To solve the contradiction between the injectability of the profile control agent and its profile control ability in low-permeability reservoirs, a novel in-situ polymeric microsphere profile control agent is proposed. In-situ-polymeric microsphere (ISPM) emulsion was injected into the formation by polymerization to form microspheres for profile control. The emulsion was composed of divinylbenzene, acrylamide monomer, surfactant fatty acid polyoxyethylene ether sulfate, sorbitan oleate and p-hydroxyanisole. An ISPM particle diameter of 1.88 to 30.60 μm was achieved by adjusting the amount of Span80. The ISPM emulsion polymerization time was set to a maximum of 8.4 hours to ensures that the microsphere emulsion could be successfully injected into the formation. Polymerization reaction time increased with the increase of salinity. pH has no significant effect on the reaction time in the range of 5 to 8. Fourier transform infrared spectroscopy (FT-IR) experiments showed that the ISPM emulsion could be polymerized in tiny pores to form microspheres. Furthermore, multipoint pressure measurement experiment and electron microscopy results showed that the ISPM emulsion presented good injectability in low-permeability cores, and the microspheres formed after emulsion polymerization achieved deep plugging in cores. The injectability and blocking effect of the core with ISPM was found to be better than with microspheres (61.7%) for the blocking rate of the core at 10–15 cm deep reached 81.55%. The double-layer heterogeneous core flooding experiments showed that ISPM could expand the sweep volume of subsequent injection fluids and achieve improved oil production and water control. The composite slug composed of surfactant BA and ISPM demonstrated better profile control effect than the ISPM slug alone, and the enhanced oil recovery factor reached 15.65%.

Surfactants play a crucial role in enhanced oil recovery by reducing interfacial tension (IFT) and promoting emulsification. However, for low-permeability reservoirs after water flooding, it remains unclear which ability is more crucial for improving recovery. To address this question, this study compared the oil displacement effects of three surfactants with different IFTs and emulsifying properties using a series of core displacement experiments. The results show that the strongly emulsifying surfactant S1# achieved an incremental oil displacement efficiency of 9.94%, which is higher than that of the ultra-low-IFT surfactant S3# (8.63%), while the composite surfactant S2# (strong emulsification + ultra-low-IFT) achieved the highest incremental oil displacement efficiency of 11.79%, representing an improvement of 3.16% compared with S3#. The three surfactants have the same effect on improving oil recovery and oil displacement efficiency in heterogeneous rock cores. Strong emulsification promotes abundant in situ emulsions, increases injection pressure (up to 0.85 MPa compared with 0.41 MPa for ultra-low-IFT flooding), and expands the swept volume, indicating that emulsification-driven sweep improvement dominates over capillary-force reduction under the investigated conditions. Furthermore, a composite displacement strategy combining emulsification-driven plugging and ultra-low-IFT oil washing achieved a 12.37% recovery improvement while maintaining relatively low injection pressure (~0.48 MPa). However, the effectiveness of this mechanism is strongly dependent on reservoir heterogeneity. When the permeability contrast increased from 5.4 to 17.3, incremental recovery decreased by up to 7.03%, demonstrating that strong heterogeneity significantly limits the effectiveness of emulsification-driven sweep expansion. This work advances the understanding of surfactant flooding mechanisms and provides guidance for designing and deploying surfactants in water-flooded low-permeability reservoirs.