Italy

The production of “green hydrogen” is currently one of the hottest topics in the field of renewable energy systems research. Hydrogen storage is also becoming more and more attractive as a flexible solution to mitigate the power fluctuations of solar energy systems. The most promising technology for electricity-to-hydrogen conversion and vice versa is the reversible solid-oxide cell (SOC). This device is still very expensive but it exhibits excellent performance under dynamic operating conditions compared to the competing devices. This work presents the dynamic simulation of a prototypal renewable plant combining a 50 kW photovoltaic (PV) field with a 50 kW solid-oxide electrolyzer cell (SOEC) and a compressed hydrogen tank. The electricity is used to meet the energy demand of a dwelling located in the area of Campi Flegrei (Naples). The SOC efficiency is simulated by developing a mathematical model in MATLAB®. The model also calculates the cell operating temperature as a function of the input current. Once the optimal values of the operating parameters of the SOC are calculated the model is integrated in the transient system simulation tool (TRNSYS) for dynamic analysis. Furthermore this work presents a parametric analysis of the hydrogen storage system (HSS). The results of the energy and environmental analyses show that the proposed system can reach a primary energy saving by 70% and an amount of saved CO2 of 28 tons/year. Some possible future market scenarios are considered for the economic analysis. In the most realistic case the optimal configuration shows a simple pay back lower than 10 years and a profit index of 46%.

This study seeks to answer a simple question: will we have enough renewable electricity to meet all of the EU's decarbonisation objectives and if not what should be the priorities and how to address the remaining needs for energy towards carbon neutrality? Indeed if not the policy push for green hydrogen would not be covered by enough green electricity to match the “energy efficiency and electrification first” approach outlined in the system integration communication and a prioritization of green electricity uses complemented by other solutions (import of green electricity or sustainable fuels CCS...) would be advisable [1]. On one hand we show that the principle “Energy efficiency and electrification first” results in an electricity demand which will be very difficult to satisfy domestically with renewable energy. On the other hand green hydrogen and other sustainable fuels will be needed for a carbon neutral industry for the replacement of the fuel for aviation and navigation and as strategic green energy reserves. The detailed modelling of these interactions is challenging given the large uncertainties on technology and infrastructure development. Therefore we offer a “15 minutes” decarbonization scenario based on general and transparent technical considerations and very straightforward “back-of-envelope” calculations. This working paper contains the calculations and assumptions in support of the accompanying policy brief with the same title which focuses instead on the main take-aways.

Alternative fuel policies need accurate and transparent methods to find the embedded carbon intensity of individual refinery products. This study investigates different ways of allocating greenhouse gases emissions deriving from refining and upstream crude oil supply. Allocation methods based on mass energy content economic value and innovatively added-value are compared with the marginal refining emissions calculated by CONCAWE’s linear-programming model to the average EU refinery which has been adopted as reference in EU legislation. Beside the most important transportation fuels (gasoline diesel kerosene/jet fuel and heavy fuel oil) the analysis extends to petroleum coke and refinery hydrogen. Moreover novel criteria based on the implications due to hydrogen usage by each fuel pathway have been introduced to test the consistency of the analyzed approaches. It is found that only two economic-based allocation methods are consistent with the introduced criteria. These two methods also give negative refinery emissions for heavy products which is coherent with the marginal emissions calculated through the CONCAWE refinery model. The recommended allocation methods are transparent and use only publicly available statistical data so they may be useful not only for future EU legislation but also in jurisdictions where a representative refinery model is not available.

