Nano-scale kerogen pores in unconventional reservoirs make reserve quantification and production forecast very uncertain, owing to drastic impacts on adsorption and confined-fluid characterization. Routine and special core analyses are less reliable in unconventional formations because of exaggerated impacts by pore size distribution (PSD). We presented a new relative permeability model derived from pore size distribution measurements, and used Eagle Ford core and fluid samples to illustrate the important difference in rock-fluid interaction and notably production performance. Micropores in unconventional reservoirs play an important role deterministic to ultimate recovery in stimulated reservoir volume (SRV). Yet it largely remains unclear how pore size distribution for these nano-pores would impact rock-fluid interaction and thus its influence on reservoir production behavior. We systematically investigate the relationship between PSD and relative permeability because of complex fluid behavior in kerogen pores. These nanopores affects flow behavior through three different mechanisms: (1) capillarity for confined fluid; (2) adsorption for multi-component fluid; and (3) permeability alteration in depletion. In this paper, we focused on efforts for the last production driver, that how relative permeability model differs in unconventional reservoirs compared with conventional ones. A new relative permeability model was developed, coming out of algorithm concerning capillarity for confined fluid (Mezzatesta el. al., 2015), to modify and refine those from Corey's equations, taking into account of pore structure and fluid flow in nano-pores. We integrated the new model into commercial reservoir simulator, CMG Imex, to predict reservoir production profile using data from several Eagle Ford samples, and showed that PSD may have significant impact on relative permeability, which further affected production behavior. This may suggest a new rock-typing mechanism for a better understanding in unconventional reservoirs. Results showed that, starting from the same Corey's equations, different PSD yielded different relative permeability curves, and the cumulative oil production might differ more than 25% using the same PVT properties for some confined fluids. In addition, we demonstrated the reservoir criterion where the PVT and PSD may have a larger impact on production. This analysis would shed light on reserves and differences in production type curves for key unconventional reservoirs. A substantial increase in oil production and/or reserves was observed for some fluids when PSD was integrated into relative permeability model with GOR profile similar to that observed in the fields. The new method may bring additional insight to greatly mitigate uncertainties for productivity and EUR evaluation for unconventional reservoirs, and useful to understand why production profile had a large variation even for blocks next to each other.