Solvent aided steam injection is one of the most promising enhanced oil recovery methods for recovering heavy oil and oil sands. Experiments, simulations, and some field pilots have demonstrated that a hybrid steam and solvent injection can result in better production rates and higher ultimate oil recovery. However, the simulation studies assume that the steam and solvent mixture will be at the sandface in pre-determined pressure, temperature, and steam/solvent gas molar ratios, neglecting the pressure gradients, heat losses, and condensations that occur along the wellbore, which will affect the thermodynamic condition of the mixture at the perforation zones. This paper provides important background information regarding the wellbore numerical modeling in hybrid steam/solvent injection. Detailed formulations of pressure gradient and enthalpy calculations are described, and we investigate the effect of partial pressure on the condensation behavior of steam and solvent. The benefits of the model on the steam and solvent co-injection process optimization are examined with three case studies, where steam is co-injected with a) gas condensate, b) medium weight solvent, and c) heavy weight solvent. Gas condensate is unlikely to condense in the wellbore. However, medium and heavy weight solvents might condense depending on the steam and solvent ratios. To avoid solvent condensation, it is suggested to reduce the solvent ratio compared to steam, or to increase the steam quality at the wellhead. As a result, the solvent partial pressure will be reduced.