Pore–throat size is a key parameter for the assessment of reservoirs. Tight sandstone has the strong heterogeneity in the distribution of pores and throats; consequently, it is very difficult to characterize their distributions. In this study, the existing pore–throat characterization techniques were used jointly with scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), high-pressure mercury intrusion (HPMI), and rate-controlled mercury intrusion (RCMI) technologies to highlight features of throat sizes and distribution of pores in tight sandstone reservoirs of the Y Basin in China. In addition, full-scale maps (FSMs) were generated. The study results show that key pore types in reservoirs of the Y Basin include residual intergranular pores, dissolved pores, clay mineral pores, and microfractures. LTNA can effectively characterize the distribution of pore–throats with a radius of 2–25 nm. HPMI test results show that tight sandstones contain throats with a radius less than 1000 nm, which are mainly distributed in 25–400 nm and have a unimodal distribution. RCMI tests show that there is no significant difference in pore radius distribution of the tight sandstones, peaking at approximately 100,000–200,000 nm; the throat radius of tight sandstones varies greatly and is less than 1000 nm, in agreement with that of HPMI. Generally, the pore–throat radius distribution of tight sandstones is relatively concentrated. By using the aforementioned techniques, FSM distribution features of pore–throat radius in tight sandstone can be characterized effectively. G6 tight sandstone samples develop pores and throats with a radius of 2–350,000 nm, and the pore–throat types of tight sandstone reservoirs in Y basin are mainly mesopores and macropores.

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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.

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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.

Rocks contain multi-scale pore structures, with dimensions ranging from nano- to sample-scale, the inherent tradeoff between imaging resolution and sample size limits the simultaneous characterization of macro-pores and micro-pores using single-resolution imaging. Here, we developed a new hybrid digital rock modeling approach to cope with this open challenge. We first used micron-CT to construct the 3D macro-pore digital rock of tight sandstone, then performed high-resolution SEM on the three orthogonal surfaces of sandstone sample, thus reconstructed the 3D micro-pore digital rock by Markov chain Monte Carlo (MCMC) method; finally, we superimposed the macro-pore and micro-pore digital rocks to achieve the integrated digital rock. Maximal ball algorithm was used to extract pore-network parameters of digital rocks, and numerical simulations were completed with Lattice-Boltzmann method (LBM). The results indicate that the integrated digital rock has anisotropy and good connectivity comparable with the real rock, and porosity, pore-throat parameters and intrinsic permeability from simulations agree well with the values acquired from experiments. In addition, the proposed approach improves the accuracy and scale of digital rock modeling and can deal with heterogeneous porous media with multi-scale pore-throat system.