Extended wellbore storage can be mistakenly interpreted as a reservoir response in gas well testing with surface shut-in. This interpretation usually results in false values for permeability, skin and reservoir size and shape. This paper investigates gas cooling effects on pressure transient testing with surface shut-in in gas wells. This study was prompted by the observation, that in gas wells, many of the buildup tests obtained with surface shut-in exhibited complex reservoir model behavior with relatively low skin. These models, such as narrow channels or multiple nearby boundaries, often did not agree with the actual reservoir system thus resulting in incorrect estimations of well and reservoir parameters. This in turn may result in missed opportunities to enhance well productivity and to develop the field further. The results presented in this paper are based on well test simulation and field data from five wells in three different fields offshore Louisiana. This work demonstrates the effect of gas cooling. in combination with gas compression. on the pressure derivative curve. Knowledge of the expected pressure derivative shape. and duration, will improve the design of buildup tests that will allow enough time for the actual reservoir response to be observed. This will result in a reliable reservoir model and correct estimation of permeability and skin factor. Introduction To minimize cost and operational risk, many well tests are performed with a surface shut-in with a bottom-hole pressure measurement, rather than bottom-hole shut-in and pressure measurement. However, a surface shut-in includes many factors that can effect the bottom-hole pressure value. The combined effect of these factors is usually referred to as the wellbore storage effect and period. A surface shut-in allows fluid flow from the tested formation into the wellbore for a long period of time, depending on the permeability and thickness of the formation, and the wellbore volume. Moreover, the multiphase composition of wellbore fluids results in an upward movement of the gas phase relative to the liquid phase. These changes in fluid pressure and temperature, may also result in liquid drop out or evaporation (phase changes). These factors will result in significant changes in the wellbore fluids' compressibility, density, and composition. Lee presented procedures to design well tests including after-flow conditions. He used Agarwal, Al-Hussainy, Ramey type curve empirical fit which predict the end of wellbore storage duration. In terms of equivalent shut-in times, Ate, the duration of after-flow is given by the following equation: Hegeman, Hallford, and Joseph presented a model for analyzing increasing or decreasing wellbore storage. Their model is based on modification and extension of Fair's approach. Fair modified Van Everdingen and Hurst equation by adding a term to account for the pressure change caused by phase redistribution: The changing storage pressure function has the following properties: (2a) (2b) (2c) P. 77^

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