Given the difficulty in developing waterflooding in tight oil reservoirs, using waterflooding huff-n-puff is an effective method to improve oil recovery. Online nuclear magnetic resonance (NMR) can detect the change in internal oil and water during the core displacement process, and magnetic resonance imaging (MRI) in real time. To improve the tight oil reservoir development effectiveness, cores with different permeability were selected for a waterflooding huff-n-puff experiment. Combined with online NMR equipment, the fluid saturation, recovery rate, and residual oil distribution were studied. The experiments showed that, for tight oil cores, more than 80% of the pores were sub-micro- and micro-nanopores. More than 77.8% of crude oil existed in the sub-micro- and micropores, and movable fluids mainly existed in the micropores with a radius larger than 1 μm. The NMR data and the MRI images both demonstrated that the recovery ratio of waterflooding after waterflooding huff-n-puff was higher than that of conventional waterflooding, and, therefore, residual oil was lower. Choosing two cycles’ of waterflooding, huff-n-puff was more suitable for tight oil reservoir development. The production of crude oil increased by 22.2% in the field pilot test, which preliminarily proved that waterflooding huff-n-puff was suitable for tight oil reservoirs.

In order to evaluate the displacement effect of four kinds of injection media in tight oil sandstone, water, active water, CO₂, N₂ flooding experiments were carried out in laboratory. Online Nuclear Magnetic Resonance (NMR) spectrometers combine the advantages of NMR technology and core displacement experiments. In the displacement experiment, NMR data of different injection volumes were obtained and magnetic resonance imaging (MRI) was carried out. The results showed that micro and sub-micropores provided 62–97% of the produced crude oil. The enhanced oil recovery ratio of active water flooding was higher than that of conventional water flooding up to 10%. The recovery ratio of gas flooding in micro and sub-micropores was 60–70% higher than that of water flooding. The recovery ratio of CO₂ flooding was 10% higher than that of N₂ flooding. The remaining oil was mainly distributed in pores larger than 0.1 μm. Under the same permeability level, the remaining oil saturation of cores after gas flooding was 10–25% lower than water flooding. From MRI images, the displacement effects from good to bad were as follows: CO₂ flooding, N₂ flooding, active water flooding, and conventional water flooding.

The key to the efficient development of a tight reservoir is its accurate evaluation. In this study, the pore throat structure characteristics of sandstone samples in the study block were analyzed by high-pressure mercury injection technology. According to the characteristics of the capillary pressure curve, the sandstone samples in the study block were divided into three types: the first type has a reservoir permeability greater than 0.7 mD and a core mercury injection saturation of 96% with a good reservoir quality; the second type has a reservoir permeability ranging from 0.4 to 0.7 mD and a core mercury injection saturation of 80% with a moderate reservoir quality; and the third type has a reservoir permeability between 0.1 and 0.4 mD and a core mercury injection saturation of 50% with a poor reservoir quality. Also, high-resolution synchrotron radiation imaging and scanning electron microscopy were used to observe the pore throat structure, connectivity, and microscopic heterogeneity of sandstone samples, showing an increasing level of pore disconnection, serious microscopic heterogeneity, and poor reservoir performance as reservoir permeability declines. As mineral composition tests show, the lithology of the tight sandstone in the target block is mainly medium-grained and fine-grained feldspar lithic sandstone and the longitudinal heterogeneity of lithology and mineral components of tight sandstone is relatively weak at above the centimeter level. Besides, based on the high-pressure mercury injection test data, fractal theory is applied to calculate the fractal dimensions of the three types of reservoirs. The result shows a gradual increase in fractal dimensions with the decrease of reservoir quality, in which the closer the fractal dimension is to 3, the more serious the microscopic heterogeneity is, and the stronger the roughness of the pore surface is. As a result, the more heterogeneous the tight reservoir gets, the more likely the injected fluid is to flow along the developed and connected pore regions.

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., T2 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.