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This paper presents a novel energy management strategy (EMS) to control a wind-hydrogen microgrid which includes a wind turbine paired with a hydrogen-based energy storage system (HESS), i.e., hydrogen production, storage and re-electrification facilities, and a local load. This complies with the mini-grid use case as per the IEA-HIA Task 24 Final Report, where three different use cases and configurations of wind farms paired with HESS are proposed in order to promote the integration of wind energy into the grid. Hydrogen production surpluses by wind generation are stored and used to provide a demand-side management solution for energy supply to the local and contractual loads, both in the grid-islanded and connected modes, with corresponding different control objectives. The EMS is based on a hierarchical model predictive control (MPC) in which long-term and short-term operations are addressed. The long-term operations are managed by a high-level MPC, in which power production by wind generation and load demand forecasts are considered in combination with day-ahead market participation. Accordingly, the hydrogen production and re-electrification are scheduled so as to jointly track the load demand, maximize the revenue through electricity market participation and minimize the HESS operating costs. Instead, the management of the short-term operations is entrusted to a low-level MPC, which compensates for any deviations of the actual conditions from the forecasts and refines the power production so as to address the real-time market participation and the short time-scale equipment dynamics and constraints. Both levels also take into account operation requirements and devices' operating ranges through appropriate constraints. The mathematical modeling relies on the mixed-logic dynamic (MLD) framework so that the various logic states and corresponding continuous dynamics of the HESS are considered. This results in a mixed-integer linear program which is solved numerically. The effectiveness of the controller is analyzed by simulations which are carried out using wind forecasts and spot prices of a wind farm in center-south of Italy. • Design of control algorithms for islanded and grid-connected microgrids. • Development of hierarchical MPCs to target long-term and short-term operations. • Tracking the load demand and maximizing the revenue via electricity markets. • Minimization of the HESS operational costs. [ABSTRACT FROM AUTHOR]

Hydrogen storage can help achieve climate change and reduce greenhouse gas emissions. This paper presents a first assessment of the suitability of northeastern Italy for underground hydrogen storage (UHS). The study focuses on the analysis of publicly available well data, which allowed identifying geological formations potentially suitable for UHS. The most promising area, known as the "Treviso Area" consists of both saline aquifers and depleted gas fields. One of the key petrophysical properties, i.e. porosity, was calculated for each of the five wells revealing conditions potentially suitable for UHS by applying empirical formulas to geophysical log data. For the two depleted gas fields, a hydrogen injection simulation was also performed. This work is a pioneer study and lays the foundation for hopeful further analyses, which could help implement the recently launched "North Adriatic Hydrogen Valley" initiative. [Display omitted] • A first assessment of underground hydrogen storage (UHS) in Italy is provided. • In NE Italy, saline aquifers and depleted gas fields are potentially suitable for UHS. • A key petrophysical property for UHS, porosity, is calculated from geophysical logs. • A simulation of hydrogen injection and production is provided. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

[Display omitted] • Solar H₂ system can supply up to 20% H₂ vol. fraction in natural gas pipeline. • Optimum H₂ production and storage system delivers 106 kilotonnes at 2.81 €/kg. • Battery size in liquid H₂ system is 12 times larger than in gaseous H₂ system. • Storing H₂ in gaseous form results in 3 times larger volume than in liquid form. • Liquid H₂ system requires larger PV arrays & electrolyser than in gaseous H₂ system. This paper presents the results of techno-economic modelling for hydrogen production from a photovoltaic battery electrolyser system (PBES) for injection into a natural gas transmission line. Mellitah in Libya, connected to Gela in Italy by the Greenstream subsea gas transmission line, is selected as the location for a case study. The PBES includes photovoltaic (PV) arrays, battery, electrolyser, hydrogen compressor, and large-scale hydrogen storage to maintain constant hydrogen volume fraction in the pipeline. Two PBES configurations with different large-scale storage methods are evaluated: PBES C with compressed hydrogen stored in buried pipes, and PBES L with liquefied hydrogen stored in spherical tanks. Simulated hourly PV electricity generation is used to calculate the specific hourly capacity factor of a hypothetical PV array in Mellitah. This capacity factor is then used with different PV sizes for sizing the PBES. The levelised cost of delivered hydrogen (LCOH D) is used as the key techno-economic parameter to optimise the size of the PBES by equipment sizing. The costs of all equipment, except the PV array and batteries, are made to be a function of electrolyser size. The equipment sizes are deemed optimal if PBES meets hydrogen demand at the minimum LCOH D. The techno-economic performance of the PBES is evaluated for four scenarios of fixed and constant hydrogen volume fraction targets in the pipeline: 5%, 10%, 15%, and 20%. The PBES can produce up to 106 kilotonnes of hydrogen per year to meet the 20% target at an LCOH D of 3.69 €/kg for compressed hydrogen storage (PBES C) and 2.81 €/kg for liquid hydrogen storage (PBES L). Storing liquid hydrogen at large-scale is significantly cheaper than gaseous hydrogen, even with the inclusion of a significantly larger PV array that is required to supply additional electrcitiy for liquefaction. [ABSTRACT FROM AUTHOR]

Abstract: Energy conversion from hydrogen represents a viable contribution to sustainable development. For this reason several authors have investigated clean hydrogen production and its end uses. One end use is a hydrogen storage system with a fuel cell to mitigate grid instabilities inherent to renewable power generation or intermittent reactive loads. Another end use is burning hydrogen in internal combustion engines for motive transport or remote power generation. Blending hydrogen with traditional hydrocarbon fuels is also possible. The aim of this paper is to assess the opportunity for realizing a small-scale renewable hydro methane production system in Italy. The system is completely integrated in an electrical and thermal smart grid. For this reason, a techno-economic feasibility analysis on hybrid systems was carried out to quantify the carbon avoidance cost associated with blended hydrogen fuels. Twelve different scenarios were simulated with the HOMER software and the optimal system configuration was identified by applying the levelized cost of hydrogen (LCOH) as evaluation criterion. Furthermore, a sensitivity analysis was applied to explore potential fiscal policy scenarios. The simulation results show that the lowest LCOH (8.041 €/kg) was achieved with a 5 Nm3 electrolyser capability (operating for about 4000 h/yr) and a grid connected 160 kWp PV array when hydrogen was produced only during the winter season. Instead considering the same operating hours and modifying the hydrogen production daily and monthly profile (i.e. hydrogen production from May to September) the best results were obtained (LCOH = 0 €/kg). An analysis of carbon avoidance costs showed the optimal hydrogen mixture of approximately 23% by volume to provide the best economic and environmental trade-off. Finally, if the hydrogen cost is equal to 1.5587 €/kg a null over price for decarbonisation is achievable. To obtain this result a dedicated incentive scheme to encourage the hydrogen production should be developed by Italian Government. [Copyright &y& Elsevier]