The deposition of asphaltenes in the petroleum industry has been found to be a significant factor affecting the profitability of petroleum production and refining. For this reason, many efforts have been made to clarify the mechanism of deposition formation and to find measures to reduce its harmful impact on the efficiency of oil production and refining. Recent reports on the mechanism of deposit formation by asphaltenes suggest that it is a phase transition phenomenon. Many studies have shown that this process can be slowed by using chemical inhibitors. Different classes of chemical substances (non-polymeric, organic compounds, polymers, ionic liquids and nanomaterials) have been found to be capable of inhibiting asphaltene precipitation. This paper presents a comprehensive review of asphaltene deposition research and makes an attempt to decipher the convoluted asphaltene deposition phenomena and relate the chemistry of asphaltene inhibitors to the nature of treated petroleum oils. The choice of appropriate additives to mitigate asphaltene deposition in commercial oil and gas facilities requires comprehensive knowledge of chemistry of oils, asphaltenes, and the chemical substances, along with the appropriate laboratory techniques that best mimic the commercial operation conditions.

A comprehensive investigation of a highly complex petroleum refinery (Nelson complexity index of 10.7) during the processing of 11 crude oils and an imported atmospheric residue replacing the design Urals crude oil was performed. Various laboratory oil tests were carried out to characterize both crude oils, and their fractions. The results of oil laboratory assays along with intercriteria and regression analyses were employed to find quantitative relations between crude oil mixture quality and refining unit performance. It was found that the acidity of petroleum cannot be judged by its total acid number, and acid crudes with lower than 0.5 mg KOH/g and low sulphur content required repeated caustic treatment enhancement and provoked increased corrosion rate and sodium contamination of the hydrocracking catalyst. Increased fouling in the H-Oil hydrocracker was observed during the transfer of design Urals crude oil to other petroleum crudes. The vacuum residues with higher sulphur, lower nitrogen contents, and a lower colloidal instability index provide a higher conversion rate and lower fouling rate in the H-Oil unit. The regression equations developed in this work allow quantitative assessment of the performance of crucial refining units like the H-Oil, fluid catalytic cracker, naphtha reformer, and gas oil hydrotreatment based on laboratory oil test results.

The compatibility of constituents making up a petroleum fluid has been recognized as an important factor for trouble-free operations in the petroleum industry. The fouling of equipment and desalting efficiency deteriorations are the results of dealing with incompatible oils. A great number of studies dedicated to oil compatibility have appeared over the years to address this important issue. The full analysis of examined petroleum fluids has not been juxtaposed yet with the compatibility characteristics in published research that could provide an insight into the reasons for the different values of colloidal stability indices. That was the reason for us investigating 48 crude oil samples pertaining to extra light, light, medium, heavy, and extra heavy petroleum crudes, which were examined for their colloidal stability by measuring solvent power and critical solvent power utilizing the n-heptane dilution test performed by using centrifuge. The solubility power of the investigated crude oils varied between 12.5 and 74.7, while the critical solubility power fluctuated between 3.3 and 37.3. True boiling point (TBP) analysis, high-temperature simulation distillation, SARA analysis, viscosity, density and sulfur distribution of narrow petroleum fractions, and vacuum residue characterization (SARA, density, Conradson carbon, asphaltene density) of the investigated oils were performed. All the experimentally determined data in this research were evaluated by intercriteria and regression analyses. Regression and artificial neural network models were developed predicting the critical solubility power with correlation coefficients R of 0.80 and 0.799, respectively.

