Abstract

Hydrogen blending into natural gas grids can support early renewable hydrogen deployment, but admissible injection depends on local gas flow, blending limits, and upstream hydrogen concentrations. This paper analyses these effects for a regional high-pressure gas-grid section in Styria, Austria, with two hydrogen injection points. A transient gas-network model derives time- and location-dependent injection limits, which are integrated into an electrolyser dispatch optimisation with fixed trailer demand and annual gas-grid injection demand. Three cases are compared: unrestricted injection, a “CH4-based” limit without upstream hydrogen, and an “H2-aware” case representing potential upstream hydrogen injection. For the analysed configuration, blending constraints shift operation away from favourable electricity-price periods, particularly when low prices coincide with reduced gas demand. In the 2025 reference case, the “H2-aware” constraint increases the electricity-cost contribution from 4.22 to 5.45 EUR/kgH2. A robustness analysis using electricity-price series for 2020, 2022, and 2025 shows that the “H2-aware” constraint increases the electricity-cost contribution by 15.8–29.1% relative to unrestricted injection. The results demonstrate that dynamic gas-grid constraints should be considered when assessing blending-based electrolyser projects, while the quantitative findings remain specific to the analysed network and assumptions.

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