Benefits from Islanding Green Hydrogen Production

Abstract: In wind- and solar-dominated energy systems it has been assumed that there are synergies between producing electricity and electrolytic hydrogen since electrolysis can use excess electricity that would otherwise be curtailed. However, it remains unclear whether these synergies hold true at higher levels of hydrogen demand and how they compare with benefits of off-grid, islanded hydrogen production, such as better renewable resources and cost savings on electronics due to relaxed power quality standards. Using a mathematical model across two geographical locations for Germany, Spain, Australia, and Great Britain, we explore trade-offs and synergies between integrated and islanded electrolysers. Below a certain threshold, between 5% and 40% hydrogen share depending on the country, integrated electrolysers offer synergies in flexibility and reduced curtailment. Above these thresholds, islanded electrolysers become more favourable. Without cost advantages, systems including islanded electrolysers in Germany achieve up to 21% lower hydrogen costs than systems with only integrated electrolysers. With 25% island cost advantage, this benefit rises to 40% lower hydrogen costs. Our study identifies three investment regimes with country-specific transition points that vary based on island cost advantages and each country's renewable resources. Based on our results we provide guidelines for countries considering how to deploy electrolysers.

• The paper quantifies the cost trade-offs between grid-integrated and islanded electrolyzer strategies for green hydrogen production.
• It employs a streamlined optimization model to assess investment regimes and hourly dispatch across varied hydrogen demand scenarios.
• Results indicate that modest capital cost reductions in islanded systems can shift optimal deployment to cost-effective, island-focused production.

This paper investigates the trade-offs and potential benefits of producing green hydrogen using electrolyzers integrated into the main electricity grid versus using electrolyzers located in "islanded" systems powered solely by dedicated renewable resources. The core question addressed is how the optimal deployment strategy for electrolyzers changes depending on the overall demand for hydrogen and potential cost advantages for islanded systems.

The authors employ a streamlined mathematical optimization model using the PyPSA toolbox (2310.12606). This model performs greenfield capacity expansion and hourly dispatch to minimize the annual cost of an energy system based on wind and solar power, electrolyzers, storage (batteries and hydrogen caverns), and green-fuel dispatchable plants. The model represents each of four countries (Germany, Spain, Great Britain, and Australia) with two geographical locations: a mainland connected to an electricity and hydrogen grid, and an island connected only to a hydrogen pipeline exporting to the mainland. Country selection was based on different dominant renewable resources and island distances/resources.

The study explores three scenarios for electrolyzer deployment:

1. Integration: Electrolyzers can only be built on the mainland grid.
2. Island: Electrolyzers can only be built on the island.
3. Optimisation: Electrolyzers can be built on both the mainland and the island.

These scenarios are run across a sweep of hydrogen shares in final energy demand (from 0% to 100%) and with varying levels of capital cost advantages (0% to 25%) applied to power electronics components (wind/solar inverters, electrolyzer power electronics, battery inverters) in the islanded system.

Key Findings and Practical Implications:

The study identifies three characteristic investment regimes for electrolyzer deployment based on the optimal solutions from the Optimisation scenario:

1. Integration Regime: In this regime, the optimal strategy is to deploy only integrated electrolyzers on the mainland. This is typically cost-optimal at low hydrogen demand shares. The benefit here is the utilization of previously curtailed renewable electricity, providing synergy with the electricity grid. However, integrated electrolyzers cannot eliminate all curtailment, and their capacity factor is limited by the availability of low-cost electricity. This regime is prevalent in the UK and Australia across most or all hydrogen demand shares tested (without cost advantages), and at low hydrogen shares in Spain and Germany.
2. Hybrid Regime: As hydrogen demand increases, some countries (like Germany) transition into this regime where it is cost-optimal to deploy both integrated and islanded electrolyzers. This regime benefits from the "Portfolio Benefit." This benefit arises from synergies between the renewable resource profiles on the mainland and the island. Deploying electrolyzers in both locations allows for a more balanced hydrogen production schedule throughout the year, reducing the need for large hydrogen storage capacity and potentially increasing the average capacity factor of the entire electrolyzer fleet compared to only integrated deployment.
3. Island Regime: At higher hydrogen demand shares, some countries (like Spain) transition into this regime where it is cost-optimal to deploy only additional islanded electrolyzers. Integrated electrolyzers deployed in earlier stages remain, but all new capacity is on the island. This regime is driven by the "Superiority Benefit," where the island location has superior renewable resources (higher capacity factors) compared to the mainland for dedicated hydrogen production, making islanded production cheaper despite pipeline costs.

Impact of Capital Cost Advantages:

A crucial finding is that potential capital cost reductions for components in islanded systems significantly influence these regimes (2310.12606). These cost reductions (e.g., due to relaxed power quality standards or simplified DC systems on the island) make islanded hydrogen production more competitive. Even modest cost advantages (e.g., 5%) can introduce or shift the transition points between regimes, making the Hybrid or Island regime optimal at lower hydrogen demand levels. With higher cost advantages (e.g., 25%), the benefits from islanding (both Portfolio and Superiority Benefits) become substantial, leading to significantly lower overall hydrogen costs in the Optimisation scenario compared to the Integration scenario. For example, with a 25% cost advantage, the island becomes the superior resource location for all countries studied, leading to significantly lower hydrogen costs compared to an integrated-only approach.

Implementation and Application Guidelines:

The results provide practical guidance for policymakers and system planners:

• Initial Stage (Low H2 Demand): Most countries should initially focus on integrated electrolyzers to leverage existing grid infrastructure and utilize excess renewable electricity.
• Scaling Up (Increasing H2 Demand): As hydrogen demand grows, evaluate the potential for islanded production. This decision point (Competitiveness Point) depends heavily on the quality of renewable resources at potential island locations relative to the mainland and the potential for capital cost reductions in islanded systems.
• Dominant Islanding (High H2 Demand): If island resources are superior or significant cost advantages exist for islanded systems, the optimal strategy might shift to deploying the bulk of new electrolyzer capacity on islands (Winout Point), limiting further expansion of integrated electrolyzers.
• Resource Quality and Cost Advantages: The "superiority" of an island location can come either from inherently better renewable resources or from cost advantages that effectively lower the levelized cost of energy and hydrogen production on the island. Both factors push towards earlier adoption of islanded production.
• Policy and Regulation: Regulatory frameworks are needed to certify "green" hydrogen from integrated systems, especially since real-world grids may not be 100% renewable initially. Incentives should be designed to guide private investment towards the cost-optimal deployment mix identified by such analyses.
• Technology Development: Continued focus on reducing costs of power electronics in islanded systems, potentially through simplified architectures or direct DC coupling of renewables and electrolyzers, can significantly enhance the competitiveness of islanded production.

Limitations:

The study uses a simplified model with two locations per country, constant demand profiles, and no detailed transmission networks. It focuses on a future system dominated by wind and solar (year 2050 projections) and does not evaluate short-term transitions from fossil fuel systems. While the results provide strategic long-term guidance, more detailed geographically-resolved models (like PyPSA-Eur) would be needed for precise planning and deployment in specific regions.

In summary, the paper demonstrates that while integrated electrolysis is beneficial for low hydrogen demand by utilizing curtailed electricity, islanded production becomes increasingly attractive and potentially cost-optimal at higher demand levels, particularly if island locations have superior renewable resources or can achieve significant capital cost reductions for balance-of-plant components (2310.12606). Understanding the transition points between the Integration, Hybrid, and Island regimes is crucial for developing cost-effective national hydrogen strategies.