Full Load Hours Research Articles

A comprehensive analysis of wind power integrated with solar and hydrogen storage systems: Case study of Java's Southern coast

Wind and solar energy are vital to the global transition toward sustainable energy systems, driven by the need to reduce fossil fuel dependence, mitigate climate change, and enhance energy security. This study aims to optimize system performance by integrating hydrogen technology and addressing capacity shortages and excess energy. First, a comprehensive analysis of wind characteristics in a strategically important area to meet unaccomplished Indonesia's 2023 wind energy targets, focusing on Java's southern coast using wind speed data from the System Advisor Model (SAM), was conducted. Four scenarios are then evaluated: wind turbine (WT)-battery energy storage system (BESS), WT-photovoltaic (PV)-BESS, WT-fuel cell (FC)-electrolyzer (EL)-hydrogen tank (H2T), and WT-PV–FC–EL-H2T. Key metrics analyzed include excess energy, Levelized Cost of Electricity (LCOE), Net Present Cost (NPC), capacity shortage (CS), and electrolyzer full-load hours (EFH). Results show that average wind speeds reach 4.2 m/s in Pandeglang, with the WT–FC–EL-H2T system being the most reliable, exhibiting a 5% capacity shortage and 68.5% excess electricity. The WT-PV–FC–EL scenario is the most cost-effective, with a COE of $0.508/kWh and an NPC of $2.6 million. These findings provide valuable insights for improving sustainable energy infrastructure in the region.

Global sensitivity analysis of nuclear district heating reactor primary heat exchanger and pressure vessel optimization

Recently, small modular reactors (SMRs) have received greater interest as a source for clean and affordable district heating (DH). Compared to power plants, the low-pressure, low-temperature design and nearly 100 % efficiency reduce the cost of produced energy considerably. However, few practical implementations exist yet, and cost estimates and design principles are subject to uncertainties whose interactions remain largely unknown. In this work, we present a techno-economic optimization and sensitivity analysis of a natural circulation DH SMR primary heat exchanger. A Cuckoo Search variant augmented with a modified Hooke-Jeeves search was used as the optimizer, with SimDec (simulation decomposition) subsequently employed for global sensitivity analysis. The reactor pressure vessel and containment vessel specific costs exhibited the greatest impact on the cost of heat and the optimized configurations. While low-pressure, low-temperature design is central to heating reactor cost-effectiveness, optimized primary circuit temperatures clearly exceeded previous assumptions. In a 5260 full-load hours mid-load application, a 34–41 €/MWh cost range was found for produced heat at 8 % interest and 20-year lifetime. For heat exchanger optimization, the results indicate the potential for considerable performance improvement from using deterministic local search for terminal convergence and sensitivity analysis for dimensionality reduction.

Co-Design of a Wind–Hydrogen System: The Effect of Varying Wind Turbine Types on Techno-Economic Parameters

Green hydrogen is crucial for achieving climate neutrality and replacing fossil fuels in processes that are hard to electrify. Wind farms producing electricity and hydrogen can help mitigate stress on electricity grids and enable new markets for operators. While optimizing wind farms for electricity production is well-established, optimizing combined wind–hydrogen systems is a relatively new research field. This study examines the potential profit of wind–hydrogen systems by conducting a case study of an onshore wind farm near the North Sea. Varying turbine types from high wind-speed turbines (with high annual energy production) to low wind-speed turbines (with high full-load hours) are examined. Findings indicate that in a combined hydrogen system, the low wind-speed turbines, which are sub-optimal for mere electricity production, yield lower levelized costs of hydrogen at a higher hydrogen production. Although high wind-speed turbines generate higher profits under current market conditions, at high hydrogen prices and low electricity prices, low wind-speed turbines can yield higher total profit at this site. Therefore, an integrated optimization approach of wind–hydrogen systems can, in certain cases, lead to better results compared to an isolated, sequential optimization of each individual system.

