Study on the calorific value change of withdrawal gas of hydrogen-enriched natural gas in depleted gas reservoir underground storage systems

Abstract Underground hydrogen storage (UHS) in depleted gas reservoirs is emerging as a viable strategy for large-scale energy buffering, particularly suited to balancing the intermittency of renewable power sources. This study develops a numerical model to simulate multi-cycle injection and withdrawal of hydrogen-enriched natural gas, exploring how varying hydrogen blending ratios affect the calorific value of the withdrawn gas. A cubic reservoir model (100 m × 100 m × 20 m) was used under injection pressures from 12 MPa to over 30 MPa, with a 180-day injection, 60-day shut-in, and 120-day withdrawal per cycle. The simulation comprehensively incorporates Darcy flow, convection, and diffusion mechanisms to capture the internal transport behavior of hydrogen and methane under realistic underground storage conditions. Results show that gas migration is dominated by Darcy flow and convection, while diffusion plays a minor role. Higher hydrogen fractions in the injected gas lead to larger fluctuations in the produced gas’s volumetric calorific value, requiring more hydrogen supplementation and longer adjustment cycles to meet end-use quality standards. Moreover, extended simulations evaluate the effect of injection–production well placement. When the injection well is positioned closer to the production well, the hydrogen supplementation demand is reduced, although the total duration of supplementation may increase. Optimal spacing configurations achieve a balance between gas quality, system reliability, and infrastructure investment. The findings provide critical insights for engineering applications, guiding the design of UHS systems to maintain steady calorific value delivery and ensure safe, efficient, and cost-effective operation.