This paper investigates the characteristics of oil–water two-phase flow after volumetric fracturing of horizontal wells in tight reservoirs. Based on a large-scale high-pressure, high-temperature experimental system for modeling horizontal well injection and production, the characteristics of the pressure distribution, cumulative liquid production, recovery factor, and liquid production rate of a matrix model and fractured model during the waterflooding process are compared and analyzed. The results show that, for both types of reservoirs, the fluid forms a high-pressure zone and a low-pressure zone during water injection. As the development progresses, the high-pressure zone continuously moves forward. There is a pressure step between the high-pressure zone and the low-pressure zone, which gradually decreases in magnitude as the pressure wave reaches the well. By this time, the main resistance before water breakthrough is the pressure step at the waterflooding front. The ultimate recovery is found to be 26.71% for the matrix model and 28.48% for the fractured model. Without an effective displacement system, the resistance of the horizontal well during waterflooding mainly acts on the oil–water interface. After the establishment of an effective displacement scheme, the resistance gradually expands to both sides of the water-swept zone. At this point, the formation of a dominant channel greatly weakens the displacement performance. Thus, it is necessary to rely on imbibition or surfactants in the later stages to improve the recovery factor.

At present, the existing measuring methods for viscosity of fluid can only obtain the viscosity of bulk fluid, while the in situ viscosity of fluid in porous media cannot be acquired. In this paper, with the combination of nuclear magnetic resonance (NMR) and physical simulation experiment, a testing method for in situ viscosity of fluid in porous media is established, and the in situ viscosity spectra of water in tight cores under different displacement conditions is obtained. The experimental results show that the in situ viscosity distribution of water in porous media is inhomogeneous, and it is not a constant but is related to the distance between water and rock walls. When the distance between fluid and rock walls is close enough (e.g., 2 relaxation time is less than 1 ms), the viscosity of fluid increases rapidly, and the in situ viscosity is greater than the bulk viscosity. Moreover, after the rock samples are saturated with water, the in situ viscosity of water is distributed as a double-peak structure. The left peak is characterized mainly by the in situ viscosity distribution of movable fluid, whose in situ viscosity is smaller, and the right peak mainly represents the in situ viscosity distribution characteristics of immovable fluid, whose in situ viscosity is larger and increases gradually. Under a relatively large driving force, the in situ viscosity amplitude of movable fluid decreases greatly, and the average in situ viscosity of residual water in the core is much higher than that of saturated water in initial state.