A New Insight into the Determination of True Residual Oil Saturation and Oil Relative Permeability from the Experimental Data in Heavy Oil/Water Systems

Determination of true residual oil saturation and oil relative permeability curve for heavy oil/water systems requires extensive effort and time as the breakthrough time occurs early in the imbibition process and the history match techniques are not able to obtain these two parameters perfectly. The aim of this work is to provide a new insight into the determination of residual oil saturation and oil relative permeability from core flooding in heavy oil/water systems at different temperatures. Literature claimed that the ratio of water relative permeability to oil relative permeability should be considered besides the production and pressure drop data in history matching to determine the residual oil saturation more accurately. In this regard, different relative permeability curves from our previous experimental works are incorporated in a series of simulations that were run for up to 100 PV of water injection. Production and pressure drop data were generated where a normal error distribution is added to the input data. The history matching runs (considering relative permeability ratio) are carried out to examine how many pore volumes of water need to be injected to reach the true residual oil saturation accurately in different experiments. The history matching results (with a Corey relative permeability model), employing the production data, pressure drop data, and the ratio of water relative permeability to oil relative permeability, which can be calculated fairly accurate from the Welge method, confirm that water relative permeability exponent is generally independent of the volume of injected water. Since the irreducible water saturation can be determined nicely during the oil flooding due to the inverse mobility ratio, the water relative permeability is not a function of volume of injected water. In contrast, determination of the true residual oil saturation in five experiments out of six is predicted with an error less than 5%. For several systems at different temperatures, at least 40 PV of water needs to be injected to result in accurate residual oil saturation determination. The oil exponent determination reveals a deviation of 20%-60% from the entered value to the simulation. The ratio of water relative permeability to oil relative permeability should be inserted into the simulation for acceptable history matching of relative permeability determination. The estimation of true residual oil saturation for relative permeability determination from the experimental data cannot be achieved easily. In this study, a new technique described by in the literature has been examined and tested to determine the required pore volume of injected water in different heavy oil/water systems within a wide range of temperatures.