Forced oilââ?¬â??water displacement is the crucial\nmechanisms of secondary oil recovery. The knowledge of\nrelative permeability is required in the simulation of multiphase\nflow in porous media. Obvious dynamic effect of\ncapillary pressure occurs in that the formation of ultra-low\npermeability reservoir (the permeability is <1 X\n10-3 lm2) is tight and the pores and throats are very small.\nIn addition, the significant capillary end effect causes\nserious errors when calculating relative permeabilities. For\nthese reasons, the JBN method (neglecting capillary pressure)\ndoes not apply. Therefore, the dynamic capillary\npressure and capillary end effects should be taken into\naccount. This work focuses on calculating two-phase relative\npermeability of ultra-low permeability reservoir\nthrough considering the dynamic capillary pressure and\neliminating the influence of capillary end effects. Firstly,\nlaboratory core scale measurements of in situ water phase\nsaturation history based on X-ray CT scanning technique\nwere used to estimate relative permeability. Secondly, a\nmathematical model of two-phase relative permeability\nconsidering the dynamic capillary pressure was established.\nThe basic problem formulations, as well as the more\nspecific equations, were given, and the results of\ncomparison using experimental data are presented and\ndiscussed. Results indicate that the dynamic capillary\npressure measured at laboratory core scale in ultra-low\npermeability rocks has a significant influence on the estimation\nof unsteady-state relative permeability. The mathematical\ncalculating method was compared with the history\nmatching method and the results were close, suggesting\nreliability for ultra-low permeability reservoirs. Importantly,\nthe proposed methods allow measurement of relative\npermeability from a single experiment. Potentially this\nrepresents a great time savings.
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