Abstract: Countercurrent imbibition is an important mechanism for tight oil recovery, that is, water imbibes spontaneously from the fracture into the porous matrix while oil flows reversely into the fracture. Its significance over cocurrent imbibition and forced imbibition is highlighted when permeability reduces. We used the computed tomography (CT) scanning to measure the one-dimensional evolution of water saturation profile and countercurrent imbibition distance (CID) at different fluid pressures, initial water saturations, and permeability. Surprisingly, experiments show that CID evolution for tight reservoir cores dramatically deviates from the classical diffusive rule (i.e., evolutes proportional to square root of time, t0.5). At early stage, CID extends faster than t0.5 (super-diffusive); while at late stage, CID extends much slower than t0.5 (sub-diffusive). After tens of hours, the CID change becomes too slow to be practically efficient for tight oil recovery. This research demonstrates that this deviation from classic theory is a result of (1) a much longer characteristic capillary length than effective invasion depth, which eliminates full development of a classical displacement front; and (2) non-zero flow at low water saturation, which was always neglected for conventional reservoir and is amplified in sub-mili-Darcy rocks. To well depict the details of the imbibition front in this situation, we introduce non-zero wetting phase fluidity at low saturation into classical countercurrent imbibition model and conduct numerical simulations, which successfully rationalizes the non-diffusive behavior and fits experimental data. Our data and theory imply an optimum soaking time in tight oil recovery by countercurrent imbibition, beyond which increasing exposed fracture surface area becomes a more efficient enhanced oil recovery (EOR) strategy than soaking for longer time.