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1
Solyanik, Andrey. "Analysis of cost efficiency of hydrogen production via electrolysis: the Russian case study." E3S Web of Conferences 289 (2021): 04002. http://dx.doi.org/10.1051/e3sconf/202128904002.
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The article focused on investigation of cost efficiency of hydrogen production via water electrolysis in Russia up to 2030. Different non-carbon generation technologies were assumed as input sources for electrolysis, namely wind, solar, hydro and nuclear power plants. Analysis is based on levelized cost of hydrogen (LCOH) framework incorporating all cost related to electrolysis (capital cost, operation & maintenance, electricity price, etc.). Additionally, we estimated LCOH sensitivity to some techno-economic parameters – cost of capital, capital expenses and capacity factor of different power supply sources.
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Xia, Tian, Mostafa Rezaei, Udaya Dampage, Sulaiman Ali Alharbi, Omaima Nasif, Piotr F. Borowski, and Mohamed A. Mohamed. "Techno-Economic Assessment of a Grid-Independent Hybrid Power Plant for Co-Supplying a Remote Micro-Community with Electricity and Hydrogen." Processes 9, no. 8 (August 6, 2021): 1375. http://dx.doi.org/10.3390/pr9081375.
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This study investigates the techno-economic feasibility of an off-grid integrated solar/wind/hydrokinetic plant to co-generate electricity and hydrogen for a remote micro-community. In addition to the techno-economic viability assessment of the proposed system via HOMER (hybrid optimization of multiple energy resources), a sensitivity analysis is conducted to ascertain the impact of ±10% fluctuations in wind speed, solar radiation, temperature, and water velocity on annual electric production, unmet electricity load, LCOE (levelized cost of electricity), and NPC (net present cost). For this, a far-off village with 15 households is selected as the case study. The results reveal that the NPC, LCOE, and LCOH (levelized cost of hydrogen) of the system are equal to $333,074, 0.1155 $/kWh, and 4.59 $/kg, respectively. Technical analysis indicates that the PV system with the rated capacity of 40 kW accounts for 43.7% of total electricity generation. This portion for the wind turbine and the hydrokinetic turbine with nominal capacities of 10 kW and 20 kW equates to 23.6% and 32.6%, respectively. Finally, the results of sensitivity assessment show that among the four variables only a +10% fluctuation in water velocity causes a 20% decline in NPC and LCOE.
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Rosenstiel, Andreas, Nathalie Monnerie, Jürgen Dersch, Martin Roeb, Robert Pitz-Paal, and Christian Sattler. "Electrochemical Hydrogen Production Powered by PV/CSP Hybrid Power Plants: A Modelling Approach for Cost Optimal System Design." Energies 14, no. 12 (June 10, 2021): 3437. http://dx.doi.org/10.3390/en14123437.
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Global trade of green hydrogen will probably become a vital factor in reaching climate neutrality. The sunbelt of the Earth has a great potential for large-scale hydrogen production. One promising pathway to solar hydrogen is to use economically priced electricity from photovoltaics (PV) for electrochemical water splitting. However, storing electricity with batteries is still expensive and without storage only a small operating capacity of electrolyser systems can be reached. Combining PV with concentrated solar power (CSP) and thermal energy storage (TES) seems a good pathway to reach more electrolyser full load hours and thereby lower levelized costs of hydrogen (LCOH). This work introduces an energy system model for finding cost-optimal designs of such PV/CSP hybrid hydrogen production plants based on a global optimization algorithm. The model includes an operational strategy which improves the interplay between PV and CSP part, allowing also to store PV surplus electricity as heat. An exemplary study for stand-alone hydrogen production with an alkaline electrolyser (AEL) system is carried out. Three different locations with different solar resources are considered, regarding the total installed costs (TIC) to obtain realistic LCOH values. The study shows that a combination of PV and CSP is an auspicious concept for large-scale solar hydrogen production, leading to lower costs than using one of the technologies on its own. For today’s PV and CSP costs, minimum levelized costs of hydrogen of 4.04 USD/kg were determined for a plant located in Ouarzazate (Morocco). Considering the foreseen decrease in PV and CSP costs until 2030, cuts the LCOH to 3.09 USD/kg while still a combination of PV and CSP is the most economic system.
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Ahshan, Razzaqul. "Potential and Economic Analysis of Solar-to-Hydrogen Production in the Sultanate of Oman." Sustainability 13, no. 17 (August 24, 2021): 9516. http://dx.doi.org/10.3390/su13179516.