The effects of climate change and global warming are arising a new awareness on the impact of our daily life. Power generation for transportation and mobility as well as in industry is the main responsible for the greenhouse gas emissions. Indeed currently 80% of the energy is still produced by combustion of fossil fuels; thus great efforts need to be spent to make combustion greener and safer than in the past. For this reason a review of the most recent gas turbines combustion strategy with a focus on fuels combustion techniques and burners is presented here. A new generation of fuels for gas turbines are currently under investigation by the academic community with a specific concern about production and storage. Among them biofuels represent a trustworthy and valuable solution in the next decades during the transition to zero carbon fuels (e.g. hydrogen and ammonia). Promising combustion techniques explored in the past and then abandoned due to their technological complexity are now receiving renewed attention (e.g. MILD PVC) thanks to their effectiveness in improving the efficiency and reducing emissions of standard gas turbine cycles. Finally many advances are illustrated in terms of new burners developed for both aviation and power generation. This overview points out promising solutions for the next generation combustion and opens the way to a fast transition toward zero emissions power generation.

Power to substitute natural gas (PtSNG) is a promising technology to store intermittent renewable electricity as synthetic fuel. Power surplus on the electric grid is converted to hydrogen via water electrolysis and then to SNG via CO2 methanation. The SNG produced can be directly injected into the natural gas infrastructure for long-term and large-scale energy storage. Because of the fluctuating behaviour of the input energy source the overall annual plant efficiency and SNG production are affected by the plant operation time and the standby strategy chosen. The re-use of internal (waste) heat for satisfying the energy requirements during critical moments can be crucial to achieving high annual efficiencies. In this study the heat recovery from a PtSNG plant coupled with wind energy based on proton exchange membrane electrolysis adiabatic fixed bed methanation and membrane technology for SNG upgrading is investigated. The proposed thermal recovery strategy involves the waste heat available from the methanation unit during the operation hours being accumulated by means of a two-tanks diathermic oil circuit. The stored heat is used to compensate for the heat losses of methanation reactors during the hot-standby state. Two options to maintain the reactors at operating temperature have been assessed. The first requires that the diathermic oil transfers heat to a hydrogen stream which is used to flush the reactors in order to guarantee the hot-standby conditions. The second option entails that the stored heat being recovered for electricity production through an Organic Rankine Cycle. The electricity produced is used to compensate the reactors heat losses by using electrical trace heating during the hot-standby hours as well as to supply energy to ancillary equipment. The aim of the paper is to evaluate the technical feasibility of the proposed heat recovery strategies and how they impact on the annual plant performances. The results showed that the annual efficiencies on an LHV basis were found to be 44.0% and 44.3% for the thermal storage and electrical storage configurations respectively.

The deployment of low-carbon hydrogen in gas grids comes with strategic benefits in terms of energy system integration and decarbonization. However hydrogen thermophysical properties substantially differ from natural gas and pose concerns of technical and regulatory nature. The present study investigates the blending of hydrogen into distribution gas networks focusing on the steady-state fluid dynamic response of the grids and gas quality compliance issues at increasing hydrogen admixture levels. Two blending strategies are analyzed the first of which involves the supply of NG–H2 blends at the city gate while the latter addresses the injection of pure hydrogen in internal grid locations. In contrast with traditional case-specific analyses results are derived from simulations executed over a large number (i.e. one thousand) of synthetic models of gas networks. The responses of the grids are therefore analyzed in a statistical fashion. The results highlight that lower probabilities of violating fluid dynamic and quality restrictions are obtained when hydrogen injection occurs close to or in correspondence with the system city gate. When pure hydrogen is injected in internal grid locations even very low volumes (1% vol of the total) may determine gas quality violations while fluid dynamic issues arise only in rare cases of significant hydrogen injection volumes (30% vol of the total).

This paper deals with two main issues regarding the specific energy consumption in an electrolyzer (i.e. the Faraday efficiency and the converter topology). The first aspect is addressed using a multistack configuration of proton exchange membrane (PEM) electrolyzers supplied by a wind turbine conversion system (WTCS). This approach is based on the modeling of the wind turbine and the electrolyzers. The WTCS and the electrolyzers are interfaced through a stacked interleaved DC–DC buck converter (SIBC) due to its benefits for this application in terms of the output current ripple and reliability. This converter is controlled so that it can offer dynamic behavior that is faster than the wind turbine avoiding overvoltage during transients which could damage the PEM electrolyzers. The SIBC is designed to be connected in array configuration (i.e. parallel architecture) so that each converter operates at its maximum efficiency. To assess the performance of the power management strategy experimental tests were carried out. The reported results demonstrate the correct behavior of the system during transient operation.

