| Summary: | Asphaltenes are the heaviest and most complex components in crude oil. Their precipitation and deposition may cause severe problems during production, transportation and processing of crude oil, hence affecting efficiency and cost of production in both upstream and downstream operations. During crude oil production, asphaltenes can deposit in the pores of reservoir rocks resulting in formation damage. Despite significant research, asphaltene behaviour in different flow regimes remains elusive. This thesis presents an investigation into crude oil asphaltene precipitation and deposition at ambient and reservoir conditions, using different experimental techniques and multi-scale simulations. Asphaltene precipitation can be triggered by altering the crude oil composition, which has been studied here through filtration experiments; a useful method to determine the amount of asphaltene precipitation induced by any precipitant. The relationship between the mass of precipitated asphaltenes and the mass of a precipitant in a crude oil+hydrocarbon system was compared to a crude oil+CO2 mixture in high pressure-high temperature experiments under conditions where the assumption of full miscibility is not valid. The precipitation onset point for the heavy crude oil used throughout the study was precisely determined in terms of the Hildebrand solubility parameter, showing for the first time that CO2 follows the same behaviour as hydrocarbon precipitants. However, the solubility parameter was not suitable for correlating precipitation at different temperatures. Subsequently, this work reports on asphaltene deposition in glass capillary flow experiments under laminar conditions where asphaltenes were precipitated with n-heptane, an analogue fluid for CO2. This study elucidates the fundamental behaviour of asphaltene deposition through the unique combination of techniques not previously been illustrated in the literature. The experiments involved co-injecting a toluene diluted crude oil and n-heptane through a capillary at constant volumetric flow rate while simultaneously measuring the pressure drop across the capillary. Increasing the total volumetric flow rate led to more deposition, observed through confocal laser-scanning microscopy and mass measurements, with more deposits build up at the capillary inlet. Beyond a critical flow rate, the deposition rate decreased as entrainment effects became more profound. Deposition was limited as the pressure levelled off in all the experiments, and oscillations in pressure suggested dynamic cycles between deposition and entrainment. In addition, a dependence of deposition on the floc size was revealed, showing that smaller particles dominate the deposition process. The experimental results were then compared to stochastic rotation dynamics simulations at the colloid scale, where a constant pressure drop over the capillary length was imposed. Results show a more homogeneous deposition profile with higher Peclet number, which is in agreement with the experimental findings. Additionally, deposition studies were extended to real sandstone reservoir samples using C7 and CO2 as precipitants at more realistic reservoir conditions. Pressure drop measurements across the core to quantify permeability damage were combined with X-Ray Microtomography (microCT) to visualise the deposits produced within the porous medium. The permeability measured through core-flooding experiments was compared to lattice-Boltzmann calculations in the segmented microCT images before and after deposition, where an increase in the flow rate showed a decrease in dimensionless permeability. Fitting the pressure drop data to a computational Deep Bed Filtration model allowed for a distinction between pore surface and pore throat deposition, which was confirmed by the microCT images of the location of asphaltene deposits. The results elucidate important asphaltene-related issues in porous media and provide a suitable framework for developing and improving deposition models.
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