The production of very-low-sulfur residual fuel oil is a great challenge for modern petroleum refining because of the instability issues caused by blending incompatible relatively high-sulfur residual oils and ultra-low-sulfur light distillates. Another obstacle in the production of very-low-sulfur residual fuel oil using hydroprocessing technology is the contradiction of hydrodesulfurization with hydrodemetallization, as well as the hydrodeasphaltization functions of the catalytic system used. Therefore, the production of very-low-sulfur residual fuel oil by employing hydroprocessing could be achieved by finding an appropriate residual oil to be hydroprocessed and optimal operating conditions and by controlling catalyst system condition management. In the current study, data on the characteristics of 120 samples of heavy fuel oils produced regularly over a period of 10 years from a high-complexity refinery utilizing H–oil vacuum residue hydrocrackers in its processing scheme, the crude oils refined during their production, the recipes of the heavy fuel oils, and the level of H–oil vacuum residue conversion have been analyzed by using intercriteria and regression analyses. Artificial neural network models were developed to predict the characteristics of hydrocracked vacuum residues, the main component for the production of heavy fuel oil. It was found that stable very-low-sulfur residual fuel oil can be manufactured from crude oils whose sulfur content is no higher than 0.9 wt.% by using ebullated bed hydrocracking technology. The diluents used to reduce residue viscosity were highly aromatic FCC gas oils, and the hydrodemetallization rate was higher than 93%.

Ebullated bed vacuum residue hydrocracking is a well-established technology providing a high conversion level of low-value residue fractions in high-value light fuels. The main challenge in this technology when processing vacuum residues derived from different crude oils is the sediment formation rate that leads to equipment fouling and cycle length shortening. With the severity enhancement, the asphaltenes become more aromatic and less soluble which leads to sediment formation when the difference between solubility parameters of asphaltenes and maltenes goes beyond a threshold value. Although theoretical models have been developed to predict asphaltene precipitation, the great diversity of oils makes it impossible to embrace the full complexity of oil chemistry by any theoretical model making it impractical for using it in all applications. The evaluation of process data of a commercial ebullated bed vacuum residue hydrocracker, properties of different feeds, and product streams by intercriteria and regression analyses enabled us to decipher the reason for hydrocracked oil sediment content rising from 0.06 to 1.15 wt.%. The ICrA identified the presence of statistically meaningful relations between the single variables, while the regression analysis revealed the combination of variables having a statistically meaningful effect on sediment formation rate. In this study, vacuum residues derived from 16 crude oils have been hydrocracked as blends, which also contain fluid catalytic cracking heavy cycle oil and slurry oil (SLO), in a commercial H-Oil plant. It was found that the hydrocracked oil sediment content decreased exponentially with fluid catalytic cracking slurry oil augmentation. It was also established that it increased with the magnification of resin and asphaltene and the reduction in sulfur contents in the H-Oil feed.

Refining light and heavy oils in different proportions seems attractive, especially in cases of geopolitical, economic, environmental, and logistical constraints. The economical attractiveness could be undermined in cases where incompatibility occurs. The current study explores a highly complex refinery performance during processing a blend consisting of 17 crude oils of which one was extra light, five were light, nine were medium, and two were heavy. A n-heptane dilution test, using centrifugation, was employed to assess the colloidal stability of crude oils. In addition, a previously established correlation to relate crude oil vacuum residue fraction Conradson carbon content to asphaltene peptizability Sa according to ASTM D 7157 was also availed for the purpose of evaluating colloidal stability. It was found that the crude desalter amperage increases with the ${\displaystyle \frac{SBN}{IBN}}$ ratio and Sa reduction, reaching its maximum allowable value of 180 A at the ${\displaystyle \frac{SBN}{IBN}}$ ratio of 1.35, and Sa of 0.64. The ${\displaystyle \frac{SBN}{IBN}}$ ratio was found more reliable in predicting oil compatibility than the other ${\displaystyle \frac{SBN}{{IN}_{max}}}$ ratio used to assess colloidal stability in various research. Along with the increase in crude desalter amperage, fouling of the heat exchangers of a crude oil distillation plant was also recorded. An intercriteria analysis of process data together with crude composition data, and compatibility indices revealed that the amperage enhancement is statistically meaningfully related to an increase in the heaviest crude oil content in the process blend and the compatibility indices ${\displaystyle \frac{SBN}{IBN}}$ ratio and Sa, while the fouling was related only to the content of one of the light crude oils in the processed blend.