Most unconventional wells typically exhibit limited oil production during the primary production stage, primarily due to ultralow permeability of the rock matrix and immaturity of the organic matter. To understand the key factors responsible for this limitation and identify candidate sweet spots for drilling, we conduct physical simulations of the primary production stage in the laboratory. In this study, Duvernay shale samples undergo a single-cycle methane injection process to simulate the primary production stage. We utilize a visualization cell to explore oil-recovery mechanisms under representative reservoir conditions. We soak oil-saturated core plugs with methane at 4,150 psig and a reservoir temperature of 90°C to restore initial reservoir conditions. After equilibrium, we deplete the cell pressure at a controlled rate to simulate the primary production stage. Using two shale samples with different thermal maturity levels, our results demonstrate that methane diffuses into both cores during the soaking; however, it dissolves in oil only in the mature shale sample, resulting in a live oil with a solution gas-oil ratio of 932 standard ft3/stock tank barrel. During the primary production stage, we observe significant oil production under the solution-gas drive mechanism from the mature shale, while the immature shale exhibits negligible oil production. Natural fractures enhance gas penetration into the core, contributing to increased oil production in the primary production stage. Ultimately, the mature shale sample exhibits an oil recovery factor of 25.6% of original oil-in-place after the primary production stage, a remarkable contrast to 1.5% recovery observed in the immature shale. This difference is attributed to the immaturity of the organic matter, insufficient original oil-in-place, and absence of connected oil-wet pore network in the immature shale sample, confirmed by wettability evaluation and rock-eval pyrolysis data.
