This paper compares two common dispatch policies—Load-Following (LF) and Cycle-Charging (CC)—for a photovoltaic Battery Energy Storage System (PV–BESS) microgrid (MG) with a 12 kW diesel generator, using a full-year of real 15 min PV and load data from an industrial use case in Germany. A forward time-step simulation enforces the battery State-of-Energy (SoE) window (total basis [20, 100] %, DoD = 80%) and computes curtailment, generator use, and unmet energy. Feasible designs satisfy a Loss of Power Supply Probability (LPSP) ≤ 0.03. Economic evaluation follows an Equivalent Annual Cost (EUAC) model with PV and BESS Capital Expenditure/Operation and Maintenance (CAPEX/O&M) (cycle life dependent on DoD and 15-year calendar life), generator costs, and fuel via SFC and diesel price. A value of lost load (VOLL) can be applied to unserved energy, with an optional curtailment penalty. Across the design space, a clear cost valley appears toward moderate storage and modest PV, with the baseline optimum at ≈56 kWp PV and 200 kWh BESS (DoD = 80%). Both policies meet the reliability target (in our runs LPSP ≈ 0), and their SoE trajectories are nearly identical; CC only lifts the SoE slightly after generator-ON events by using headroom to charge, while LF supplies just the residual deficit. Sensitivity analyses show that the optimum is most affected by diesel price and discount rate, with smaller shifts for ±10% changes in SFC. The study provides a transparent, reproducible workflow—grounded in real data—for controller selection and capacity planning.

Microgrid sizing has traditionally been driven by economic, technical, environmental, and social criteria, while safety has often been treated implicitly or addressed at later stages of design and operation. In this context, safety refers to the prevention of unacceptable harm to people, assets, and the environment through appropriate design margins, protection coordination, operational limits, and risk-aware system configuration. However, the increasing penetration of distributed energy resources, battery energy storage systems, power electronics, and advanced digital control architectures has elevated safety to a critical design dimension that directly influences sizing decisions. Despite its importance, safety remains fragmented across the microgrid literature and lacks unified treatment within sizing-oriented studies. This paper presents a systematic review of microgrid sizing methodologies with a specific focus on safety-related indicators. The review critically examines how distinct safety dimensions—namely energy storage safety, protection and fault tolerance, operational margins and redundancy, grid interaction, cybersecurity, human and environmental safety—are addressed within traditional, artificial-intelligence-based, software-driven, and hybrid sizing approaches. Safety is conceptualized as a cross-cutting design constraint that shapes sizing variables and feasibility boundaries rather than as an independent optimization objective. By synthesizing the existing literature, this work identifies the safety dimensions most strongly coupled with sizing decisions. The paper further analyses how safety-related constraints can be incorporated into sizing frameworks and highlights key research gaps that hinder their systematic integration. The findings aim to provide a structured reference for researchers and practitioners seeking to embed safety considerations into microgrid sizing methodologies.

In a recent paper, we extended a previous study on the solar solar influence to the generation of the March 2012 heatwave in the northeastern USA. In the present study we check the possible relationship of solar activity with the early March 2012 bad weather in northeast Thrace, Greece. To this end, we examined data from various remote sensing instrumentation monitoring the Sun (SDO satellite), Interplanetary space (ACE satellite), the Earth’s magnetosphere (Earth-based measurements, NOAA-19 satellite), the top of the clouds (Terra and Aqua satellites), and the near ground atmosphere. Our comparative data analysis suggests that: (i) the winter-like weather (rainfall, fast winds, decreased temperature) in Thrace started on 6 March 2012, the same day as the heatwave started in USA, (ii) during the March 2012 winter-like event in Thrace (6–15 March), the ACE satellite recorded enhanced fluxes of solar energetic particles (SEPs), while SOHO and PAMELA recorded solar protons at very high energies (>500 MeV), (iii) Between 3–31 March, the temperature in Alexandoupoli and the ACE/EPAM solar high energy (1.88–4.70 MeV) proton flux were strongly anticorelated (r = −0.75, p = 0.5). (iv) Thrace experienced particularly intense cyclonic circulation, during periods of magnetic storms on 8–10 and 12–13 March, which occurred after the arrival at ACE of two interplanetary shock waves, on March 8 and March 11, respectively, (v) at the beginning of the two above mentioned periods large atmospheric electric fields were recorded, with values ranging between ~−2000 V/m and ~1800 V/m on 8 March, (vi) the winter-like weather on 8–10 March 2012 occurred after the detection of the main SEP event related with a coronal mass ejection released in interplanetary space as a result of intense solar flare activity observed by SDO on 7 March 2012, (vi) the 8–10 March weather was related with a deep drop of ~63 °C in the cloud top temperature measured by MODIS/Terra, which favors strong precipitation. Finally, we analyzed data from the electric power network in Thrace (~41°N) and we found, for the first time sudden voltage changes of ~3.5 kV in the electric grid in Greece, during the decay phase of the March 2012 storm series. We discuss the winter-like March 2012 event in Thrace regarding the influence of solar cosmic rays on the low troposphere mediated by positive North Atlantic Oscillation (NAO). Finally, we infer that the novel finding of the geomagnetic effects on the electric power grid in Thrace may open a new window into space weather applications research.