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Hydrogen production using renewable power is becoming an essential pillar for future sustainable energy sector development worldwide. The Sultanate of Oman is presently integrating renewable power generations with a large share of solar photovoltaic (PV) systems. The possibility of using the solar potential of the Sultanate can increase energy security and contribute to the development of the sustainable energy sector not only for the country but also for the international community. This study presents the hydrogen production potential using solar resources available in the Sultanate. About 15 locations throughout the Sultanate are considered to assess the hydrogen production opportunity using a solar PV system. A rank of merit order of the locations for producing hydrogen is identified. It reveals that Thumrait and Marmul are the most suitable locations, whereas Sur is the least qualified. This study also assesses the economic feasibility of hydrogen production, which shows that the levelized cost of hydrogen (LCOH) in the most suitable site, Thumrait, is 6.31 USD/kg. The LCOH in the least convenient location, Sur, is 7.32 USD/kg. Finally, a sensitivity analysis is performed to reveal the most significant influential factor affecting the future’s green hydrogen production cost. The findings indicate that green hydrogen production using solar power in the Sultanate is promising, and the LCOH is consistent with other studies worldwide.
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Gunawan, Tubagus Aryandi, Alessandro Singlitico, Paul Blount, James Burchill, James G. Carton, and Rory F. D. Monaghan. "At What Cost Can Renewable Hydrogen Offset Fossil Fuel Use in Ireland’s Gas Network?" Energies 13, no. 7 (April 8, 2020): 1798. http://dx.doi.org/10.3390/en13071798.
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The results of a techno-economic model of distributed wind-hydrogen systems (WHS) located at each existing wind farm on the island of Ireland are presented in this paper. Hydrogen is produced by water electrolysis from wind energy and backed up by grid electricity, compressed before temporarily stored, then transported to the nearest injection location on the natural gas network. The model employs a novel correlation-based approach to select an optimum electrolyser capacity that generates a minimum levelised cost of hydrogen production (LCOH) for each WHS. Three scenarios of electrolyser operation are studied: (1) curtailed wind, (2) available wind, and (3) full capacity operations. Additionally, two sets of input parameters are used: (1) current and (2) future techno-economic parameters. Additionally, two electricity prices are considered: (1) low and (2) high prices. A closest facility algorithm in a geographic information system (GIS) package identifies the shortest routes from each WHS to its nearest injection point. By using current parameters, results show that small wind farms are not suitable to run electrolysers under available wind operation. They must be run at full capacity to achieve sufficiently low LCOH. At full capacity, the future average LCOH is 6–8 €/kg with total hydrogen production capacity of 49 kilotonnes per year, or equivalent to nearly 3% of Irish natural gas consumption. This potential will increase significantly due to the projected expansion of installed wind capacity in Ireland from 5 GW in 2020 to 10 GW in 2030.
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Perna, Alessandra, Mariagiovanna Minutillo, Simona Di Micco, Viviana Cigolotti, and Adele Pianese. "Ammonia as hydrogen carrier for realizing distributed on-site refueling stations implementing PEMFC technology." E3S Web of Conferences 197 (2020): 05001. http://dx.doi.org/10.1051/e3sconf/202019705001.
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Ammonia is a particularly promising hydrogen carrier due to its relatively low cost, high energy density, its liquid storage and to its production from renewable sources. Thus, in recent years, great attention is devoted to this fuel for realizing next generation refueling stations according to a carbon-free energy economy. In this paper a distributed onsite refueling station (200 kg/day of hydrogen filling 700-bar HFCEVs (Hybrid Fuel Cell Electric Vehicles) with about 5 kg of hydrogen in 5 min), based on ammonia feeding, is studied from the energy and economic point of views. The station is designed with a modular configuration consisting of more sections: i) the hydrogen production section, ii) the electric energy supplier section, iii) the compression and storage section and the refrigeration/dispenser section. The core of the station is the hydrogen production section that is based on an ammonia cracking reactor and its auxiliaries; the electric energy demand necessary for the station operation (i.e. the hydrogen compression and refrigeration) is satisfied by a PEMFC (Proton-Exchange Membrane Fuel Cell) power module. Energy performance, according to the hydrogen daily demand, has been evaluated and the estimation of the levelized cost of hydrogen (LCOH) has been carried out in order to establish the cost of the hydrogen at the pump that can assure the feasibility of this novel refueling station.
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Kulikov, Aleksandr, Aleksey Loskutov, Andrey Kurkin, Andrey Dar’enkov, Andrey Kozelkov, Valery Vanyaev, Andrey Shahov, et al. "Development and Operation Modes of Hydrogen Fuel Cell Generation System for Remote Consumers’ Power Supply." Sustainability 13, no. 16 (August 20, 2021): 9355. http://dx.doi.org/10.3390/su13169355.
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At the present stage of electric power industry development, special attention is being paid to the development and research of new efficient energy sources. The use of hydrogen fuel cells is promising for remote autonomous power supply systems. The authors of the paper have developed the structure and determined the optimal composition of a hybrid generation system based on hydrogen fuel cells and battery storage and have conducted studies of its operating modes and for remote consumers’ power supply efficiency. A simulation of the electromagnetic processes was carried out to check the operability of the proposed hybrid generation system structure. The simulation results confirmed the operability of the structure under consideration, the calculation of its parameters reliability and the high quality of the output voltage. The electricity cost of a hybrid generation system was estimated according to the LCOE (levelized cost of energy) indicator, its value being 1.17 USD/kWh. The factors influencing the electricity cost of a hydrogen generation system have been determined and ways for reducing its cost identified.