Global optimization of capacity ratios between electrolyser and renewable electricity source to minimize levelized cost of green hydrogen

This paper presents a novel and effective approach for calculating Levelized Cost of Hydrogen production across the globe, without requiring timely resolved modelling or data. We select characteristic production patterns of photovoltaic and wind turbine power generation based on location qualities indicated by full load hours. These representative patterns are applied worldwide on similar locations to evaluate the proportion of electricity that electrolyzers can use if they have a smaller capacity than the renewable electricity source. Hence, the ratio of capacities is optimized to minimize hydrogen cost. The findings from various worldwide locations reveal that decreasing electrolyzer capacity is economically beneficial across all locations for boosting full load hours and curbing investments, particularly in locations with lower electricity generation. Validation using precise electricity production timeseries in specific locations revealed minimal errors in the methodology, though the quality of the results is impacted by the seasonality index differences between representative and exact location.

Thermoelectric generator for energy production from renewable sources

Thermoelectric generators (TEG) produce electrical energy from a temperature difference between the cold and hot side of TEG modules (Seebeck effect); in principle, they can be used at temperature differences greater than 3 K [1]. Thermoelectric energy generation is primarily known for supplying self-sufficient sensors or in exhaust systems of motor vehicle internal combustion engines [2], where high temperature differences of up to 700 K are used. In this paper, basic investigations are carried out in order to expand the power range of thermoelectric energy generation and their potential for the energy transition. To this end, the area of application should be expanded to include medium and small temperature differences. The output characteristic of a TEG module has a power maximum, which increases quadratically with the temperature difference and linearly with the module area. At a temperature difference of 40 K, an output of 250 W/m2 can be generated. A solar module can generate 150 W/m2 in full sunlight; this output is only available for 12 % of the year given the 1000 full-load hours of sunshine that are usual in our latitudes. A continuous thermoelectric energy source could provide energy all year. Under optimal conditions, an annual usage time of 5000 hours and a service life of 10 years, electricity production costs of around 10 Cents/kWh can be expected [3]. This price is quite comparable to other renewable energy sources (photovoltaics, wind).

Variable renewable energy modeling system to study challenges that impact electrical load at different penetration levels: A case study on Kuwait's load profile

The transitioning from conventional power systems to variable renewable energy (VRE) could impose significant challenges on transmission, short-term balancing requirements, and more cycling to ramp conventional plants. Kuwait's government has set a target of 15% of electricity generation from renewable resources by 2030 and more in the following years. This ambitious target requires close collaboration between researchers and decision-makers to overcome the upcoming challenges. The current study comes in the context of this objective to support decision-makers technically during planning and deploying VRE plats in various parts of the country. An in-house simulation modeling system for solar photovoltaic (PV) and wind power based on high-quality weather data has been developed. The system can model centralized or decentralized VRE scenarios. Several load characteristics have been used to examine the output of the scenario, such as the residual load, impact on the peak, and baseload due to changes in VRE penetration level. Other parameters, including capacity credit, full load hours, ramping power magnitude and rate, and overproduction of resources, are also outputs of the system. The output results of the modeling system have been validated against two years of operational solar PV and wind Shagaya power plants data. The results show combining solar PV with wind could dramatically increase the capacity credit, reduce overproduction, and reduce ramping power. The authors will continue evolve and improve this in-house modeling system to support research in this field and for the upcoming future RE projects instead of relying on commercial software.

Assessing worldwide future potentials of renewable electricity generation: Installable capacity, full load hours and costs

Several studies calculate the potential of renewable energies throughout the world. However, these studies vary in the underlying assumptions and do not consider several technologies within a uniform methodology, which affects comparability. In this paper, we calculate the worldwide potentials of ground-mounted photovoltaic (PV), concentrated solar power (CSP), and wind onshore and offshore on a 6.5 by 6.5 km grid. The results consist of installable capacity, generated electricity, and specific cost of electricity generation. Our methodology combines high-resolution data for land uses, slope, and hourly weather data with a thorough analysis of different factors for wind power, like hub heights and rotor diameters, and solar power plants, like tilt angle, and temperature-related loss of efficiency. The results show that the summed-up potential capacity of ground-mounted PV surpasses the amount of CSP, wind onshore and offshore combined with 450 TW. Given the cost-potential curve, ground-mounted PV reaches 560,000 TWh at costs below 20 €/MWh, which is twice the projected worldwide primary energy supply of the World Energy Outlook 2022 for the year 2050 with 205,557 TWh. The calculated results can function as input factors for energy system models, which are an important tool to analyse the energy transition.

