Scaling capillary imbibition during static thermal and dynamic fracture flow conditions

To incorporate the effect of temperature, previously reported scaling formulations were modified considering the wettability, change in oil properties, and thermal expansion. The results of static imbibition experiments conducted using different types of heavy-oil samples at different temperatures up to 90 °C were used to verify the formulation. The modified scaling formulations responded well if the thermal expansion effect is included, except in high-temperature crude oil imbibition cases. sults obtained through water injection experiments in artificially fractured core samples with matrix permeabilities ranging from 300 to 0.075 mD were used to verify the numerical model of core scale displacements. Then the convergence constant in Aranofskyʹs abstract recovery–time relationship was correlated to an imbibition group consisting of the injection rate and matrix properties. Three different formulations were presented and tested. Good agreement with the experimental observations could be achieved when the wettability and permeability of the matrix and the flow rate in fracture is included in the formulations. When the matrix size is included in the regression analysis, not all correlation types yielded a good agreement with the experimental data. tudy will provide an insight into the scaling of the laboratory scale experiments to the reservoir conditions and constitute a base to define matrix fracture interaction in numerical models dealing with fractured reservoir modeling.