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Singh, Shakti, Prachi Chauhan, Mohd Asim Aftab, Ikbal Ali, S. M. Suhail Hussain, and Taha Selim Ustun. "Cost Optimization of a Stand-Alone Hybrid Energy System with Fuel Cell and PV." Energies 13, no. 5 (March 10, 2020): 1295. http://dx.doi.org/10.3390/en13051295.
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Renewable energy has become very popular in recent years. The amount of renewable generation has increased in both grid-connected and stand-alone systems. This is because it can provide clean energy in a cost-effective and environmentally friendly fashion. Among all varieties, photovoltaic (PV) is the ultimate rising star. Integration of other technologies with solar is enhancing the efficiency and reliability of the system. In this paper a fuel cell–solar photovoltaic (FC-PV)-based hybrid energy system has been proposed to meet the electrical load demand of a small community center in India. The system is developed with PV panels, fuel cell, an electrolyzer and hydrogen storage tank. Detailed mathematical modeling of this system as well as its operation algorithm have been presented. Furthermore, cost optimization has been performed to determine ratings of PV and Hydrogen system components. The objective is to minimize the levelized cost of electricity (LCOE) of this standalone system. This optimization is performed in HOMER software as well as another tool using an artificial bee colony (ABC). The results obtained by both methods have been compared in terms of cost effectiveness. It is evident from the results that for a 68 MWh/yr of electricity demand is met by the 129 kW Solar PV, 15 kW Fuel cell along with a 34 kW electrolyzer and a 20 kg hydrogen tank with a LPSP of 0.053%. The LCOE is found to be in 0.228 $/kWh. Results also show that use of more sophisticated algorithms such as ABC yields more optimized solutions than package programs, such as HOMER. Finally, operational details for FC-PV hybrid system using IEC 61850 inter-operable communication is presented. IEC 61850 information models for FC, electrolyzer, hydrogen tank were developed and relevent IEC 61850 message exchanges for energy management in FC-PV hybrid system are demonstrated.
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Gracia, Lorién, Pedro Casero, Cyril Bourasseau, and Alexandre Chabert. "Use of Hydrogen in Off-Grid Locations, a Techno-Economic Assessment." Energies 11, no. 11 (November 13, 2018): 3141. http://dx.doi.org/10.3390/en11113141.
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Diesel generators are currently used as an off-grid solution for backup power, but this causes CO2 and GHG emissions, noise emissions, and the negative effects of the volatile diesel market influencing operating costs. Green hydrogen production, by means of water electrolysis, has been proposed as a feasible solution to fill the gaps between demand and production, the main handicaps of using exclusively renewable energy in isolated applications. This manuscript presents a business case of an off-grid hydrogen production by electrolysis applied to the electrification of isolated sites. This study is part of the European Ely4off project (n° 700359). Under certain techno-economic hypothesis, four different system configurations supplied exclusively by photovoltaic are compared to find the optimal Levelized Cost of Electricity (LCoE): photovoltaic-batteries, photovoltaic-hydrogen-batteries, photovoltaic-diesel generator, and diesel generator; the influence of the location and the impact of different consumptions profiles is explored. Several simulations developed through specific modeling software are carried out and discussed. The main finding is that diesel-based systems still allow lower costs than any other solution, although hydrogen-based solutions can compete with other technologies under certain conditions.
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Hinokuma, Tatsuya, Hooman Farzaneh, and Ayas Shaqour. "Techno-Economic Analysis of a Fuzzy Logic Control Based Hybrid Renewable Energy System to Power a University Campus in Japan." Energies 14, no. 7 (April 1, 2021): 1960. http://dx.doi.org/10.3390/en14071960.
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In order to reduce the load demand of buildings in Japan, this study proposes a grid-tied hybrid solar–wind–hydrogen system that is equipped with a maximum power point tracking (MPPT) system, using a fuzzy logic control (FLC) algorithm. Compared with the existing MPPTs, the proposed MPPT provides rapid power control with small oscillations. The dynamic simulation of the proposed hybrid renewable energy system (HRES) was performed in MATLAB-Simulink, and the model results were validated using an experimental setup installed in the Chikushi campus, Kyushu University, Japan. The techno-economic analysis (TEA) of the proposed system was performed to estimate the optimal configuration of the proposed HRES, subject to satisfying the required annual load in the Chikushi campus. The results revealed a potential of 2% surplus power generation from the proposed HRES, using the FLC-based MPPT system, which can guarantee a lower levelized cost of electricity (LOCE) for the HRES and significant savings of 2.17 million yen per year. The TEA results show that reducing the cost of the solar system market will lead to a reduction in LCOE of the HRES in 2030.