Role of Renewables in Energy Storage Economic Viability in the Western Balkans

Given the growing shares of renewable energy sources in the grids, the interest in energy storage systems has increased. The role of pumped hydro energy storage systems as flexible solutions for managing peak and off-peak prices from nuclear and fossil power plants in previous systems is now revitalized in the liberalized systems, with a volatile generation of wind and solar energy. Thus, understanding of the patterns behind the economics of energy storage is crucial for the further integration of energy storage in the grids. In this paper, the factors that impact the economic viability of energy storage in electricity markets are analyzed. The method of approach used in this study considers the electricity market price distribution, full load hours, the total costs of energy storage, and linear regression analysis. Using revenues from arbitraging a 10-megawatt (MW) pumped hydro storage system in the Western Balkans, resulting from the electricity market price distribution and the analysis of the total costs of storage, an econometric model is created. This model shows the impacting factors of energy storage development in the context of the rising renewables sector. Research shows that the previous hypothesis about the integration of energy storage systems in proportion to the increase in shares of renewables in the grids is incorrect. There is a significant correlation between energy storage revenues, the dependent variable, and the independent variables of hydro, wind, and solar generation. The conducted analysis indicates the future arbitraging opportunities of pumped hydro energy storage systems and provides useful insights for energy storage investors and policymakers. During the transitional period, until the deployment of renewables changes the effects of fossil power plants, energy storage price arbitrage is profitable and desirable for 500, 1000, and 2000 full load hours in the Western Balkan region. Despite the need for flexibility, with more renewables in the grids, large-scale energy storage systems will not be economically viable in the long run because of “revenue cannibalization”.

Profitability Model of Green Hydrogen Production on an Existing Wind Power Plant Location

This paper presents a new economic profitability model for a power-to-gas plant producing green hydrogen at the site of an existing wind power plant injected into the gas grid. The model is based on a 42 MW wind power plant, for which an optimal electrolyzer of 10 MW was calculated based on the 2500 equivalent full load hours per year and the projection of electricity prices. The model is calculated on an hourly level for all variables of the 25 years of the model. With the calculated breakeven electricity price of 74.23 EUR/MWh and the price of green hydrogen production of 99.44 EUR/MWh in 2045, the wind power plant would produce 22,410 MWh of green hydrogen from 31% of its total electricity production. Green hydrogen injected into the gas system would reduce the level of CO2 emissions by 4482 tons. However, with the projected prices of natural gas and electricity, the wind power plant would cover only 20% of the income generated by the electricity delivered to the grid by producing green hydrogen. By calculating different scenarios in the model, the authors concluded that the introduction of a premium subsidy model is necessary to accelerate deployment of electrolyzers at the site of an existing wind power plant in order to increase the wind farm profitability.

Life Cycle Assessment of a 5 MW Polymer Exchange Membrane Water Electrolysis Plant

This study performs a cradle‐to‐grave life cycle assessment of a 5 MW proton exchange membrane water electrolysis plant. The analysis follows a thorough engineering‐based bottom‐up design based on the electrochemical model of the system. Three scenarios are analyzed comprising a state‐of‐the‐art (SoA) plant operated with the German electricity grid‐mix, a SoA plant operated with a completely decarbonized energy system, and a future development plant electrolyzer with reduced energy and material demand, operated in a completely decarbonized energy system. The results display a global warming potential of 34 kg CO2‐eq. kg‐H2−1 and indicate a reduction potential of 89% when the plant is operated in a decarbonized energy system. A further reduction of 9% can be achieved by the technological development of the plant. Due to the reduced impacts of operation in a completely decarbonized energy system, the operation at locations with large offshore wind electricity capacity is recommended. In the construction phase, the stacks, especially the anode catalyst iridium, bipolar plates, and porous transport layers, are identified as dominant sources of the environmental impact. A sensitivity analysis shows that the environmental impact of the construction phase increases with a decreasing amount of operational full load hours of the plant.

