Hydraulic fracturing is an important means of developing unconventional oil and gas layers. The fracture conductivity of tight sandstone reservoirs after fracture is affected by many factors, such as the interaction between the fracturing fluid, water, and rocks; the fracturing materials; and the construction parameters. This paper improves the experimental process of the long-term conductivity test and provides insight into conductivity prediction and optimization based on the response surface test method. The test process is conducted in the following manner: (1) inject nitrogen to evaluate the fracture conductivity before fracturing fluid damage; (2) inject fracturing fluid to simulate shut-in; and (3) inject nitrogen again to evaluate fracture conductivity after the damage ability of the fracturing fluid. The single factor test results show that the lower the sand concentration is, the higher the fracturing fluid viscosity will be, and the longer the fracturing fluid retention time is, the greater the damage to the conductivity of the fracturing fluid will be. The response surface test results show that the order of factors affecting the retention of conductivity is fracturing fluid viscosity > sand concentration > fracturing fluid retention time. There is a certain interaction between sand concentration and fluid viscosity, and there is also a certain interaction between fluid viscosity and fluid retention time, but these interactions are not significant; when the fracturing fluid retention time is longer, there will be an interaction between the sand concentration and the fracturing fluid retention time. In addition, based on the model used to optimize the fracturing construction parameters from the perspective of proppant conductivity damage, the optimal solution is when the viscosity of the fracturing fluid is 1 mPa.s, the paved-sand content is 8.49 kg/m2, and the retention time of the fracturing fluid is 10 h. The maximum retention rate of the flow conductivity is 63.19%.

Seepage is important to improve the postpressure production enhancement effect of tight oil and gas reservoirs. To study the microscopic percolation law of different pores, this paper first characterizes the pore structure of tight cores. High-pressure spontaneous percolation experiments and nuclear magnetic resonance (NMR) tests were combined. The T 2 spectra at different times of percolation were used. The percolation law of different pore types was quantitatively characterized from a microscopic perspective. The effect of different interfacial tensions on the percolation was clarified. Results show that the pore size has a good match with the NMR T 2 relaxation time. The core pore development is dominated by submicrometer pores, which account for more than 70%. The percolation rate is fast at the beginning and then decreases and stabilizes at 48 h. The pore size of the submicropore is small, the capillary force is large, and the recovery rate of percolation is high, followed by those of the micropore and the medium-pore. The higher the porosity and permeability of the core, the greater the overall seepage recovery rate. The sensitivity of submicrometer pores to interfacial tension is great, and the recovery rate increases by 40.9% when the interfacial tension decreases from 17.1 to 1.46 mN/m. Furthermore, as the interfacial tension decreases, the recovery rate of different pores appears to increase first and then decrease. The surfactant formulation must be selected reasonably in practical production.

Conventional shale gas productivity prediction techniques consider fracture conductivity to be a fixed value, but in actual production processes, conductivity changes with time. Therefore, this paper proposed a capacity prediction method that considers time-dependent conductivity and validates its accuracy using commercial simulators. First, relevant parameters were obtained by fitting the improved long-term conductivity test, and then the shale gas seepage model was established using the EDFM method. The laboratory test results showed that the order of significance affecting the conductivity retention rate was fracturing fluid viscosity > sand concentration > fracturing fluid retention time; the calculation results of the production prediction model show that the flow and the pressure curves that corresponded to constant conductivity and variable conductivity were to some extent different. In the presence of complex fractures and natural fractures, the increase in the variable conductivity production curve was smaller than that of the constant conductivity production curve. This study provides some guidance for field production.