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Takatsu, Naoto, and Hooman Farzaneh. "Techno-Economic Analysis of a Novel Hydrogen-Based Hybrid Renewable Energy System for Both Grid-Tied and Off-Grid Power Supply in Japan: The Case of Fukushima Prefecture." Applied Sciences 10, no. 12 (June 12, 2020): 4061. http://dx.doi.org/10.3390/app10124061.
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After the Great East Japan Earthquake, energy security and vulnerability have become critical issues facing the Japanese energy system. The integration of renewable energy sources to meet specific regional energy demand is a promising scenario to overcome these challenges. To this aim, this paper proposes a novel hydrogen-based hybrid renewable energy system (HRES), in which hydrogen fuel can be produced using both the methods of solar electrolysis and supercritical water gasification (SCWG) of biomass feedstock. The produced hydrogen is considered to function as an energy storage medium by storing renewable energy until the fuel cell converts it to electricity. The proposed HRES is used to meet the electricity demand load requirements for a typical household in a selected residential area located in Shinchi-machi in Fukuoka prefecture, Japan. The techno-economic assessment of deploying the proposed systems was conducted, using an integrated simulation-optimization modeling framework, considering two scenarios: (1) minimization of the total cost of the system in an off-grid mode and (2) maximization of the total profit obtained from using renewable electricity and selling surplus solar electricity to the grid, considering the feed-in-tariff (FiT) scheme in a grid-tied mode. As indicated by the model results, the proposed HRES can generate about 47.3 MWh of electricity in all scenarios, which is needed to meet the external load requirement in the selected study area. The levelized cost of energy (LCOE) of the system in scenarios 1 and 2 was estimated at 55.92 JPY/kWh and 56.47 JPY/kWh, respectively.
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Szima, Szabolcs, Carlos Arnaiz del Pozo, Schalk Cloete, Szabolcs Fogarasi, Ángel Jiménez Álvaro, Ana-Maria Cormos, Calin-Cristian Cormos, and Shahriar Amini. "Techno-Economic Assessment of IGCC Power Plants Using Gas Switching Technology to Minimize the Energy Penalty of CO2 Capture." Clean Technologies 3, no. 3 (August 10, 2021): 594–617. http://dx.doi.org/10.3390/cleantechnol3030036.
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Cost-effective CO2 capture and storage (CCS) is critical for the rapid global decarbonization effort recommended by climate science. The increase in levelized cost of electricity (LCOE) of plants with CCS is primarily associated to the large energy penalty involved in CO2 capture. This study therefore evaluates three high-efficiency CCS concepts based on integrated gasification combined cycles (IGCC): (1) gas switching combustion (GSC), (2) GSC with added natural gas firing (GSC-AF) to increase the turbine inlet temperature, and (3) oxygen production pre-combustion (OPPC) that replaces the air separation unit (ASU) with more efficient gas switching oxygen production (GSOP) reactors. Relative to a supercritical pulverized coal benchmark, these options returned CO2 avoidance costs of 37.8, 22.4 and 37.5 €/ton (including CO2 transport and storage), respectively. Thus, despite the higher fuel cost and emissions associated with added natural gas firing, the GSC-AF configuration emerged as the most promising solution. This advantage is maintained even at CO2 prices of 100 €/ton, after which hydrogen firing can be used to avoid further CO2 cost escalations. The GSC-AF case also shows lower sensitivity to uncertain economic parameters such as discount rate and capacity factor, outperforms other clean energy benchmarks, offers flexibility benefits for balancing wind and solar power, and can achieve significant further performance gains from the use of more advanced gas turbine technology. Based on all these insights, the GSC-AF configuration is identified as a promising solution for further development.
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Das, Vipin, Pitchai Karuppanan, Asheesh Kumar Singh, and Padmanabh Thakur. "Optimal Sizing and Control of Solar PV-PEMFC Hybrid Power Systems." International Journal of Mathematical, Engineering and Management Sciences 6, no. 4 (July 18, 2021): 1137–56. http://dx.doi.org/10.33889/ijmems.2021.6.4.068.
