In this paper, the experiments of enhanced shale gas recovery by the injections of CO2, N-2, and CO2/N-2 mixture gases were carried out in a fixed bed setup to investigate the influence of the types of displacing fluid on CH4 recovery and gas flow dynamics. Investigation results show that when taking CO2 or N-2 as displacement agent, the Coats-Smith dispersion-capacitance model can give an excellent simulated result to the breakthrough curves of CO2 and N-2. The injection of N-2 leads to the shortest breakthrough time (t(b)) of injected gas and the lowest recovery of CH4 product (RCH4-product), while injecting CO2 into shale formations results in the longest t(b) of injected gas and the highest RCH4-product with a relatively sharp displacement front. The differences of dispersion coefficient (K-D) and the flowing fraction of pore space (F-v) in the Coats-Smith dispersion-capacitance model are the underlying reasons for the distinct behaviors of CO2 injection and N-2 injection. With increasing CO2 mole fraction in CO2/N-2 mixture gases, RCH4-product rises. The injection of 50:50/N-2:CO2 mixture gases exhibits the biggest enhancement degree of N-2 concentration during the displacement process. The injection of a N-2-rich mixture can significantly prolong t(b) of CO2 and help to sequestrate injected CO2 over a long-term. For the transport of CO2 in reservoir, Fv increases and K-D and the mass transfer coefficient between mobile and immobile regions (K-m) decreases with increasing N-2 concentration in binary gas mixture, revealing that N-2 can hinder the diffusion of CO2 into the micropore system to displace CH4. The fluctuation range of flow rate of injected gas (Finjected-gas) and the CO2 storage amount (Vstorage-CO2) enhance as CO2 mole fraction in mixture raises. In order to optimize RCH4-product, Vstorage-CO2, and CO2 sequestration time, the selection of displacing fluid and the ratio of CO2/N-2 mixture gases should be taken into consideration.