Study on the fluidity of the pore-fracture binary system in a tight sandstone reservoir-NMR

Fluid movability in tight sands may not be accurately characterized by pore size-based classification methods solely because of the complex pore structure and heterogeneity in pore size. In this study, on the basis of casting thin slices and scanning electron microscope observation, pore structure was analyzed using mercury injection, NMR, and micron CT to classify and evaluate the tight oil reservoir. The experiment suggest that the quality of tight reservoir is determined by its pore structure, particularly the throat radius, with the microthroat being an essential factor in permeability. Uniquely, we divide the reservoir by Q-cluster with throat radius, displacement pressure, permeability and other parameters. Based on reservoir classification, this study proposed a method for studying the pore size classification of samples on the T₂ spectrum by combining CT scanning with mercury intrusion and a NMR experiment. Pore fluids are generally classified into movable fluid and irreducible fluid by one or two NMR T₂ cut-offs. The pore size distributions and capillarity boundaries are converted from T₂ and mercury injection capillary pressure (MICP). We categorized pores into micropores (T₂ < 1), macropores (T₂ > 10, with T₂ > 300 as fractures), and medium pores (the rest). The saturation of movable fluid and the percentage of micro-fractures can characterize the seepage characteristics of tight reservoirs, which is of great significance for the later periods of oilfield development.