A mathematical framework for underground hydrogen storage in reservoirs with geo-methanation and enhanced gas recovery
Journal
Energy Conversion and Management
Date Issued
December 1, 2025
DOI
10.1016/j.enconman.2025.120328
Abstract
This study introduces a mathematical framework for estimating the performance of underground hydrogen storage operations, considering hydrogen injection into a depleted reservoir, co-injection of hydrogen and CO<inf>2</inf> for geo-methanation, and hydrogen injection for enhanced gas recovery through an approximate piston-like displacement. The model integrates the material balance equation, various equations of state (EoS), advection-driven gas mixing, a water influx model and Gibbs energy minimization method. Results of a parametric study for a reference reservoir show that increasing initial reservoir pressure from 2000 to 5000 psi improves storage efficiency from 22 % to 42 %, and raises natural gas recovery from 60 % to 87 %. Higher temperature reduces injected hydrogen volumes due to gas expansion, while production rates above 500 MMSCF/day suppress water influx, increasing available pore space for storage. At high salinity, hydrogen solubility decreases, reducing storage efficiency by up to 12 %. Piston-like injection at a 1:8 H<inf>2</inf>/NG ratio leads to hydrogen storage volumes of 40–80 BSCF, compared to 20–40 BSCF for the 1:16 case, with storage efficiencies of 8–11 % and 4–6 %, respectively. Dissolved hydrogen remains minimal (≤1.2 BSCF), confirming the dominance of free gas storage. The hydrogen drive index reaches up to 16 % in piston-like scenarios, supplementing natural gas expansion and delaying water influx. No hydrogen breakthrough is observed. Differences of up to 63 BSCF in storage estimates between EoS at high pressure highlight the importance of thermodynamic model selection. Applied to the Frigg Field, the framework confirms suitability for large-scale hydrogen storage and recovery under diverse operational conditions.