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This paper explores several possible hybridized techniques to supply electrical energy at remote locations where the utility grid extension is found uneconomical. In this work, diesel-generator (DG) is combined with the various renewable energy resources (RES) and multiple storage facilities, such as (i) proton exchange membrane fuel cell (PEMFC) and hydrogen energy storage (HES), (ii) PEMFC, HES, and Solar PV, and (iii) HES, Solar PV, PEMFC, HES, and battery storage system (BSS), respectively, to achieve the best hybrid solution to supply electrical power in remotely located area efficiently. The Homer Pro software developed by the national renewable energy laboratory is used in this paper for conducting the proposed analysis. The problem is formulated as a multi-objective optimization problem to minimize the cost and greenhouse gas emissions. Three performance indices or objective functions, namely net present cost (NPC), levelized cost of energy (LCOE) and unmet load, have been evaluated for these three hybridizations to determine the best alternative to overcome the energy crunch, which is existing especially in remotely located area. The comparative analysis of the estimated performance parameters has revealed that the hybridization of DG with Solar PV, PEMFC, HES, & BSS provides smaller values of NPC (in US $), LCOE (in US $/kWh), and unmet load. Furthermore, hybridization of DG with Solar PV, PEMFC, HES, & BSS results in the lowest pollutant emission with zero unmet loads and energy wastage. Therefore, in this study, hybridization of DG, Solar PV, PEMFC, HES, & BSS is recommended as the best alternative to supply electrical power efficiently and economically to remote areas. In this stand-alone work mode of operation of DG is considered as a reference system and named ‘Combination 1’. The LCOE and NPC of the best suitable HPS are obtained as 0.50193 US $/kWh and 35200000 US $, respectively. As a result, the system's emission is reduced by 94% compared with the base case (combination 1).
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Fiaschi, Daniele, Giampaolo Manfrida, Karolina Petela, Federico Rossi, Adalgisa Sinicropi, and Lorenzo Talluri. "Exergo-Economic and Environmental Analysis of a Solar Integrated Thermo-Electric Storage." Energies 13, no. 13 (July 6, 2020): 3484. http://dx.doi.org/10.3390/en13133484.
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Renewable energies are often subject to stochastic resources and daily cycles. Energy storage systems are consequently applied to provide a solution for the mismatch between power production possibility and its utilization period. In this study, a solar integrated thermo-electric energy storage (S-TEES) is analyzed both from an economic and environmental point of view. The analyzed power plant with energy storage includes three main cycles, a supercritical CO2 power cycle, a heat pump and a refrigeration cycle, indirectly connected by sensible heat storages. The hot reservoir is pressurized water at 120/160 °C, while the cold reservoir is a mixture of water and ethylene glycol, maintained at −10/−20 °C. Additionally, the power cycle’s evaporator section rests on a solar-heated intermediate temperature (95/40 °C) heat reservoir. Exergo-economic and exergo-environmental analyses are performed to identify the most critical components of the system and to obtain the levelized cost of electricity (LCOE), as well as the environmental indicators of the system. Both economic and environmental analyses revealed that solar energy converting devices are burdened with the highest impact indicators. According to the results of exergo-economic analysis, it turned out that average annual LCOE of S-TEES can be more than two times higher than the regular electricity prices. However, the true features of the S-TEES system should be only fully assessed if the economic results are balanced with environmental analysis. Life cycle assessment (LCA) revealed that the proposed S-TEES system has about two times lower environmental impact than referential hydrogen storage systems compared in the study.
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Corigliano, O., G. De Lorenzo, and P. Fragiacomo. "Techno-energy-economic sensitivity analysis of hybrid system Solid Oxide Fuel Cell/Gas Turbine." AIMS Energy 9, no. 5 (2021): 934–90. http://dx.doi.org/10.3934/energy.2021044.
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<abstract> <p>The paper presents a wide and deep analysis of the techno-energy and economic performance of a Solid Oxide Fuel Cell/Gas Turbine hybrid system fed by gas at different compositions of H<sub>2</sub>, CO, H<sub>2</sub>O, CO<sub>2</sub>, CH<sub>4, </sub> and N<sub>2</sub>. The layout of the system accounts for pressurizing of entering fluids, heat up to the set Solid Oxide Fuel Cell inlet conditions, Solid Oxide Fuel Cell thermo-electrochemical processing, Solid Oxide Fuel Cell—exhaust fluids combustion, turbo-expansion after heat up, and final recovery unit for cogeneration purposes.</p> <p>An ad hoc numerical modeling is developed and then run in a Matlab calculation environment. The influence on the system is evaluated by investigating the change of the fuel composition, and by managing the main operating parameters such as pressure and the fuel utilization factor. The analysis reports on the specific mass flowrates necessary to the purpose required, by assessing the SOFC outlet molar compositions, specific energies (work) at main system elements, specific thermal energies at main system elements, energy and technical performance for Solid Oxide Fuel Cell energy unit; the performance such as electric and thermal efficiency, temperatures at main system elements. A final sensitivity analysis on the performance, Levelized Cost of Energy and Primary Energy Saving, is made for completion. The first simulation campaign is carried out on a variable anodic mixture composed of H<sub>2</sub>, CO, H<sub>2</sub>O, considering the H<sub>2</sub>/CO ratio variable within the range 0.5-14, and H<sub>2</sub>O molar fraction variable in the range 0.1-0.4; used to approach a possible syngas in which they are significantly high compared to other possible compounds. While other simulation campaigns are conducted on real syngases, produced by biomass gasification. The overall Solid Oxide Fuel Cell/Gas Turbine system showed a very promising electric efficiency, ranging from 53 to 63%, a thermal efficiency of about 37%, an LCOE ranging from 0.09 to 0.14 ＄·kWh<sup>-1</sup>, and a Primary Energy Saving in the range of 33-52%, which resulted to be highly affected by the H<sub>2</sub>/CO ratio.</p> <p>Also, real syngases at high H<sub>2</sub>/CO ratio are noticed as the highest quality, revealing electric efficiency higher than 60%. Syngases with methane presence also revealed good performance, according to the fuel processing of methane itself to hydrogen. Low-quality syngases revealed electric efficiencies of about 51%. Levelized Cost of Energy varied from 0.09 (for high-quality gas) to 0.19 (for low-quality gas) ＄·kWh<sup>-1</sup>, while Primary Energy Saving ranged from 44 to 52%.</p> </abstract>
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Montenon, Alaric Christian, and Costas Papanicolas. "Economic Assessment of a PV Hybridized Linear Fresnel Collector Supplying Air Conditioning and Electricity for Buildings." Energies 14, no. 1 (December 29, 2020): 131. http://dx.doi.org/10.3390/en14010131.
