Quantifying how inorganic and organic porosity co-evolve in shale during burial and later uplift is a key scientific issue for constraining shale-gas occurrence, storage capacity, and enrichment mechanisms. Despite extensive studies, major uncertainties remain regarding (1) quantitatively separating compaction-driven inorganic pore loss from maturity-controlled organic pore generation and (2) restoring porosity under in situ effective stress through geological time. Here we develop an integrated quantitative framework for the Wufeng–Longmaxi shale gas reservoirs in the southern Sichuan Basin, China. Core samples from production wells, in which porosity is primarily controlled by total organic carbon (TOC), were selected to minimize the interference of mineral composition and compaction heterogeneity. Using a TOC–porosity-intercept approach, inorganic porosity was calculated from the intercept of the porosity–TOC linear relationship and its burial evolution was reconstructed with a compaction model constrained by well burial histories. Organic porosity was quantified by extracting organic-matter surface porosity from field-emission scanning electron microscopy (FE-SEM) images using ImageJ, and a maturity-dependent organic porosity evolution model was established from samples spanning different thermal maturities. Total porosity evolution in the Luzhou, Changning, Weiyuan, and Western Chongqing blocks was reconstructed by integrating the inorganic- and organic-porosity models, and in situ porosity was further restored using pressure-confined porosity experiments. Results indicate that inorganic porosity decreases sharply with burial depth, from an initial value of ~50% to 2.47%–4.05% at maximum burial, mainly controlled by mechanical compaction. Organic porosity increases after entering the hydrocarbon generation window and peaks at 1.54%–1.79%, reflecting pore generation during organic matter transformation. Consequently, total porosity declines to 4.16%–5.76% with increasing burial depth, demonstrating that compaction outweighs hydrocarbon-generation-related porosity creation. Restored in situ porosity fluctuates slightly during subsidence but exhibits an overall decreasing trend, reaching 2.34%–3.78% at maximum burial, and then shows only a modest rebound during late-stage tectonic uplift to 2.49%–4.17% at present. Uncertainties are quantified via bootstrap/Monte Carlo propagation and reported as 95% prediction intervals. These results highlight the coupled controls of compaction, hydrocarbon generation, and tectonic unloading on shale pore evolution and provide a quantitative basis for predicting the distribution of high-quality shale reservoirs.