Island energy systems are becoming an important part of energy transformation due to the growing needs for the penetration of renewable energy. Among the possible systems, a combination of different energy generation technologies is a viable option for local users, as long as energy storage is implemented. The presented paper describes an energy-economic assessment of an island system with a photovoltaic field, small wind turbine, wood chip gasifier, battery, and hydrogen circuit with electrolyzer and fuel cell. The system is designed to satisfy the electrical energy demand of a tourist facility in two European localizations. The operation of the system is developed and dynamically simulated in the Transient System Simulation (TRNSYS) environment, taking into account realistic user demand. The results show that in Gdansk, Poland, it is possible to satisfy 99% of user demand with renewable energy sources with excess energy equal to 31%, while in Agkistro, Greece, a similar result is possible with 43% of excess energy. Despite the high initial costs, it is possible to obtain Simple Pay Back periods of 12.5 and 22.5 years for Gdansk and Agkistro, respectively. This result points out that under a high share of renewables in the energy demand of the user, the profitability of the system is highly affected by the local cost of energy vectors. The achieved results show that the system is robust in providing energy to the users and that future development may lead to an operation based fully on renewables.

For lignite intense regions such as the case of Western Macedonia (WM), the production and utilization of green hydrogen is one of the most viable ways to achieve near zero emissions in sectors like transport, chemicals, heat and energy production, synthetic fuels, etc. However, the implementation of each technology that is available to a respective sector differs significantly in terms of readiness and the current installation scale of each technology. The goal of this study is the provision of a transition roadmap for a decarbonized future for the WM region through utilizing green hydrogen. The technologies which can take part in this transition are presented, along with the implementation purpose of each technology, and the reasonable extension that each technology could be adopted in the present context. The WM region’s limited capacity for green hydrogen production leads to certain integration scenarios, with regards to the required hydrogen, electrolyzer capacities, and required power, whereas an environmental assessment is also presented for each scenario.

While community energy initiatives and pilot projects have demonstrated technical feasibility and economic benefits, their site-specific nature limits transferability to systematic, scalable investment models. This study addresses this gap by proposing a modular framework for Renewable Energy Valleys (REVs), developed from real-world Community Energy Lab (CEL) demonstrations in Crete, Greece, which is an island with pronounced seasonal demand fluctuation, strong renewable potential, and ongoing hydrogen valley initiatives. Four modular business schemes are defined, each representing different sectoral contexts by combining a baseline of 50 residential units with one representative large consumer (hotel, rural households with thermal loads, municipal swimming pool, or hydrogen bus). For each scheme, a mixed-integer linear programming model is applied to optimally size and operate integrated solar PV, wind, battery (BAT) energy storage, and hydrogen systems across three renewable energy penetration (REP) targets: 90%, 95%, and 99.9%. The framework incorporates stochastic demand modeling, sector coupling, and hierarchical dispatch schemes. Results highlight optimal technology configurations that minimize dependency on external sources and curtailment while enhancing reliability and sustainability under Mediterranean conditions. Results demonstrate significant variation in optimal configurations across sectors and targets, with PV capacity ranging from 217 kW to 2840 kW, battery storage from 624 kWh to 2822 kWh, and hydrogen systems scaling from 65.2 kg to 192 kg storage capacity. The modular design of the framework enables replication beyond the specific context of Crete, supporting the scalable development of Renewable Energy Valleys that can adapt to diverse sectoral mixes and regional conditions.

Remote off-grid microgrids are often locked into diesel-backed operation because renewable variability creates multi-day and seasonal energy gaps that short-duration batteries cannot economically bridge. This work examines how renewable hydrogen can complement batteries and dispatchable biomass to push an existing hybrid microgrid toward near-autonomous, low-carbon operation, while remaining robust under future electrification demands. The analysis is based on real operational load insights from a remote off-grid system, combined with techno-economic optimization in HOMER Pro. The examined architecture includes PV panels, battery energy storage, a biomass CHP unit, and a diesel generator as backup; the hydrogen pathway additionally incorporates an electrolysis, storage and a PEMFC. Three scenarios are considered: a baseline PV/BAT configuration, an intermediate PV/BAT/BIO configuration that strengthens dispatchable renewable supply and short-term flexibility, and a PV/BAT/BIO/H₂ configuration targeting an increase in renewable energy penetration (REP). Results show that hydrogen integration shifts the system from curtailment-limited, diesel-supported operation to storage-enabled operation: surplus renewable production that would otherwise be curtailed is converted into hydrogen and later dispatched during prolonged deficits, enabling deep diesel displacement without compromising reliability. Hydrogen-enabled configurations achieve 90–99% REP, reduced diesel consumption, and lower CO₂ emissions, primarily by converting curtailed surplus into storable hydrogen. A rule-based EMS highlights technology complementarity across timescales, with batteries providing diurnal balancing and hydrogen covering longer deficits, which also reduces battery cycling stress. Overall, the study clarifies key design trade-offs, especially the need for coordinated PV expansion and storage sizing, and illustrates how a multi-storage portfolio can support high renewable penetration in such systems.

The integration and control of energy systems for power generation consists of multiple heterogeneous subsystems, such as chemical, electrochemical, and thermal, and contains challenges that arise from the multi-way interactions due to complex dynamic responses among the involved subsystems. The main motivation of this work is to design the control system for an autonomous automated and sustainable system that meets a certain power demand profile. A systematic methodology for the integration and control of a hybrid system that converts liquefied petroleum gas (LPG) to hydrogen, which is subsequently used to generate electrical power in a high-temperature fuel cell that charges a Li-Ion battery unit, is presented. An advanced nonlinear model predictive control (NMPC) framework is implemented to achieve this goal. The operational objective is the satisfaction of power demand while maintaining operation within a safe region and ensuring thermal and chemical balance. The proposed NMPC framework based on experimentally validated models is evaluated through simulation for realistic operation scenarios that involve static and dynamic variations of the power load.