It is well known that the wetting state of the rock’s internal mineral surfaces affects storage and flow characteristics of the reservoir. Moreover, it has been previously shown that injection of chemicals into the formation leads to alteration of the wettability. The oil characteristic such as the TAN (total acid number) also determines the wetting state of the reservoir. The aim of this study is to examine the effect of alkaline, polymer and alkali-polymer solutions on wettability by means of spontaneous imbibition tests. The data obtained from Amott imbibition tests were analyzed using numerical simulation of the capillary suction process and analytical solution of an equation similar to Fick’s law of diffusion. A detailed comparison is made between rock samples with various mineralogy, oils with different TAN numbers and brines with various composition. The experiments were done on cleaned water-wet core plugs as well as on samples with restored oil-wet state. The results illustrate a large influence of chemicals not only on ultimate oil production, but also on the rate of production over time. The investigation has revealed that the application of chemicals influences capillary forces in the core plug, which can be directly correlated to wettability alteration. The framework presented in the project can be used to evaluate relative wettability change with the application of different EOR agents.