During the injection process, micro?nano bubbles are generated in the oil?displacing agent polyacrylamide (HPAM) system. This will lead to the oxidative degradation of HPAM and the loss of viscosity. In order to determine the effect of micro?nano bubbles on the change rule of the viscosity retention rate and structure of HPAM solution, the viscosity retention rate at different aeration conditions was studied, and technologies such as dynamic laser scattering, biological microscopy, and infrared spectroscopy were carried out. Results showed that the viscosity retention rate of HPAM sample, which was prepared with simulated mineralized water after 20 mins circulation of the micro?nano bubbles generator with air as the gas source, decreases the most, and its viscosity average molecular weight is also the lowest. This is attributed to the chemical reaction between oxygen and HPAM molecules in the solution, leading to oxidative degradation. The micro?nano bubbles containing air increase the solubility of oxygen in the solution and generate hydroxyl radicals (·OH), thereby reducing the viscosity retention. In the absence of inflation, micro?nano bubbles are formed in the HPAM solution during the preparation process due to mechanical shear, but the high concentration of the solution hinders the dispersion of micro?nano bubbles, thereby slowing down the decrease in viscosity retention. In addition, micro?nano bubbles have a longer stabilization time in solution than large bubbles, and will affect the particle size distribution of the polymer, resulting in uneven particle size distribution and larger average particle size.

Formation damage control of Hutubi underground gas storage (UGS) presents a serious challenge due to low formation pressure coefficient and reservoir deep invasion of wellbore working fluid under large pressure difference during drilling and completion. Mineral composition analysis, expansion capacity, wettability and permeability reduction after spontaneous imbibition measurement of reservoir rocks were conducted to reveal formation damage mechanism of Hutubi UGS. That is the clay minerals hydrated swell and dispersion of water?sensitive formation and water?blocking effect of tight sand reservoir. Drilling fluid technical countermeasure of improving inhibition, weakening liquid wettability and enhancing temporary plugging was put forward. Amine inhibitor and surfactant ABSN were selected to optimize the current used drilling fluid. Temporary plugging particle size fraction distribution was determined based on the “optimal filling” bridging plugging theory. Laboratory and field evaluation show that the optimized drilling fluid is suitable for perforation and screen pipe completion with a permeability recovery more than 90% and effective inhibition of clay swell. The results provide reference for improving formation damage control effect of depleted gas reservoir drilling and completion.