Impact of large-scale hydrogen electrification and retrofitting of natural gas infrastructure on the European power system (2310.01250v2)

Abstract: In this paper, we aim to analyse the impact of hydrogen production decarbonisation and electrification scenarios on the infrastructure development, generation mix, $CO_{2}$ emissions, and system costs of the European power system, considering the retrofit of the natural gas infrastructure. We define a reference scenario for the European power system in 2050 and use scenario variants to obtain additional insights by breaking down the effects of different assumptions. The scenarios were analysed using the European electricity market model COMPETES, including a proposed formulation to consider retrofitting existing natural gas networks to transport hydrogen instead of methane. According to the results, 60% of the EU's hydrogen demand is electrified, and approximately 30% of the total electricity demand will be to cover that hydrogen demand. The primary source of this electricity would be non-polluting technologies. Moreover, hydrogen flexibility significantly increases variable renewable energy investment and production, and reduces $CO_{2}$ emissions. In contrast, relying on only electricity transmission increases costs and $CO_{2}$ emissions, emphasising the importance of investing in an $H_{2}$ network through retrofitting or new pipelines. In conclusion, this paper shows that electrifying hydrogen is necessary and cost-effective to achieve the EU's objective of reducing long-term emissions.

• The paper’s main contribution is the development of a novel LP formulation for retrofitting natural gas pipelines to transport hydrogen.
• It shows that strategic hydrogen electrification drives higher renewable investments and achieves a 35% reduction in CO₂ emissions.
• The study demonstrates that repurposing 11% of existing gas capacity meets 58% of EU hydrogen demand via electrolysis, optimizing system costs.

The paper "Impact of large-scale hydrogen electrification and retrofitting of natural gas infrastructure on the European power system" (Impact of large-scale hydrogen electrification and retrofitting of natural gas infrastructure on the European power system, 2023) analyzes the role of hydrogen (H₂) electrification and the repurposing of natural gas infrastructure in achieving the European Union's carbon neutrality goals by 2050.

Problem Addressed:

The European Union aims for carbon neutrality by 2050, relying heavily on the electrification of various sectors and the decarbonization of electricity generation. While direct electrification is viable for transport and residential heating, sectors like heavy industry and long-distance transport require alternative energy vectors such as green hydrogen. Existing energy system models often do not comprehensively analyze the combined impact of large-scale hydrogen production electrification, sector coupling, and the potential for retrofitting natural gas networks for hydrogen transport. Furthermore, existing models lack a linear programming (LP) formulation that effectively incorporates different levels of natural gas network retrofitting as an investment option, which is computationally challenging with traditional mixed-integer programming (MIP) approaches for large-scale systems.

Contribution:

The paper provides a detailed analysis of various large-scale electrification and hydrogen decarbonization scenarios for the EU power system in 2050 using the COMPETES optimization model. Its key contribution is the proposal and implementation of a novel LP mathematical formulation within COMPETES to model the retrofitting of existing natural gas networks for hydrogen transport at different capacity levels and associated costs. This allows for efficient optimization of hydrogen transport infrastructure investment decisions within a large-scale energy system model.

Methodology:

The paper uses the COMPETES model, an LP-based power system optimization and economic dispatch model covering EU Member States and selected non-EU countries. COMPETES solves a transmission and generation capacity expansion problem to minimize social costs while meeting electricity and hydrogen demand under techno-economic and policy constraints.

A reference scenario for 2050 (R2050) is defined based on input data regarding electricity and hydrogen demand, generation technologies, initial capacities, hourly profiles for demand and renewables, fuel and CO₂ prices, and policy targets (like the 50% limit on Steam Methane Reforming (SMR) based hydrogen production).

Four scenario variants are analyzed to isolate the impact of specific assumptions:

• NoP2H2: Electrolysis is not allowed (hydrogen mainly supplied by SMR).
• NoH2Storage: Investment in underground hydrogen storage is not allowed.
• NoH2Transmission: Investment in new or retrofitted hydrogen pipelines is not allowed (only electricity trade for energy transfer).
• NoETransmission: Investment in new electricity transmission is not allowed (only uses forecasted capacities).

The proposed LP formulation for retrofitting natural gas networks includes piecewise linear cost curves for increasing hydrogen transport capacity through different levels of compression ($\eta^1, \eta^2$), relating the retrofitted hydrogen capacity to the initial natural gas capacity ($\overline{P}_l^{CH4}$). The constraints ensure that retrofitting a pipeline for hydrogen reduces its capacity for natural gas. The investment decisions are linear variables ($\overline{p}_l^{1H2}, \overline{p}_l^{2H2}$) appearing in the objective function with their annualized CAPEX.

