## 2 Methodology
### Model Setup
Dawsonite, mackinawite, elemental sulfur, albite (and pyrite) are considered as potential secondary phases, which may form at saturation. The clay minerals are considered as follows: illite is defined as a primary mineral phase, and the cation exchange capacity of chlorite, illite, montmorillonite, and kaolinite are estimated based on the data given by [PERSON] and [PERSON] [44]. An initial small amount of CO\({}_{2}\) (\(p\)CO\({}_{2}\) = partial pressure of CO\({}_{2}\) = 1.0 atm) is assumed to be available in the cap rock, reservoir rock, and underlying rock from burial. The possible outgassing of CH\({}_{4(\mathrm{g})}\), N\({}_{2(\mathrm{g})}\), CO\({}_{2(\mathrm{g})}\), H\({}_{2}\)S\({}_{(\mathrm{g})}\), and H\({}_{2(\mathrm{g})}\) is assumed in all cells. The reservoir rock (cells 183-850) has an initial porosity of 10% (\(n\) = 0.1), 2.5% (\(n\) = 0.025) of the pore space is filled with irreducible water, which is equal to 1 L H\({}_{2}\)O, and 7.5% (\(n\) = 0.075) of the pore space is filled with gas. The total volume is 40 L (1 L/0.025) and therefore, 3 L are filled with gas (40 L \(\times\) 0.075). The porosity is filled with 3 L gas and 1 L H\({}_{2}\)O, so 36 L are occupied by solids in each cell of the reservoir rock. The gas consists of 10% residual gas (that was not extracted during natural gas production) and 90% stored hydrogen gas. The composition of the residual gas in the reservoir rock is based on data from [PERSON] and Gocht [45] with \(p\)CH\({}_{4(\mathrm{g})}\) = 3.56 atm, \(p\)N\({}_{2(\mathrm{g})}\) = 0.4 atm, and \(p\)CO\({}_{2(\mathrm{g})}\) = 0.04 atm. The stored hydrogen gas is composed of 96% H\({}_{2(\mathrm{g})}\) (\(p\)H\({}_{2(\mathrm{g})}\) = 34.56 atm) and 4% CO\({}_{2(\mathrm{g})}\) (\(p\)CO\({}_{2(\mathrm{g})}\) = 1.44 atm), these values are modified from data presented by [PERSON] [5]. For modeling purposes, the stored hydrogen gas is additionally induced as a tracer gas with the same chemical properties as H\({}_{2(\mathrm{g})}\). It is used instead of H\({}_{2(\mathrm{g})}\) because H\({}_{2(\mathrm{g}/\mathrm{a}0)}\) is induced and used as the reactant in the calculation kinetics. The amount of tracer gas corresponds to 4.3 mol L\({}^{-1}\) of gas in each cell of the reservoir. The summed volume of all gases in the reservoir rock is 3 L per cell and represents the stored gas volume at 40 atm under the assumed reservoir conditions. The sum of the partial pressure of all available gases (including tracer gas) is equivalent to the total pressure (40 atm) in the reservoir so that the generated gases (H\({}_{2}\)S\({}_{(\mathrm{g})}\), CH\({}_{4(\mathrm{g})}\)) are released as gas bubbles. Figure 1: Selected reactions and processes associated with bacterial sulfate reduction and methanogenesis (purple). Single arrow = kinetic-controlled reactions; double arrow = equilibrium reactions; blue triangles = time-dependent diffusive transport of aqueous components; bold = injected gas for storage. The cap rock (cells 1-182) is defined by an initial porosity of 5.0% (\(n\) = 0.05), with 1 L irreducible water and 19 L solid. The underlying rock (cells 851-1488) is defined by an initial porosity of 10% (\(n\) = 0.1), divided into 2.5% (\(n\) = 0.025) irreducible water, which is equal to 1 L H\({}_{2}\)O, and 7.5% (\(n\) = 0.075) gas. The porosity is filled with 3 L gas and 1 L H\({}_{2}\)O, so 36 L are occupied by solids in each cell of the underlying rock. The assumed natural gas composition in the underlying rock is \(p\)CH\({}_{4(\mathrm{g})}\) = 81.1 atm, \(p\)N\({}_{2(\mathrm{g})}\) = 4.3 atm, \(p\)H\({}_{2}\)S\({}_{(\mathrm{g})}\) = 10.7 atm, and \(p\)CO\({}_{2(\mathrm{g})}\) = 10.7 atm [45]. The initial brine compositions of the cap rock, reservoir rock, and underlying rock are pre-calculated in a separate transport model to simulate the million-years-long interaction of the different brines with each other.