Entrained flow gasification-based biomass-to-X processes: A techno-economic assessment

In the pursuit of a successful energy transition, synthetic basic chemicals and fuels, alongside renewable energies, play pivotal roles. This study focuses on the utilization of biomass as a carbon source to replace conventional fossil feedstocks, conducting detailed process simulations and techno-economic analyses for various biomass-to-x pathways. Six key products—Methanol, Dimethyl Ether, Methane (SNG), Fischer-Tropsch syncrude, Hydrogen, and Ammonia—derived from entrained flow gasification of a representative biomass are systematically compared. The uniformity of simulation detail and economic methodology enables a direct and comprehensive comparison of these products. Notably, carbon-based products exhibit up to 34% lower average investment costs compared to their hydrogen-based counterparts, namely ammonia and hydrogen. This cost discrepancy is reflected in the levelized costs of manufacturing, with hydrogen-based products emerging as the most energy-expensive. The analysis identifies variable costs as the primary contributor to overall costs with around 50%, followed by fixed investment. The study underscores the critical impact of full load hours, plant lifetime, and feedstock costs on results. This emphasise the importance of detailed planning if alternative feedstock is used to balance fuel costs and enhance plant availability. Among the evaluated products, methanol emerges as the most promising across the evaluated KPIs with costs of 283.48 € MWh−1. However, regarding hydrogen-based products, it is suggested that, especially in the context of CO2 abatement costs, a comprehensive consideration of the long-term system effects is essential to prevent misinvestments during the early stages of the energy transition. This emphasizes the need for strategic planning to ensure a sustainable and economically viable shift towards biomass-derived synthetic fuels.

Off-grid vs. grid-based: Techno-economic assessment of a power-to-liquid plant combining solid-oxide electrolysis and Fischer-Tropsch synthesis

The economic performance of Power-to-Liquid processes depends substantially on the power source’s features, i.e., electricity costs and full load hours. Off-grid solutions can ensure cheap, green electricity without being exposed to fluctuating electricity markets. A techno-economic assessment of a Power-to-Liquid plant combining solid-oxide electrolysis and Fischer-Tropsch synthesis has been conducted. Off-grid and grid-based scenarios of three process configurations at plant scales from 1 to 1000 MWel. rated electrolyzer power were evaluated. Net production costs of Fischer-Tropsch products ranging from 2.42 to 4.56 €2022/kg were obtained for the grid-based scenarios. In contrast, values of 1.28 to 2.40 €2022/kg were determined for the evaluated off-grid scenarios. Scaling up the plant showed a weakened decrease in net production costs after surpassing a threshold of 100 MWel. due to substantial relative electricity costs of up to 88 %. Thus, future Power-to-Liquid projects should be designed at a scale of 100MWel. rated electrolyzer power. In addition, an availability exceeding 4000 h/a is recommended for off-grid plants, e.g., by implementing hybrid renewable power plants as well as electricity and syngas storage technologies.

Impact of backtracking strategies on techno-economics of horizontal single-axis tracking solar photovoltaic power plants

Optimisation of horizontal single-axis tracking solar photovoltaic power plants is important for its optimal application. Commonly, standard backtracking has been applied to avoid mutual shading and improve the full load hours and levelised cost of electricity; however, this approach is not always the best solution for state-of-the-art modules with half cell technology. Backtracking has not yet been studied for different test sites with different solar and climatic conditions. This study aims to improve the knowledge on the techno-economic performance of horizontal single-axis tracking systems with half cell modules applying different backtracking strategies in full hourly resolution for nine test sites globally and varying row spacing. In addition to the standard backtracking algorithm, an advanced backtracking algorithm that varies the tracking angle only if the irradiance can be improved, and an advanced sophisticated backtracking algorithm simulating the irradiance for all possible tracking angles, are studied. The results confirm that standard backtracking is only superior for specific conditions. Compared to no backtracking, standard backtracking shows up to ca. 9% higher levelised cost of electricity due to lower full load hours. Advanced backtracking can lower the levelised cost of electricity by up to 9% and advanced sophisticated backtracking by up to 12%, due to improved full load hours. In general, results are similar and comparable for all test sites studied. This study highlights the importance of backtracking for optimised future horizontal single-axis tracking system planning.

