the wellbore are small and cheap, whereas flow meters are cumbersome and expensive, and affect the flow in the well. The method presented in the current paper shows its significance in predicting the gas rate from temperature and pressure data. A mathematical model for pressure and temperature distributions along gas well has been developed. Temperature and pressure profiles from nine well intervals in field C (Australia) have been matched with the mathematical model to determine the flow rates from different layers in the well. The present model considers the variables as functions of thermal properties at each depth, which is more accurate if compared to previous models. Results of tuning the mathematical model to field data show good agreement with the model prediction. Simple and explicit formulae are derived for effective evaluation of flow rate and thermal conductivity in gas wells. The proposed approach has been applied to the estimation of gas rates and formation thermal conductivities from the measured well pressure and temperature data in field C. It provides useful information for identifying the source and magnitude of formation damage and recommending well stimulation of the layers with low rates.

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