Relative permeability has a significant impact on the understanding of migration and accumulation of hydrocarbons in tight formations as well as on their development. However, estimation of oil-water relative permeability curves through conventional coreflooding methods is difficult due to the low-permeability and high capillary pressure in tight rock. This study aims at providing important theory basis for researching on the development of tight oil and gas reservoir. In this work, relative permeability curves in tight core were derived from capillary pressure curves using normalization and non-standardized computational methods. The relationship in tight rock yields high-quality correlation coefficients, typically of the order of 0.95. This is interpreted here to indicate good fractal behavior, particularly for nanopores. Fractal dimension D ranges from 2.5362 to 2.7399 in this study. The larger value of D represents smaller pore size and more complicated pore structures. The connate water saturation from theoretically derived relative permeability curves for tight cores can reach a value as high as 60-80% and the two-phase flow area is narrow. The total effective permeability is low and the two-phase flow process is complex. The drainage capillary pressure curve actually reflects the process during which the non-wetting phase displaces the wetting phase, thus the derived relative permeability curve for oil-water system should be comparable to the results from coreflooding experiments of oil displacing water. The calculated permeability curves are in good agreement with data obtained from the laboratory experiments, and can be especially applied to reservoir simulation work of the migration and accumulation of hydrocarbon in tight rock.
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