Techno-economic analysis of Power-to-Gas plants in a gas and electricity distribution network system with high renewable energy penetration (2111.11790v1)

Abstract: Distributed generation, based on the exploitation of Renewable Energy Sources (RES), has increased in the last few decades to limit anthropogenic carbon dioxide emissions, and this trend will increase in the future. However, RES generation is not dispatchable, and an increasing share of RES may lead to inefficiencies and even problems for the electricity network. Flexible resources are needed to handle RES generation in order to support the delicate electricity generation and demand balance. Energy conversion technologies (P2X, Power to X) allow the flexibility of energy systems to be increased. These technologies make a connection between different energy sectors (e.g., electricity and gas) possible, and thus create new synergies within an overall multi energy system. This paper analyzes how the P2G technology can be used at the distribution network level (both gas and electricity) to optimize the use of RES. In fact, in order to coordinate P2X resources, it is necessary to take into account the whole multi energy scenario, and not just the electrical side: it therefore becomes fundamental to recognize the pros and cons that Balancing Service Providers (BSPs), composed of a number of P2G plants (representing the Balancing Responsible Providers, BRPs), may have when offering services to an electricity network. Moreover, the convenience of the decarbonization of the gas grid has been evaluated through the calculation of the levelized cost of Synthetic Natural Gas (LCSNG) for cost scenarios for the years 2030 and 2050, considering different assumptions about the cost of the surplus utilization of RES. The results show that LCSNG may vary from 47 to 319 EURO/MWh, according to the different configurations, i.e., only in the best case scenario is the SNG cost comparable with the cost of natural gas, and hence does the P2G technology result to be profitable

• The paper demonstrates that P2G plants can absorb 80-85% of surplus renewable energy, mitigating reverse power flow in coupled electricity and gas distribution networks.
• It employs integrated dynamic models and a centralized control strategy to optimize PEM electrolyzer and methanation operations under gas network constraints.
• Economic analysis reveals that synthetic natural gas costs are highly sensitive to surplus electricity prices, with significant benefits from by-product valorization.

This paper (2111.11790) investigates the techno-economic feasibility and operational challenges of integrating Power-to-Gas (P2G) plants, specifically Power-to-Methane (P2M) producing Synthetic Natural Gas (SNG), into coupled electricity and gas distribution networks with high penetration of intermittent Renewable Energy Sources (RES). The core problem addressed is how to manage surplus RES generation, which can lead to issues like Reverse Power Flow (RPF) in electricity distribution networks, by converting it into SNG and injecting it into the gas grid, while considering the operational constraints of both networks.

The paper develops a simulation model of an urban multi-energy system comprising an electricity distribution network (EN), a medium-pressure gas distribution network (GN), and three distributed P2G plants. Each P2G plant consists of a 1200 kW PEM electrolyzer, a hydrogen buffer, and a 600 kW catalytic methanation unit. The plants are strategically connected to the EN downstream of different HV/MV transformers to absorb localized RPF and are distributed across the GN. The scenario is characterized by high RES penetration, particularly concentrated in one part of the network, and a highly seasonal gas demand (high in winter for heating, low in summer). The simulation covers one year with a 15-minute time resolution.

Key Modeling and Implementation Aspects:

• Network Models: The electricity network is modeled using a Backward Forward Sweep method. The gas network uses a dynamic model based on the Renouard equation to simulate pressure and flow evolution, incorporating constraints like maximum pressure limits and a unidirectional connection to the high-pressure transmission network (citygate). The gas network model includes a simplified calculation of the maximum SNG injection capacity at each timestep based on withdrawals and linepack (network storage capacity).
• P2G Plant Models: Simplified, lumped models represent the PEM electrolyzer (linear efficiency) and methanation unit (surrogate model derived from high-fidelity simulations). A hydrogen buffer model tracks storage and pressure. Key dynamic constraints for the methanation unit, such as minimum load (50%) and ramp rates (though electrolyzer ramp is neglected due to the 15-minute timestep), are included.
• Control Strategy: A crucial practical contribution is the proposed control algorithm for the P2G plants operating under a central coordinator (BSP).
  • Electrolyzer Control: The electrolyzer of a specific P2G plant is activated when RPF occurs downstream of its connected transformer. Its power consumption setpoint is determined by the magnitude of the RPF, the plant's nominal capacity, and the hydrogen buffer's capacity limit (Fig. 6). It operates at minimum load otherwise.
  • Methanation Unit Control: The methanation unit is activated when the hydrogen buffer reaches a sufficient state of charge (15 bar). Its operation is constrained by its own minimum load and ramp rates, but critically, also by the gas network's ability to accept SNG injection (its 'host capacity'), which depends on overall gas demand and network pressure (Fig. 7).
  • Coordination under GN Constraints: When the GN injection capacity is limited, the control strategy prioritizes methanation units already running and, if curtailment is needed, prioritizes units with lower hydrogen buffer levels. If more injection capacity becomes available and multiple units are in standby, units with higher buffer levels are prioritized to maximize continuous operation and electrolyzer availability. This highlights the necessity of coordinating distributed P2G assets when a shared resource (the gas network) becomes a bottleneck.

