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In recent years, a series of major natural gas exploration discoveries and breakthroughs have been achieved in deep and ultra-deep carbonate gas reservoirs in the Sichuan Basin, and all discovered gas reservoirs are characterized by great burial depth, complex pore structures and high formation temperature and pore pressure. In order to accurately predict the gas flow rate of single well in high temperature and high pressure (HTHP) gas reservoirs and clarify the gas flow characteristics under formation conditions, this paper establishes a productivity simulation experimental device and method based on the formation temperature and pore pressure of carbonate gas reservoirs in the Middle Permian Qixia Formation of northwestern Sichuan Basin and the Upper Sinian Dengying Formation of central Sichuan Basin. Then, the cores of above mentioned gas reservoirs are selected to carry out the productivity simulation experiment under HTHP. Finally, the gas flow characteristics are studied. And the following research results are obtained. First, the newly established productivity simulation experimental device and method suitable for the conditions of 160 °C formation temperature and 100 MPa pore pressure is used to predict the natural gas AOF (absolute open flow) of Well S-1 in the Qixia Formation gas reservoir of northwestern Sichuan Basin. And the prediction result is better accordant with the calculation result of theoretical model, with a relative error of only 2.12%. Second, based on the Klinkenberg permeability under surface conditions, the single-well gas flow rate calculated from the productivity simulation experiment is better accordant with the gas flow rate from field completion testing; while based on the Klinkenberg permeability under formation conditions, the single-well gas flow rate calculated from the productivity simulation experiment is better accordant with the AOF. Third, the change of formation temperature and pore pressure has a significant influence on rock permeability, and the permeability is more sensitive to stress than to temperature. Fourth, to carry out the reservoir stress sensitivity experiment and the productivity simulation experiment, it is required that core samples be recovered to the formation conditions for aging, or the experimental results may have characteristics of strong stress sensitivity and cannot be used for reservoir engineering evaluation directly. In conclusion, the production rate and AOF of HTHP gas wells can be predicted accurately by means of productivity simulation experiment, based on drilling core samples. In addition, the Klinkenberg permeability under formation conditions can be evaluated by using the relational expression between surface or Klinkenberg permeability under formation conditions and single-well gas flow rate, combined with gas well testing data.

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