{'fraction_non_alphanumeric': 0.018853102906520033, 'fraction_numerical': 0.01335428122545169, 'mean_word_length': 5.5, 'pattern_counts': {'":': 0, '<': 0, '<?xml version=': 0, '>': 0, 'https://': 0, 'lorem ipsum': 0, 'www.': 0, 'xml': 0}, 'pii_count': 0, 'substrings_counts': 0, 'word_list_counts': {'cursed_substrings.json': 0, 'profanity_word_list.json': 0, 'sexual_word_list.json': 0, 'zh_pornsignals.json': 0}}
Experimental Verification of Reservoirs with Different Wettability Using an Oil–Water Relative Permeability Model

Oil–water relative permeability is an important parameter that affects fluid flow in porous media. It is usually obtained in a laboratory. Since rock resistivity and relative permeability are both effects of water saturation, they should theoretically have a relationship. Based on the parallel conduction principle of fluid and skeleton in porous media, the pore structure and fluid distribution can be simplified using the Kozeny–Carman permeability correction equation and the Archie formula, and the relative permeability model of the water phase can be deduced under different wetting conditions. In this study, the resistivity and relative permeability experimental data of 20 rock samples from four inspection wells were compared and verified. The results show that the proposed oil–water relative permeability model agrees well with a reservoir having a porosity range of 17.6–30.7% and an air permeability of 0.16–973 × 10−3 μm, and it may explain why the relative permeability of the water phase decreases as water saturation increases. This model could provide a new technique to construct the relative permeability curves of sandstone reservoirs.