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The present study evaluates the potential upgrade of a Linear Fresnel Reflector (LFR) collector at the Cyprus Institute (CyI) with photovoltaics via the calculation of the Levelized Cost Of Heat (LCOH). For over 4 years the collector has been supplying heating and cooling to the Novel Technologies Laboratory (NTL) of the Cyprus Institute (CyI). Extensive measurements have been carried out both on the LFR and NTL to render real numbers in the computations. This hybridization would be undertaken with the installation of PV arrays under mirrors, so that the collector is able to either reflect direct radiation to the receiver to process heat or to produce electricity directly in the built environment. The main objective is the decrease of the LCOH of Linear Fresnel collectors, which hinders their wider deployment, while air conditioning demand is globally booming. The results show that the LCOH for a small LFR to supply air conditioning is high, c€25.2–30.1 per kWh, while the innovative PV hybridization proposed here decreases it. The value of the study resides in the real data collected in terms of thermal efficiency, operation, and maintenance.
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Stanytsina, Valentyna, Volodymyr Artemchuk, Olga Bogoslavska, Iryna Zinovieva, and Nataliia Ridei. "The influence of environmental tax rates on the Levelized cost of heat on the example of organic and biofuels boilers in Ukraine." E3S Web of Conferences 280 (2021): 09012. http://dx.doi.org/10.1051/e3sconf/202128009012.
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In December 2019, the European Commission officially presented The European Green Deal, a new EU economic development program aimed at achieving climate neutrality on the European continent by 2050. Many previous global, European, and national programs also aim to reduce emissions of pollutants into the atmosphere. In this context, one of the ways to reduce emissions is the development of alternative energy sources (in particular the wider use of biofuel boilers) and increasing environmental tax rates. When choosing the optimal heating boilers, the practice of using the levelized cost of heating (LCOH) indicator is common. Environmental pollution tax (as a component of LCOH) is calculated for the three most common types of boilers (for Ukrainian boiler houses) with a capacity of 4.65 to 58 MW, burning natural gas, coal, and fuel oil, as well as low-power boilers burning organic and biofuels, for existing environmental tax rates, for projected increasing in 4 times (according to the bill) and subject to the introduction of minimum and maximum rates in EU countries. It is established that at the current environmental tax rates in Ukraine there are almost no economic incentives for the introduction of technologies to reduce the concentration of pollutants in emissions, but increasing environmental tax rates may change this situation. This, in turn, once again suggests that changing environmental tax rates can be an effective tool for achieving sustainable development goals.
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Parkinson, B., P. Balcombe, J. F. Speirs, A. D. Hawkes, and K. Hellgardt. "Levelized cost of CO2 mitigation from hydrogen production routes." Energy & Environmental Science 12, no. 1 (2019): 19–40. http://dx.doi.org/10.1039/c8ee02079e.
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Hussaini, Zaharaddeen Ali, Peter King, and Chris Sansom. "Numerical Simulation and Design of Multi-Tower Concentrated Solar Power Fields." Sustainability 12, no. 6 (March 19, 2020): 2402. http://dx.doi.org/10.3390/su12062402.
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In power tower systems, the heliostat field is one of the essential subsystems in the plant due to its significant contribution to the plant’s overall power losses and total plant investment cost. The design and optimization of the heliostat field is hence an active area of research, with new field improvement processes and configurations being actively investigated. In this paper, a different configuration of a multi-tower field is explored. This involves adding an auxiliary tower to the field of a conventional power tower Concentrated Solar Power (CSP) system. The choice of the position of the auxiliary tower was based on the region in the field which has the least effective reflecting heliostats. The multi-tower configuration was initially applied to a 50 MWth conventional field in the case study region of Nigeria. The results from an optimized field show a marked increase in the annual thermal energy output and mean annual efficiency of the field. The biggest improvement in the optical efficiency loss factors be seen from the cosine, which records an improvement of 6.63%. Due to the size of the field, a minimal increment of 3020 MWht in the Levelized Cost of Heat (LCOH) was, however, recorded. In much larger fields, though, a higher number of weaker heliostats were witnessed in the field. The auxiliary tower in the field provides an alternate aim point for the weaker heliostat, thereby considerably cutting down on some optical losses, which in turn gives rise to higher energy output. At 400 MWth, the multi-tower field configuration provides a lower LCOH than the single conventional power tower field.
