This study simulated seabed high pressure and low temperature conditions to synthesize natural gas hydrates, multi-stage depressurization mode mining hydrates as the blank group, and then carried out experimental research on the decomposition and mining efficiency of hydrates by depressurization and injection of different alcohols, inorganic salts, and different chemical agent concentrations. According to the experimental results, the chemical agent with the best decomposition efficiency is preferred; the results show that: the depressurization and injection of a certain mass concentration of chemical agents to exploit natural gas hydrate is more effective than pure depressurization to increase the instantaneous gas production rate. This is because depressurization combined with chemical injection can destroy the hydrate phase balance while effectively reducing the energy required for hydrate decomposition, thereby greatly improving the hydrate decomposition efficiency. Among them, depressurization and injection of 30% ethylene glycol has the best performance in alcohols; the decomposition efficiency is increased by 52.0%, and the mining efficiency is increased by 68.2% within 2 h. Depressurization and injection of 15% calcium chloride has the best performance in inorganic salts; the decomposition efficiency is increased by 46.3%, and the mining efficiency is increased by 61.1% within 2 h. In the actual mining process, the appropriate concentration of chemical agents should be used to avoid polluting the environment.

To address the issue of ineffective injection resulting from the consistent channeling of injected water through highly permeable channels in ultra-deep, high-temperature, high-salinity, and strongly heterogeneous reservoirs during the production process, a gel particle profile control agent suitable for high-temperature and high-salinity conditions was chosen. With the help of the glass etching visual microscopic model and the heterogeneous long core model, the formation mechanism of a water flooding channeling path and the distribution law of the remaining oil were explored, the microscopic profile control mechanism of the different parameters was clarified, and the profile control effect of macroscopic core displacement was analyzed. The research shows that the formation mechanism of a water flooding channeling path is dominated by the distribution law of the permeability section and the connection mode between different penetration zones. The remaining oil types after water flooding are mainly contiguous block, parallel throats, and multi-branch clusters. The profile control effect of gel particles on reservoir vertical heterogeneity is better than that of reservoir lateral heterogeneity. It was found that 10 wt% submicron particles with a median diameter of 600 nm play a good role in profiling and plugging pores of 5–20 μm. In addition, 10 wt% micron-sized particles with a median diameter of 2.63 μm mainly play a strong plugging role in the pores of 20–30 μm, and 5 wt% micron-sized particles with a median diameter of 2.63 μm mainly form a weak plugging effect on the pores of 10–20 μm. The overall profile control effect of 10 wt% submicro particles is the best, and changes in concentration parameters have a more significant effect on the profile control effect. In the macroscopic core profile control, enhanced oil recovery (EOR) can reach 16%, and the gel particles show plugging, deformation migration, and re-plugging. The research results provide theoretical guidance for tapping the potential of the remaining oil in strong heterogeneous reservoirs. To date, the gel particles have been applied in the Tahe oilfield and have produced an obvious profile control effect; the oil production has risen to the highest value of 26.4 t/d, and the comprehensive water content has fallen to the lowest percentage of 32.1%.

Acid fracturing as an important stimulation technique, provides strong technical support for the exploration breakthrough and efficient development of carbonate oil and gas reservoirs. Accurately predicting the effective length of acid-fracturing fractures is of great significance for guiding the acid-fracturing design and improving the stimulation effect of acid fracturing. This article fully considers the essential requirement that the long-term conductivity of acid-fracturing fractures is not zero within the effective length segment. Based on the principle of the same acid concentration and acid dissolution amount, the long-term conductivity testing experiment of acid-fracturing fractures under different residual acid concentrations was designed and carried out with the consideration of the common ion effect. The critical acid concentration with long-term conductivity of 0 was obtained. This method overcomes the shortcomings of the existing methods that result in the overestimation of the effective length of acid-fracturing fractures due to inaccurate values of residual acid concentration or short-term conductivity as the determining criterion. The experimental results show that the higher the acid concentration, the deeper the acid etching groove, and the higher the initial conductivity of acid-fracturing fractures. The long-term conductivity decline rate of different acid concentrations is above 80%, which means that using short-term conductivity as an evaluation indicator alone will overestimate the effective length of acid-fracturing fracture and the yield-increasing effect of acid-fracturing treatment. In the case presented in this paper, the critical acid concentration for acid-fracturing fracture with long-term conductivity of 0 is 4%, and the effective length of acid-fracturing fractures is 120 m.

The conventional liquid acid has several shortcomings in the acidizing process of fractured-vuggy carbonate reservoirs, including high filtration loss, fast reaction rate, high friction resistance, and difficult flowback. To address these issues, a new atomizing acid acidizing technology is proposed, combining the gas injection development practice from the fractured-vuggy carbonate reservoir in the Tahe oilfield. The laboratory experiments were conducted to optimize the type and concentration of atomized acid, iron ion stabilizer, corrosion inhibitor, and atomization stabilizer. The acid atomization rate was evaluated under different combinations of gas and liquid injection flows using a self-made atomized acid well migration simulator, and the best atomization scheme was selected. Furthermore, a kinetic experiment for the acid–rock reaction was carried out to evaluate the retarding performance of the atomized acid. The optimized formula for the atomizing acid system consists of 15~25% hydrochloric acid, 0.005% atomizing stabilizer (AEO-7), 1% iron ion stabilizer (EET), 1.5% corrosion inhibitor (EEH-160), and water. The optimal gas and acid injection scheme is gas injection at 2m3/min and acid injection at 10 mL/min, which maintains an atomization rate of over 80% after the acid mist migrates through the wellbore. Compared with gelling acid, the acid–rock reaction rate of atomized acid is 8.5, 9.1, and 10.6 times slower under acid concentrations of 15%, 20%, and 25% respectively. The retarding effect of atomized acid is superior, facilitating etching and initiating underdeveloped gas drive channels and thereby increasing the probability of gas communication with new reservoirs. The research findings presented in this paper establish a theoretical foundation for the practical implementation of the atomized acid acidizing process in the field.