Simulation of asphaltene deposition in vertical oil wells: A computational approach

This study developed an in-house computational model that predicts the thickness of asphaltene deposition in the vertical tubing of oil wells. The proposed model calculates fugacity in the gas-liquid phase using flash calculations based on the Peng-Robinson equation of state (PR EOS). Subsequently, the asphaltene diffusion coefficient and the mass transfer coefficient of asphaltenes to the walls of vertical wells are estimated based on the extent of asphaltene precipitation. These coefficients are then utilized to determine the diffusive deposition mass rate of asphaltenes on vertical well tubing. Furthermore, this study quantitatively predicts asphaltene deposition thickness as a function of variations in oil production rate, tubing inner diameter, and wellhead pressure. The results indicate that asphaltene deposition on the tubing wall reached a thickness of up to 10 mm as the oil production rate approached 250 barrels per day (bbl/d). This thickness subsequently increased to approximately 20 mm when the production rate rose to 1000 bbl/d. Typically, this substantial increase in asphaltene deposition corresponds to a rise in the mass transfer coefficient of asphaltene molecules as the production rate increases. Conversely, an increased tubing diameter decreased the oil flow rate, in turn reducing the mass-transfer coefficient and lowering asphaltene deposition. Variations in wellhead pressure influence the depth at which the bubble point pressure is attained, subsequently affecting both the extent and thickness of asphaltene precipitation. This study proposes a means by which asphaltene deposition can be mitigated. Insulation of the outer tubing wall modifies the temperature profile. A comparative analysis of scenarios with and without insulation revealed that such insulation significantly reduced asphaltene deposition.