Large‐scale spatiotemporal calculation of photovoltaic capacity factors using ray tracing: A case study in urban environments

AbstractPhotovoltaics (PVs) on building facades, either building‐integrated or building‐attached, offer a large energy yield potential especially in densely populated urban areas. Targeting this potential requires the availability of planning tools such as insolation forecasts. However, calculating the PV potential of facade surfaces in an urban environment is challenging. Complex time‐dependent shadowing and light reflections must be considered. In this contribution, we present fast ray tracing calculations for insolation forecasts in large urban environments using clustering of Sun positions into typical days. We use our approach to determine time resolved PV capacity factors for rooftops and facades in a wide variety of environments, which is particularly useful for energy system analyses. The advantage of our approach is that the determined capacity factors for one geographic location can be easily extended to larger geographic regions. In this contribution, we perform calculations in three exemplary environments and extend the results globally. Especially for facade surfaces, we find that there is a pronounced intra‐day and also seasonal distribution of PV potentials that strongly depends on the degree of latitude. The consideration of light reflections in our ray tracing approach causes an increase in calculated full load hours for facade surfaces between 10% and 25% for most geographical locations.

Exploring the location and use of baseload district heating supply. What can current heat sources tell us about future opportunities?

The decentralization of energy production and recovery of excess heat (EH) to reach climate targets is essential for renewable and fully decarbonized heating systems. This paper identifies current and potential industrial EH sources providing baseload capacity for district heating (DH) systems. These sources are evaluated by sector and process for supplying baseload capacities explored for current 3rd generation district heating (3GDH) and 4th generation district heating (4GDH) systems with lower grid temperatures and losses, with and without expansions. The method combines geographical analysis and available baseload capacity estimations for 360 Danish DH systems scenario-making and an additional sensitivity analysis evaluating baseload capacity full-load hours. It is found that 80 % of Danish DH systems have an unmet baseload capacity of 50 % or higher. Half of the systems have geothermal capacity available and up to 20 % of industrial EH baseload capacity potential, which sums up to 5 PJ of EH potential within a 2 km distance. The findings also suggest that there is an additional opportunity for the placement of future energy infrastructure able to supply EH, which is highly contextual and strategic in heat planning, particularly considering the future development of sustainable and energy-efficient DH systems.

Aggregated wind power characteristic curves and artificial intelligence for the regional wind power infeed estimation

The wind power generation is highly dependent on current weather conditions. In the course of the energy transition, the generation levels from volatile wind energy are constantly increasing. Accordingly, the prediction of regional wind power generation is a particularly important and challenging task due to the highly distributed installations. This paper presents a study on the role of regional wind power infeed estimation and proposes a multi-aggregated wind power characteristics model based on three scaled Gumbel distribution functions. Multi-levels of wind turbines and their allocation are investigated for the regional aggregated wind power. Relative peak power performance and full load hours are compared for the proposed model and the real measurement obtained from a local distribution system operator. Furthermore, artificial intelligence technologies using neural networks, such as Long Short-Term Memory (LSTM), stacked LSTM and CNN–LSTM, are investigated by using different historical measurement as input data. The results show that the suggested stacked LSTM performs stably and reliably in regional power prediction.

Assessment of the technical-economic performance and optimization of a parabolic trough solar power plant under Algerian climatic conditions

In this study, the design, analysis and optimization of the performance of a concentrated solar power plant that is based on the parabolic trough technology with a capacity of 100 MW equipped with a thermal energy storage system were conducted, in two representative sites in Algeria (Tamanrasset and M’Sila). The System Advisor Model software is used to evaluate the technical and economic performances of the two proposed power plants, in addition to carrying out the process of optimizing the initial design of the two power plants by finding the optimal values of the solar multiple and full load hours of the thermal energy storage system, with the aim of increasing the annual energy production and reducing the levelized cost of electricity. The results of the performance analysis conducted on the optimized design showed that the optimum values of the solar multiple and full load hours of the thermal energy storage system for the proposed power plant at the Tamanrasset site were found to be 2.4 and 7 h, respectively, with an annual electricity production of 514.6 GWh, and a minimum value of the levelized cost of electricity of 6.3¢/kWh. While the optimum performance of the proposed plant at the M'Sila site can be achieved by selecting a solar multiple of 3 and 7 h for thermal energy storage system, with a high annual energy production of 451.84 GWh and a low value of the levelized cost of electricity of 7.8¢/kWh. The results demonstrate that CSP plants using parabolic trough technology can increase energy security in the country, while reducing environmental concerns associated with the use of fossil materials.

