This thesis contributes to increasing the technology readiness level of hydrogen storage in gas reservoirs, which will be required when hydrogen has become a major energy carrier in the future Dutch energy system. It addresses the mixing processes with resident gases that occur during hydrogen storage operations in gas fields, and analyzes their implementation in a reservoir simulator. The CMG GEM reservoir simulator allows incorporation of mechanical dispersion and effective molecular diffusion into its simulations, while solving the advection dispersion transport equation fully implicitly, as well as gravitational segregation and other macro scale mixing phenomena. Mechanical dispersion is quantified by its main parameter dispersivity, for which a large uncertainty exists in the literature. Dispersivity represents pore scale fluid velocity differences caused by microscale heterogeneities in a porous medium. Due to the lack of adequate hydrogen dispersivity experiments, a range of dispersivity values is collected from literature on (groundwater) dispersivity experiments in sandstones. A sensitivity analysis is conducted, in which the influence of the different mixing processes on the mixing between working gas and cushion gas is analyzed. For this, a conceptual reservoir model (radial and homogeneous), with properties based on Dutch sandstone gas fields was built in CMG GEM. The effect of molecular diffusion on mixing proves to be negligible compared to mechanical dispersion at typical reservoir flow rates. Furthermore, the results of the simulations prove to be significantly influenced by numerical dispersion, which is a calculation error, dependent on grid size and time step. The effect of numerical dispersion compared to mechanical dispersion is quantitatively analyzed, after which various options are introduced to deal with numerical dispersion in a way that the physical processes are most realistically represented. The work in this thesis demonstrates the challenges of realistically implementing hydrogen storage mixing processes in a reservoir simulator, and should be regarded as a foundation for further research.

Sequestration of carbon dioxide (CO2) in depleted gas reservoirs is an attractive choice, especially in The Netherlands, to reduce CO2 emissions into the atmosphere. Injection of CO2 in the subsurface geological formations can distort local thermal, chemical and geomechanical equilibria. As such, it results in highly coupled (thermo)physical effects in the near wellbore region, referred to as “near wellbore effects”. In this work, qualitative and quantitative descriptions of the near wellbore effects in depleted gas fields on macroscopic scale are provided. The primary focus is on the thermal effects (i.e., Joule-Thomson effect, water vaporization and CO2 dissolution) and specific chemical effects (i.e., salt precipitation and hydrate formation). Occurrence and the corresponding magnitude of certain near wellbore effects influence the injectivity of CO2 both positively and negatively. In several occasions these effects can lead to severe reduction of the injectivity. To accurately model these effects, thermal multi-component multi-phase simulations are conducted using both TOUGH2-ECO2MG and CMG-GEM commercial-grade simulators. Important is that these simulations include precipitation of salt and phase changes of CO2 during repressurization of the reservoir. Extensive sensitivity study on numerous 1D, 2D and 3D reservoirs with various injection parameters and degrees of heterogeneity is carried out. A comprehensive 3D geological model of the nearly depleted P18-4 gas field (located in the Dutch North sea) is also investigated, in order to examine the near wellbore effects in a real-field application. Moreover, the potential control of the near wellbore thermal effects by interplay of controllable operational parameters (e.g. rate, temperature or composition) and the local reservoir pressure and temperature conditions is presented. Results reveal that the high injection rates targeted for real CO2 injection (i.e., 1.1 Mt/yr) in combination with low initial reservoir pressures (> 40 bar) and a large reservoir volume provide favorable conditions for development of predominantly excessive cooling effects (15 oC) near the wellbore. Injection of CO2 in gaseous conditions at low temperatures can cause such strong cooling that hydrate can form, which can potentially jeopardize the injection process due to clogging of the reservoir. However, as for its specific geometry and well location, the thermal effects are significantly less pronounced in the P18-4 field model. Besides, heterogeneity of the formations plays a key role in the distribution of the appearing effects along the wellbore. Overall, for the considered cases, the injectivity is found to be enhanced rather than decreased by the studied near wellbore effects, with the proviso that the conditions in the near wellbore region remain outside the hydrate formation window.