This paper investigates the integration of on-site photovoltaic (PV) systems in the industrial sector under a zero feed-in configuration, where all generated electricity is consumed locally without export to the grid. The analysis follows the current Greek regulatory framework and uses real operating data from an insulation materials manufacturing plant. Twelve months of measured electricity demand were combined with Typical Meteorological Year (TMY) solar data to simulate PV systems of 500, 1000, 1500, and 2000 kWp. Annual PV production ranges from approximately 739 MWh (500 kWp) to 2970 MWh (2000 kWp), and it is all fully self-consumed by the factory due to its high and continuous load. However, given the plant’s large annual electricity use, the PV systems offset 1.0–2.8% of total consumption. The avoided grid purchases correspond to 40–160 MWh/year of net energy savings, delivering positive Net Present Value (NPV) when electricity tariffs exceed EUR 0.15/kWh. The results confirm that zero feed-in PV deployment is technically feasible and economically attractive for industrial facilities facing high electricity prices, while also enhancing sustainability by reducing dependency on the public grid.

This paper presents a unified, data-driven optimization framework for the planning and operation of an arbitrary number N of grid-connected microgrids connected to a distribution feeder. Each microgrid is represented as a controllable energy entity comprising local loads, battery energy storage systems (BESS) modeled through their State of Energy (SOE), and optional local generation. The microgrids are embedded explicitly in a radial distribution network subject to hosting-capacity and ramp-rate constraints at the point of common coupling (PCC). Unlike many existing studies that rely on synthetic or stylized demand profiles, this work employs real, open-access hourly load data from the Electricity Load Measurements and Analysis (ELMAS) dataset (France) to construct heterogeneous residential, commercial, and industrial microgrid instances. A plug-and-play integration rule is formulated at the planning level: the connection of an additional microgrid is admissible if and only if the enlarged optimization problem remains feasible and all reliability, network, and safety-oriented constraints are satisfied. The deterministic formulation is extended to handle uncertainty via scenario-based stochastic modeling of load variability. A comprehensive case study based on real French load profiles illustrates how feeder hosting capacity can be quantified in terms of the maximum number of microgrids that can be safely integrated. The results demonstrate that coordinated planning significantly improves PCC behavior, reduces operational stress, and provides a clear quantitative criterion for plug-and-play microgrid integration in distribution networks.

This study presents an advanced safety management framework for “Wave Energy Converter” (WEC) projects, addressing the inherent uncertainty, technological complexity, and environmental exposure of offshore renewable energy systems. By collaborating “Failure Modes and Effects Analysis” (FMEA) and “Hazard and Operability Study” (HAZOP), the framework captures both component‐level failures and operational deviations, and through all lifecycle phases, the framework also enables systematic identification, prioritization, and mitigation of risks. The results highlight critical vulnerabilities related to anchoring systems, articulation joints, transport operations, and subsea connections. The proposed approach delivers actionable recommendations for phase‐specific risk prevention and mitigation and outlines principles for integration into comprehensive risk management systems. It emphasizes the importance of adaptive and dynamic frameworks capable of responding to evolving marine conditions and regulatory landscapes, providing a robust template for future offshore renewable energy projects.