Blending hydrogen into the natural gas infrastructure is becoming a very promising practice to increase the exploitation of renewable energy sources which can be used to produce “green” hydrogen. Several research projects and field experiments are currently aimed at evaluating the risks associated with utilization of the gas blend in end-use devices such as the gas meters. In this paper the authors present the results of experiments aimed at assessing the effect of hydrogen injection in terms of the durability of domestic gas meters. To this end 105 gas meters of different measurement capabilities and manufacturers both brand-new and withdrawn from service were investigated in terms of accuracy drift after durability cycles of 5000 and 10000 h with H2NG mixtures and H2 concentrations of 10% and 15%. The obtained results show that there is no metrologically significant or statistically significant influence of hydrogen content on changes in gas meter indication errors after subjecting the meters to durability testing with a maximum of 15% H2 content over 10000 h. A metrologically significant influence of the long-term operation of the gas meters was confirmed but it should not be made dependent on the hydrogen content in the gas. No safety problems related to the loss of external tightness were observed for either the new or 10-year-old gas meters.

The feasibility and cost-effectiveness of hydrogen-based microgrids in facilities such as public buildings and small- and medium-sized enterprises provided by photovoltaic (PV) plants and characterized by low electric demand during weekends were investigated in this paper. Starting from the experience of the microgrid being built at the Renewable Energy Facility of Sardegna Ricerche (Italy) which among various energy production and storage systems includes a hydrogen storage system a modeling of the hydrogen-based microgrid was developed. The model was used to analyze the expected performance of the microgrid considering different load profiles and equipment sizes. Finally the microgrid cost-effectiveness was evaluated using a preliminary economic analysis. The results demonstrate that an effective design can be achieved with a PV system sized for an annual energy production 20% higher than the annual energy requested by the user and a hydrogen generator size 60% of the PV nominal power size. This configuration leads to a self-sufficiency rate of about 80% and without public grants a levelized cost of energy comparable with the cost of electricity in Italy can be achieved with a reduction of at least 25–40% of the current initial costs charged for the whole plant depending on the load profile shape.

Blending hydrogen (H2) produced from PEM electrolysis coupled to Renewable Energy Sources (RES) in the existing Natural Gas (NG) network is a promising option for the deep decarbonization of the gas sector. However blending H2 with NG significantly affects the thermophysical properties of the gas mixture changing the gas supply requirements to meet the demand. In this work different scenarios of green hydrogen blending (Blend Ratio BR equal to 5/10/15/20%vol) are analyzed at the national level with different temporal constraints (hour/day/week/month/year) based on real gas demand data in Italy addressing both design requirements (RES and PEM electrolyzer capacity) via Linear Programming (LP) and carrying out dynamic simulations of different operational strategies (constant or variable blend). Although H2/NG blending provides a huge opportunity in terms of deployed H2 volume higher BRs show rapidly increasing design requirements (1.3-1.5 GWe/%vol and 2.5-3 GWe/%vol for PEM electrolyzers and RES capacity respectively) and a significative increase of the total gas mixture volume (0.83 %/%vol) which hinders the CO2 reduction potential (0.37 %/%vol). A variable blend operation strategy (allowing a variation of BR within the analyzed period) allows to balance a variable H2 production from RES. Wider temporal constraints imply several beneficial effects such as relaxing design constraints and avoiding the implementation of an external storage. The Levelized Cost Of Hydrogen (LCOH) is preliminarily estimated at around 7.3 $/kg for yearly scenarios (best-case) although shorter temporal constraints entail significant excess hydrogen which would increase the LCOH if not deployed for other applications.