Surfactant and polymer are used to improve oil recovery. The micro-emulsion phase composition, viscosity and interfacial tension vary with salinity and injection concentration of chemicals. The viscosity contrast which is very large for heavy oil reservoirs, results in various types of viscous instabilities. There is no comprehensive field-scale modelling on the viscous fingering affecting the oil recovery for different types of surfactant-polymer (SP) flooding. We numerically simulated the above phenomena for different types of SP flooding in five-spot wells setup for both water-wet and oil-wet reservoirs. We have observed that many saturation shocks and banks of micro-emulsion, water and polymer are formed. The viscous fingering at the interface of these banks depend on the reservoir wettability, micro-emulsion phase behaviour and injection concentration of chemicals. Fingering can be suppressed by changing the duration of injection and concentration of surfactant and polymer. We have shown that Type II(+) flooding produces more oil than Type II(−) and Type III. But the oil production by Type II(−) can be increased by adopting better injection strategies. We have made a quantitative comparison of output, i.e., oil recovery vs inputs such as injected mass of chemicals, injection duration and pumping energy, which is of interest to industry. The pumping energy requirement is higher for Type II(−) flooding irrespective of wettability. Our results show that short duration injection of surfactant with multistep reduction of polymer concentration suppresses viscous instabilities and produce more than 90% OOIP. © 2019, Springer Nature Switzerland AG.