Abstract: To address the unclear understanding of the imbibition patterns of nanoemulsions in tight reservoirs at the field scale, a numerical simulation method was employed to analyze the factors influencing the imbibition recovery rate from both laboratory and field scales. The results show that at the laboratory scale, as permeability increases, the imbibition recovery rate rises to 47% and then stabilizes; with increasing capillary pressure, the recovery rate gradually increases to 61%; and as the critical adsorption amount increases, the recovery rate initially stabilizes at 28% before decreasing to 2%. At the field scale, the imbibition recovery rate increases to 38%, 35%, and 11% with the rise in permeability, capillary pressure, and diffusion coefficient, respectively; and it decreases to 5% as the critical adsorption amount gradually increases. The variation patterns of factors influencing the imbibition recovery rate at the field scale differ from those at the laboratory scale, primarily because the smaller matrix volume and larger contact area between the core and fracturing fluid at the laboratory scale allow the fracturing fluid to enter all pores of the core, which does not reflect the actual field conditions. This study provides guidance for the design of fracturing fluid parameters in tight oil reservoirs.

Key words: tight oil reservoirs, nanoemulsions, low-permeability reservoirs, hydraulic fracturing, surfactants, wettability