The Impact of Microscopic Pore Network Characteristics on Movable Fluid Properties in Tight Oil Reservoir

The fluid flow behavior, generally referred to as seepage, could determine the hydrocarbon and brine movement behavior. Movable fluid property, as one of the vital parameters for seepage characteristic evaluation, was generally used for tight oil reservoirs’ fluid flow ability assessment. The nuclear magnetic resonance technique was used to experiment with movable fluid percentage and movable fluid porosity, which can provide a realistic assessment of the amount of fluid that can flow in the porous media. Other techniques were also used to analyze the main factors in regulating the differences in movable fluid parameters. However, the research about fluid flow behavior was generally based on traditional methods, while the seepage characteristics from the pore-scale view are still a myth. To promote this process, in this study, core samples obtained from the Chang 7 reservoir of the Triassic Yanchang Formation in the Longdong region of Ordos Basin, China, were tested. The results show that the average movable fluid percentage and average movable fluid porosity of the total 16 core samples are 36.01% and 2.77%, respectively. The movable fluid exists mainly in the midlarge pores with the corresponding $T_2$ relaxation time over 10 ms. $T_2$ distributions mainly present four typical patterns: (1) bimodal distribution with similar amplitudes of the two peaks (occupying 6.25%), (2) bimodal distribution with higher right peak and lower left peak (occupying 18.75%), (3) bimodal distribution with higher left peak and lower right peak (occupying 56.25%), and (4) unimodal distribution (occupying 18.75%). Pore structure heterogeneity is closely related to the movable fluid parameters; the movable fluid parameters exhibit a relatively good correlation with core throat radius as well as permeability. There is an obvious difference between the movable fluid parameters and the microscopic characteristic factors in tight oil reservoirs due to the difference in physical properties, clay mineral content, microcracks, and pore structure characteristics. This research has provided a new perspective for the movable fluid property evaluation, and the relevant results can give some advice for the oil field development.