Techno-Economic Analysis:

The economic analysis calculates the Levelized Cost of SNG (LCSNG) using a formula (Eq. 1) that includes CAPEX (electrolyzer, buffer, methanation), fixed OPEX, variable costs (electricity, CO₂, PEM stack replacement), revenues from by-products (oxygen, heat), and a Weighted Average Cost of Capital (WACC). Two economic scenarios (2030, 2050 with reduced CAPEX) and varying RES surplus electricity prices (0 to 30 €/MWh) are considered.

Key Findings and Practical Implications:

1. RES Surplus Absorption: P2G plants are effective at absorbing a significant portion (~80-85%) of RES over-generation and mitigating RPF, especially in winter when gas demand is high.
2. Gas Network as Storage: In periods of low gas demand (summer), SNG production can exceed immediate consumption. The gas distribution network can utilize its linepack effect to provide intraday storage, absorbing SNG and increasing pressure within limits (Fig. 11b). This flexibility allows methanation units to operate more constantly (Fig. 11a, Fig. 12a) even when demand is low, facilitated by the hydrogen buffer (Fig. 12b). However, the medium-pressure distribution network's volume is insufficient for seasonal storage.
3. GN Constraints: Low gas demand periods are critical. When the gas network reaches its maximum pressure limit, SNG injection must be curtailed. This necessitates coordinated operation of multiple P2G plants sharing the same GN sink, as outlined in the control strategy.
4. Economic Viability:
   • LCSNG varies widely (49 to 319 €/MWh) depending on economic assumptions, plant utilization, and surplus electricity price (Table 9).
   • Utilization is Key: Plants connected to areas with higher RES over-production (like P2G#3 in this paper) have significantly lower LCSNG due to higher operating hours and SNG production. Optimal placement is crucial.
   • Electricity Cost Dominance: The cost of surplus electricity is a major factor in LCSNG. Even with future cost reductions (2050 scenario), LCSNG remains high, especially if electricity cost is not near zero. Incentives for using surplus RES energy are likely needed for SNG to compete with natural gas (2020 average NG price was 35 €/MWh [52]).
   • By-product Valorization: Revenues from selling oxygen and waste heat significantly reduce LCSNG (by ~30 €/MWh or ~15% on average, up to 36%), highlighting the importance of finding markets for these by-products (Fig. 14).
5. Decoupling via H₂ Buffer: The hydrogen buffer provides essential operational decoupling between the electrolyzer (driven by electricity availability/RPF) and the methanation unit (driven by hydrogen availability and GN capacity). This allows the electrolyzer to absorb intermittent RES surplus even when SNG injection is temporarily constrained by the gas network.

Implementation Considerations:

• Integrated Modeling & Simulation: Developing accurate dynamic models for coupled electricity and gas distribution networks, along with P2G plants and their controls, is computationally intensive but necessary for feasibility studies and operational planning. Software platforms capable of multi-energy system simulation (like the mentioned Simulink environment or specialized energy system modeling tools) are required.
• Control System Development: Implementing the coordinated control logic requires a system that receives real-time or near-real-time data on electricity network conditions (especially RPF), gas network conditions (pressure, demand, available injection capacity), P2G plant status (buffer level, operational state), and potentially market signals (electricity price, ancillary service needs). This could involve a central BSP control platform or decentralized, coordinated controllers at each P2G site.
• Data Infrastructure: Reliable monitoring of electrical parameters, gas flows and pressures, and P2G plant operational data is essential. Communication infrastructure between P2G plants, DSOs (electricity and gas), and the BSP is needed for coordination.
• Economic Justification: Real-world deployment heavily relies on economic viability. This requires securing low-cost or subsidized surplus electricity, identifying reliable revenue streams for SNG and by-products (O₂, heat), and potentially benefiting from grid services (like RPF mitigation). Policy and market design that value the flexibility and decarbonization benefits of P2G are critical.
• Network Operator Coordination: Successful integration requires coordination between the electricity Distribution System Operator (DSO) and the gas DSO, potentially involving a multi-energy system operator or BSP that interfaces with both.
• Scalability: The paper uses 1.2 MW electrolyzers, suggesting potential for distributed P2G at the distribution level. Scaling up would require larger plants or aggregating many small units, impacting network connection requirements and coordination complexity.

In summary, the paper demonstrates that P2G can be a valuable tool for integrating high levels of RES in distribution networks by providing flexibility and converting electrical surplus into storable gas. However, its technical operation is constrained by the gas network's capacity, particularly during low demand periods, necessitating sophisticated control strategies. Economic viability remains challenging compared to natural gas and heavily depends on the cost of surplus electricity, plant utilization (location), and valorization of by-products. Future work needs to refine these integrated models and explore different P2X technologies and multi-energy system interactions.