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Pan, Guangsheng, Wei Gu, Qinran Hu, Jianxiao Wang, Fei Teng, and Goran Strbac. "Cost and low-carbon competitiveness of electrolytic hydrogen in China." Energy & Environmental Science 14, no. 9 (2021): 4868–81. http://dx.doi.org/10.1039/d1ee01840j.
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To quantify the cost and low-carbon competitiveness of electrolytic hydrogen in China, this paper presents a detailed assessment of the levelized cost of electrolytic hydrogen produced by a photovoltaic and grid-based hydrogen system (PGHS).
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Acosta-Pazmiño, Iván, Carlos Rivera-Solorio, and Miguel Gijón-Rivera. "Energetic and Economic Analyses of an LCPV/T Solar Hybrid Plant for a Sports Center Building in Mexico." Energies 13, no. 21 (October 30, 2020): 5681. http://dx.doi.org/10.3390/en13215681.
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This study presents a techno-economic performance evaluation of a hybrid low-concentrating photovoltaic/thermal (LCPV/T) plant, which operates in a student sports and wellness center building situated at a university campus in Mexico. The solar plant comprises 144 LCPV/T collectors based on a hybridized version of a local parabolic trough technology. Dynamic thermal and electrical performance analyses were performed in the TRNSYS simulation studio. The results showed that the solar field could cover up to 72% of the hot water demand of the building during the summer season and 24% during the winter season. The hybrid system could annually save 7185 USD, accounting for heat (natural gas boiler) and electricity generation. However, the payback time was of 19.23 years, which was mainly attributed to a reduced natural gas price in Monterrey, Mexico. A new approach to evaluating the equivalent levelized cost of heat (LCOHeq), is proposed. This results in an LCOHeq of 0.065 USD/kWh, which is nearly equivalent to the LCOH of a natural gas-fired boiler (0.067 USD/kWh). Finally, the hybrid plant could achieve a specific CO2e emission reduction of 77.87 kg CO2e per square meter of the required installation area.
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Szima, Szabolcs, and Calin-Cristian Cormos. "CO2 Utilization Technologies: A Techno-Economic Analysis for Synthetic Natural Gas Production." Energies 14, no. 5 (February 25, 2021): 1258. http://dx.doi.org/10.3390/en14051258.
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Production of synthetic natural gas (SNG) offers an alternative way to valorize captured CO2 from energy intensive industrial processes or from a dedicated CO2 grid. This paper presents an energy-efficient way for synthetic natural gas production using captured CO2 and renewable hydrogen. Considering several renewable hydrogen production sources, a techno-economic analysis was performed to find a promising path toward its practical application. In the paper, the five possible renewable hydrogen sources (photo fermentation, dark fermentation, biomass gasification, bio photolysis, and PV electrolysis) were compared to the two reference cases (steam methane reforming and water electrolysis) from an economic stand point using key performance indicators. Possible hydrogen production capacities were also considered for the evaluation. From a technical point of view, the SNG process is an efficient process from both energy efficiency (about 57%) and CO2 conversion rate (99%). From the evaluated options, the photo-fermentation proved to be the most attractive with a levelized cost of synthetic natural gas of 18.62 €/GJ. Considering the production capacities, this option loses its advantageousness and biomass gasification becomes more attractive with a little higher levelized cost at 20.96 €/GJ. Both results present the option when no CO2 credit is considered. As presented, the CO2 credits significantly improve the key performance indicators, however, the SNG levelized cost is still higher than natural gas prices.
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Hugo, Yohanes Antonius, Wiebrand Kout, Guido Dalessi, Antoni Forner-Cuenca, Zandrie Borneman, and Kitty Nijmeijer. "Techno-Economic Analysis of a Kilo-Watt Scale Hydrogen-Bromine Flow Battery System for Sustainable Energy Storage." Processes 8, no. 11 (November 18, 2020): 1492. http://dx.doi.org/10.3390/pr8111492.