Key Findings and Results:

• Hydrogen Electrification: In the R2050 scenario, 58% of the total EU hydrogen demand in 2050 is met by electrolysis (Power-to-Hydrogen, P2H2), consuming nearly 28% of the total electricity demand. The remaining 42% is supplied by SMR, primarily SMR with 89% CO₂ capture (SMR CCS 89).
• Generation Mix Impact: Electrifying hydrogen demand leads to a significant increase in variable renewable energy (VRE) investment and production (48% higher capacity, 50% higher production in R2050 vs NoP2H2). Nuclear production also increases. These non-polluting sources cover the additional electricity demand for electrolysis and replace a substantial portion of gas-fired generation (nearly 70% reduction).
• Flexibility Role of Electrolyzers: Flexible electricity-based hydrogen production (electrolysis) significantly increases VRE production and reduces the need for peak units like gas-CCS power plants (capacity reduced by almost 90% in R2050 vs NoP2H2). Electrolyzers operate at lower full load hours (4900 FLH) compared to SMR (7500-8650 FLH), indicating their use during periods of low electricity prices.
• Transmission Needs: Despite higher total electricity demand, R2050 requires almost 45% lower new electricity transmission capacity compared to NoP2H2. This is because electrolyzers provide local flexibility, reducing the need for long-distance electricity trade to balance the system. Conversely, hydrogen transmission capacity is 1.6 times higher in R2050, facilitating hydrogen trade between countries with high VRE potential (producing hydrogen via electrolysis) and demand centers.
• Retrofitting Potential: The R2050 scenario shows that no new hydrogen pipelines are built; the required hydrogen transport is accommodated by retrofitting 11% of the total capacity of the existing natural gas infrastructure.
• CO₂ Emissions: Electrifying hydrogen production leads to a significant reduction in total system CO₂ emissions (35% lower in R2050 vs NoP2H2). This is driven by the shift from carbon-intensive SMR to electrolysis powered primarily by VRE and nuclear energy, and also by the replacement of gas-fired power generation with non-polluting sources enabled by electrolyzer flexibility.
• System Costs: The total system costs are similar between R2050 and NoP2H2 (R2050 is 0.4% lower), but there is a significant shift in cost components. R2050 has higher investments in P2H2 and VRE, offset by lower SMR and variable generation costs (fuel).
• Impact of Constraints (Scenario Variants):
  • NoH2Storage: Results in higher total system costs and CO₂ emissions compared to R2050, indicating the value of hydrogen storage for time-shifting production. Requires more hydrogen transmission capacity (using pipelines for storage).
  • NoH2Transmission: Leads to significantly higher costs (1.2% increase) and CO₂ emissions (20% increase) compared to R2050. This highlights the critical importance of hydrogen pipeline transport (retrofitting or new) for a cost-effective and low-carbon system. Requires higher electricity transmission investment and increased hydrogen storage.
  • NoETransmission: Results in slightly higher costs (0.3% increase) but similar CO₂ emissions compared to R2050. It suggests that the forecasted electricity transmission expansion by 2050 might be close to optimal, and focusing on hydrogen transport is more impactful for further cost and emission reductions.

Practical Implications and Conclusions:

The paper strongly suggests that widespread electrification of hydrogen production is a cost-effective and necessary strategy for the EU to meet its long-term emission reduction targets. Integrating flexible electrolysis allows for greater penetration of VRE in the power system and reduces reliance on fossil fuels for both electricity and hydrogen production.

The retrofitting of existing natural gas pipelines for hydrogen transport is identified as a viable and crucial solution. Investing in a hydrogen network, primarily through repurposing existing infrastructure, is shown to be more impactful in reducing overall system costs and CO₂ emissions than relying solely on further expanding the electricity transmission network beyond forecasted levels. Policymakers are encouraged to focus on facilitating hydrogen transport infrastructure development.

The LP formulation proposed for retrofit modeling allows for efficient analysis of this investment option in large-scale optimization models, demonstrating that complex infrastructure decisions can be effectively captured within linear frameworks for computational feasibility.

The findings provide a quantitative assessment to guide policy decisions regarding the optimal balance of investments in hydrogen production technologies, storage, and transmission infrastructure (both electricity and hydrogen) to achieve a decarbonized and cost-efficient European energy system by 2050.