Economic comparison of electric fuels for heavy duty mobility produced at excellent global sites - a 2035 scenario

The transformation of economies worldwide towards climate neutrality will require not only renewable electricity but also climate-neutral energy carriers such as hydrogen and its derivatives. The production cost of electric fuels (e-fuels) are to a large extent driven by the energy-intensive electrolytic water splitting. The option of producing e-fuels in highly industrialized countries, as Germany, competes with production at international locations, with excellent conditions for renewable energies and thus very low levelized cost of green hydrogen and its derivatives. In this paper, we examine the economic efficiency of various imported e-fuels that are under consideration in different scenarios for the year 2035: Fischer-Tropsch diesel, methanol, and hydrogen transported as cryogenic liquid or in form of liquid organic hydrogen carriers. We develop a mathematical model that covers the entire process chain, from the production of the e-fuels at various excellent locations worldwide to the energetic utilization of the fuels in a heavy duty vehicle. We find that the choice of production site has a major impact on the mobility cost using the respective fuels. Under the selected boundary conditions and assumptions, methanol, cryogenic hydrogen, and liquid organic hydrogen carriers are the most favourable options for all seven locations examined. Which e-fuel is cheapest varies with the production site. Especially in case of diesel, the levelized cost of electricity determined by the full load hours of the applied renewable energy source have a huge impact. An LOHC-based system is shown to be less dependent on electricity source compared to other technologies due to its comparatively low electricity consumption. The length of the transportation route and the price of the filling station infrastructure, however, increase mobility cost for LOHC and LH2.

Development Potential Assessment for Wind and Photovoltaic Power Energy Resources in the Main Desert–Gobi–Wilderness Areas of China

The large-scale centralized development of wind and PV power resources is the key to China’s dual carbon targets and clean energy transition. The vast desert–Gobi–wilderness areas in northern and western China will be the best choice for renewable energy development under multiple considerations of resources endowment, land use constraints, technical conditions, and economic level. It is urgent to carry out a quantitative wind and PV resource assessment study in desert–Gobi–wilderness areas. This paper proposed a multi-dimensional assessment method considering the influence of the power grid and transportation infrastructure distributions, which includes three research levels, namely, the technical installed capacity, the development potential, and the development cost. Nine main desert–Gobi–wilderness areas were assessed. The wind and PV technical installed capacities were 0.6 TW and 10.7 TW, and the total development potentials were over 0.12 TW and 1.2 TW, with the full load hours of 2513 and 1759 and the average development costs of 0.28 CNY/kWh and 0.20 CNY/kWh. Finally, this paper proposed the meteorological–electrical division distribution. A case study in the Kubuqi and Qaidam Deserts was carried out on wind–wind and wind–PV collaborative development across different meteorological–electrical divisions, which can reduce by 58% the long-term energy storage capacity and decrease the total system LCOE from 0.488 CNY/kWh to 0.445 CNY/kWh.

Off-grid solar PV–wind power–battery–water electrolyzer plant: Simultaneous optimization of component capacities and system control

Green hydrogen production systems will play an important role in the energy transition from fossil-based fuels to zero-carbon technologies. This paper investigates a concept of an off-grid alkaline water electrolyzer plant integrated with solar photovoltaic (PV), wind power, and a battery energy storage system (BESS). The operation of the plant is simulated over 30years with 5min time resolution based on measured power generation data collected from a solar photovoltaic installation and a wind farm located in southeastern Finland. Levelized cost of hydrogen (LCOH) is calculated based on the capital expenditures (CAPEX), the operating expenses (OPEX), and the respective learning curves for each of the components. Component degradation and replacements during the operational lifetime are included in the model, and the capacity of the components and the system control are simultaneously optimized to obtain the minimum LCOH. A sensitivity analysis performed over different installation years and discount rates reveals that for the off-grid alkaline system, the implementation of a wind farm as the sole power supply is the most economical solution until the installation years 2035–2040. Solar PV and a BESS are found to increase the full-load hours of the electrolyzer and reduce the electricity curtailed in the off-grid plant to less than 8%. However, with the current component prices and the climate in the studied region, they are not economically beneficial. It is found that the cost of hydrogen can be reduced to 2 €/kg by the year 2030.