Focusing on the medium-to high-maturity shale oil play of the Qingshankou Formation in the Gulong Sag (Songliao Basin, NW China), pressure-retained, full-closure, and conventional core samples (including long-term stored core samples) with varying thermal maturities were collected, to visually demonstrate the changes in oil content and retained hydrocarbon composition during exposure. The factors influencing the evaporative loss of light hydrocarbons were investigated. We utilized T1-T2 nuclear magnetic resonance (T1-T2 NMR), thermal desorption-gas chromatograph (TD-GC) and Rock-Eval analysis techniques to examine pressure-retained core samples during exposure. A fitting formula was established to describe the relationship between oil content and exposure time. The evaporation of oil content in sample H1-1 (Ro = 1.55%) was best modeled using a power-law decay, whereas an exponential decay provided a better fit for the samples B5-1 (Ro = 1.20%) and G5-1 (Ro = 1.32%). The oil content detected by T1-T2 NMR was significantly higher than that obtained by TD-GC, with Rock-Eval analysis yielding the lowest values. During the exposure of pressure-retained core samples, nearly all nC9- alkanes were lost, nC10–14 showed substantial loss, and nC15+ alkanes experienced partial evaporation in higher maturity samples. Thermal maturity controls the evaporative loss of light hydrocarbons in shale, as reflected in oil composition and pore structure. In high maturity shale, organic matter has minimal impact on hydrocarbon loss, while variations in mineral composition often lead to changes in pore structure. The evaporation rate of block samples is lower than that of powdered samples, with smaller particle sizes exhibiting faster loss rate. Higher temperatures and lower humidity in storage facilitate hydrocarbon diffusion. The research enhances the understanding of light hydrocarbon evaporation processes and offers new insights for evaluating in situ oil content and composition.