The permeability and porosity vary significantly with different formation pressure in the gas injection process of the underground gas storage reconstructed from low-permeability gas reservoirs. It is necessary to understand the variation of permeability and porosity with formation pressure so as to simulate the injection and production process of underground gas storage. Firstly, the variogram theory in geostatistics was introduced, and the initial distribution of the reservoir physical parameters was determined based on the known information of the well points. Next, on the basis of the inverse problem theory, the differences between the measured values and calculated values of formation pressure were used to construct objective function, thereby transforming the inversion identification problem of reservoir physical parameters into the optimization problem. Then, the change rate of formation pressure to porosity and permeability was solved, and the physical parameters of reservoir were inversed by using conjugate gradient method. The correctness of the model was proved by a case study. A certain area of gas storage was taken as the research object for inversion analysis. Results show that although the distribution of permeability and porosity in the reservoir was basically the same at the beginning, the change rate of permeability and porosity was different at the end of gas injection, and the correlation between them was not consistent. The biggest change in permeability occurred near the 5# injection production well, and the value increased from 1.66×10^-3 μm² to 2.81×10^-3 μm², with an increase of nearly 70%. The function relationship between permeability, porosity, and formation pressure was built with the least square method. The research results can provide a theoretical basis for the injection and production simulation of low-permeability gas reservoirs converted to underground gas storage.