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Subsurface upgrading of heavy oil via solvent deasphalting has been reported previously under laboratory and field conditions. However, these processes require a relatively high solvent-to-oil ratio (SvOR > 1:1 v/v) to induce subsurface asphaltene precipitation, increase oil production, and upgrade crude oil in situ. In our previous work, lab experiments demonstrated that asphaltene precipitants reduce the SvOR (∼30−50 vol %) for subsurface upgrading at initial reservoir conditions and when heat is also applied. In this work, the preparative separations were carried out using benzoyl peroxide (BP), Fe 2 O 3 , and NiO nanoparticles as asphaltene precipitants for Venezuelan and Canadian heavy crude oils. Initial experiments showed that BP is the most effective additive, producing an increase of ∼21 wt % in the asphaltene content for a 2500 mg/kg dosage. Preparative separations at 5:1 vol/wt ratio and 50 °C showed that the order of activity as asphaltene precipitants is BP > NiO > Fe 2 O 3 . In the presence of nickel-and iron-containing precipitants, most of these metals are found in the asphaltenes indicating that the nanoparticles are acting as nucleation sites. Spectroscopic and mechanistic studies using BP as precipitant suggest a free radical mechanism that involves the thermally initiated homolytic cleavage of BP, follow by abstraction of a hydrogen atom from the asphaltenes or maltenes to produce free radical species. In the termination steps, the latter species react with each other to generate new asphaltene species that are not present in the original crude oils.

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In view of the great impact of asphaltene deposition in the petroleum industry, it is of paramount importance to estimate the tendency of crude oils and petroleum products towards precipitation as well as the potential amount of material that can precipitate. These are important parameters to consider in designing and monitoring of different processes in the petroleum value chain. It is common knowledge that asphaltene precipitation is strongly related to the colloidal nature of petroleum materials. Rather recently, a new method to evaluate the colloidal stability of crude oils was developed based on the determination of the solubility distribution of asphaltenes. It was found that samples from different origins give different solubility distribution patterns and that those patterns can be correlated to precipitation tendencies of crude oils. In this work, asphaltene distributions in solid deposits are analyzed and compared to the original asphaltene distributions in the corresponding original oils. Additional chemical and physical properties were also examined and compared. This study aims to link specific asphaltene solubility distribution patterns to the formation of deposits and to find out how asphaltenes found in deposits are compared with the asphaltenes in the materials that originated them. This information is relevant for thermodynamic as well as kinetic modeling of the asphaltene deposition phenomena. The results indicated significant differences between asphaltenes from the original crude oils and their corresponding deposits. Quantification of these differences in terms of solubility was carried out and showed that asphaltenes from deposits are in average composed of less soluble asphaltenes than those present in the original crude oils. In practical terms, this means that asphaltenes separated using heptane or pentane might not be representative of the asphaltenes found in deposits. The compositional variation of solid deposits seems to point out towards a complex mechanism of formation that is usually not considered in the tools used to model this phenomenon.