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Experimental investigation of the effect of temperature on two-phase oil-water relative permeability. [Dataset]


Draco Iyi
Data Collector

Babs Oyeneyin
Data Collector


This work investigates the effect of temperature on oil-water relative permeability using well-sorted unconsolidated silica sandpacks, by adopting the unsteady-state relative permeability method, and by applying numerical history matching technique. The series of experiments were conducted at different temperatures of 40, 60, and 80 °C under three levels of injection flow rate (0.0083, 0.0125, 0.0167 cm3/s) for two different oil samples. The findings show that oil-water relative permeability is a function of temperature, water injection flow rate and oil viscosity. Generally, the profile of oil and water relative permeability curve changes with varying temperature, oil viscosity and water injection flow rate at the same operating condition. The accompanying file contains the results of this study to investigate the effect of varying temperature on oil-water relative permeability and to developed empirical constants for an established correlation to be used under a specific range of conditions.


BALOGUN, Y., IYI, D., OYENEYIN, B., FAISAL, N., OLUYEMI, G. and MAHON, R. 2021. Experimental investigation of the effect of injection temperature on two-phase oil-water relative permeability. [Dataset]. Journal of petroleum science and engineering [online], 203, article 108645. Available from:

Acceptance Date Mar 3, 2021
Online Publication Date Mar 14, 2021
Publication Date Aug 31, 2021
Deposit Date Apr 9, 2021
Publicly Available Date Mar 15, 2022
Publisher Elsevier
Keywords Multiphase flow; Relative permeability; Temperature; Porous media flow; Empirical model; History matching
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Type of Data Excel (.xlxs) and supplementary text (.txt) file.
Collection Date Sep 10, 2020
Collection Method The porous media used for all the tests in the study is made up of unconsolidated commercial grade silica sand (20/40 mesh size). An unconsolidated system has been used mainly due to the relative ease of flooding viscous oil without building up high pressures at the injection face. The test fluid used for the experiments are mainly brine and oil. While the brine is divided into two categories; synthetic formation water and synthetic seawater; the oil sample is in two categories namely and Shell Rimula R4 L 15W - 40 engine oil, and mineral oil. These fluids are chosen because of the high level of immiscibility, ease of handling, and well-known or easily determined properties. In this study, two different synthetic brine samples are prepared to simulate the formation water (FW) inside the porous sample before flooding and seawater (SW) to simulate the seawater used for water injection during the core flooding process. The brine solutions are prepared in the lab using deionized water and appropriate amounts of sodium chloride (NaCl), anhydrous calcium chloride (CaCl2), potassium chloride (KCl), sodium hydrogen carbonate (NaHCO3) and magnesium chloride hexahydrate (MgCl2.6H2O) analytical grade salts. The viscosity of the oil sample was measured using a Fann 35 viscometer which is a typical Couette rotational viscometer capable of measuring the rheological properties of fluids: both Newtonian and non-Newtonian. The viscometer measures the viscosity as a function of shear rate. Fluid viscosities were measured at varying temperature ranges from 20 OC to 80 °C. The Fann model 35 viscometer used is a direct-reading instrument in twelve speed designs. In this viscometer, the oil sample is contained in the annular space between an outer rotating cylinder and the bob (inner cylinder). For density measurements, the Anton-Paar portable density meter: DMA 35 was used. The experimental setup was made up mainly of three sections: injection, core holder and production. Fluid was injected using a multi-solvent High-Performance Liquid Chromatography (HPLC) dual piston pump supplied by 220V. The core-holder packed with sand was placed inside the convection oven vertically and saturated with the synthetic formation brine using the HPLC pump. Relative permeability was computed through history matching with a commercial core flooding numerical simulator – Sendra. The software is a fully implicit 2-phase one dimensional black-oil simulation for analysing data from special core analysis experiment. In this study, eighteen (18) different experiments were carried out to investigate the effect of temperature on relative permeability. All the experiments involved a displacement flow performed at varying temperature of 40, 60, and 80 °C with varying injection flow rates of 0.0083, 0.0125, and 0.0167 cm3/s. Two different oil samples of varying viscosities and densities were used. A relatively low flow rate was chosen so as to mimic flow in a typical petroleum reservoir and all injection fluids are at ambient temperature. Full details of experimental methodology (Section 2), relative permeability calculations (Section 3) and results (Section 4) can be found in the article published in Journal of Petroleum Science and Engineering (