With the increasing maturity of conventional oil resources and limited volumes of new conventional resources to replace production, attention has been focused on viscosity reduction to enhance oil production from brown-field reservoirs by the injection of light gases such as CO2. Also, viscosity plays a significant role in managing and controlling injection of CO2 into depleted oil reservoirs or saline aquifers for the purpose of carbon sequestration.
In this study, experimental measurements on viscosity of crude oils and mixtures of crude oils injected with CO2 were performed using accurate technique including a vibrating-wire viscometer and a vibrating tube densimeter. However, for viscosity measurements involving crude oil using vibrating-wire viscometer, asphaltenes precipitation and deposition can be a problem making sensor to provide inaccurate and misleading results. To avoid this problem, the crude oil samples were carefully prepared using ASTM recommended procedure (ASTM2007-80) for separating asphaltenes.
The performance and accuracy of a vibrating tube densimeter is critically dependent on the adopted calibration method. Two calibration methods were investigated: using vacuum and water; and using vacuum, water and toluene as standard fluids. The findings from subsequent validation procedures revealed that the method of calibration using vacuum, water and toluene lead to better performance of the density sensor. The percent average deviations remained within ± 0.2 % for density leading to percent average deviations within ± 5% for viscosity. In contrast, the percent average deviations of using vacuum and water method were above ± 0.2% for density and above ± 5% for viscosity. Consequently, the vacuum-water-toluene calibration of the densimeter was used.
A vibrating-wire viscometer and a vibrating tube densimeter were used to measure the viscosity and density of crude oils Pi and NS. The temperatures studied were between (298.2 and 448.2) K and that of pressures were between (0.1 and 135) MPa. The experimental setup was further modified to measure the viscosity and density of mixtures of: Pi and CO2, and NS and CO2 for a range of compositions (0 ≤ wCO2 ≤ 0.11) at pressures between (0.1 and 70) MPa and temperatures between (298.2 and 448.2) K.
The data were correlated with simple mathematical functions which express the viscosity and density in terms of pressure and temperature. The percent average deviations of the experimental data from the correlation equations were within ± 5 % for the viscosity and ± 0.2 % for density.
The predictive capabilities of some physically-based viscosity models were tested using the experimental data. The models used were versions of the effective hard-sphere model for fluid mixture viscosity: (1) original model of Dymond and Assael, (2) an extended version by Caudwell et al, (3) and 1st and 2nd extended versions by Ciotta et al. The results obtained showed that the 2nd version of Ciotta et al model is capable of reproducing the viscosity prediction of crude oil within the limits of the percent average deviations of the experimental data, ± 5 %. For the mixtures of crude oil and CO2, the Caudwell et al model was able to predict the viscosity of both sets of mixtures (Pi and CO2 & NS and CO2) to within percent average deviations of ± 5 % from the experimental data. The injection of CO2 into the crude oils, markedly, reduced the viscosity of both crude oils.