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Transitioning to a renewable energy economy requires the widespread integration of solar and wind power, which are intermittent, into the electricity grid. To this goal, it is paramount to develop cost-competitive, reliable, location-independence, and large-scale energy storage technologies. The hydrogen bromine flow battery (HBFB) is a promising technology given the abundant material availability and its high power density. Here, the aim is to perform a comprehensive techno-economic analysis of a 500 kW nominal power/5 MWh HBFB storage system, based on the levelized cost of storage approach. Then, we systematically analyze stack and system components costs for both the current base and a future scenario (2030). We find that, for the base case, HBFB capital investments are competitive to Li-ion battery technology, highlighting the potential of large-scale HBFB market introduction. Improving the stack performance and reducing the stack and system costs are expected to result in ~62% reduction potential in capital investments. The base-case levelized cost of storage, $0.074/kWh, is sufficiently low for a wind-solar storage system to compete with a fossil-based power plant, with potential for reduction to $0.034/kWh in the future scenario. Sensitivity analysis indicates that the levelized cost of storage is most sensitive towards the stack lifetime, which motivates research efforts into advanced electrocatalysts with higher durability and ion-exchange membranes with improved selectivity.
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Romanov, Dmitry, and Bernd Leiss. "Analysis of Enhanced Geothermal System Development Scenarios for District Heating and Cooling of the Göttingen University Campus." Geosciences 11, no. 8 (August 19, 2021): 349. http://dx.doi.org/10.3390/geosciences11080349.
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The huge energy potential of Enhanced Geothermal Systems (EGS) makes them perspective sources of non-intermittent renewable energy for the future. This paper focuses on potential scenarios of EGS development in a locally and in regard to geothermal exploration, poorly known geological setting—the Variscan fold-and-thrust belt —for district heating and cooling of the Göttingen University campus. On average, the considered single EGS doublet might cover about 20% of the heat demand and 6% of the cooling demand of the campus. The levelized cost of heat (LCOH), net present value (NPV) and CO2 abatement cost were evaluated with the help of a spreadsheet-based model. As a result, the majority of scenarios of the reference case are currently not profitable. Based on the analysis, EGS heat output should be at least 11 MWth (with the brine flow rate being 40 l/s and wellhead temperature being 140 °C) for a potentially profitable project. These parameters can be a target for subsurface investigation, reservoir modeling and hydraulic stimulation at a later stage. However, sensitivity analysis presented some conditions that yield better results. Among the most influential parameters on the outcome are subsidies for research wells, proximity to the campus, temperature drawdown and drilling costs. If realized, the EGS project in Göttingen might save up to 18,100 t CO2 (34%) annually.
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Perez, Rapha Julysses, Alan C. Brent, and James Hinkley. "Assessment of the Potential for Green Hydrogen Fuelling of Very Heavy Vehicles in New Zealand." Energies 14, no. 9 (May 4, 2021): 2636. http://dx.doi.org/10.3390/en14092636.
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This study examined the feasibility of green hydrogen as a transport fuel for the very heavy vehicle (VHV) fleet in New Zealand. Green hydrogen is assumed to be produced through water electrolysis using purely renewable energy (RE) as an electricity source. This study chose very heavy vehicles as a potential market for green hydrogen, because it is considered “low-hanging fruit” for hydrogen fuel in a sector where battery electrification is less feasible. The study assumed a large-scale, decentralized, embedded (dedicated) grid-connected hydrogen system of production using polymer electrolytic membrane (PEM) electrolysers. The analysis comprised three steps. First, the hydrogen demand was calculated. Second, the additional RE requirement was determined and compared with consented, but unbuilt, capacity. Finally, the hydrogen production cost was calculated using the concept of levelized cost. Sensitivity analysis and cost reduction scenarios were also undertaken. The results indicate an overall green hydrogen demand for VHVs of 71 million kg, or 8.5 PJ, per year, compared to the 14.7 PJ of diesel fuel demand for the same VHV travelled kilometres. The results also indicate that the estimated 9824 GWh of RE electricity that could be generated from consented, yet unbuilt, RE projects is greater than the electricity demand for green hydrogen production, which was calculated to be 4492 GWh. The calculated levelized hydrogen cost is NZD 6.83/kg. Electricity cost was found to be the most significant cost parameter for green hydrogen production. A combined cost reduction for CAPEX and electricity translates to a hydrogen cost reduction in 10 to 20 years.
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Pan, Guangsheng, Wei Gu, Haifeng Qiu, Yuping Lu, Suyang Zhou, and Zhi Wu. "Bi-level mixed-integer planning for electricity-hydrogen integrated energy system considering levelized cost of hydrogen." Applied Energy 270 (July 2020): 115176. http://dx.doi.org/10.1016/j.apenergy.2020.115176.
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Singh, Nirala, and Eric W. McFarland. "Levelized cost of energy and sensitivity analysis for the hydrogen–bromine flow battery." Journal of Power Sources 288 (August 2015): 187–98. http://dx.doi.org/10.1016/j.jpowsour.2015.04.114.
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Coppitters, Diederik, Ward De Paepe, and Francesco Contino. "Robust design optimization of a renewable-powered demand with energy storage using imprecise probabilities." E3S Web of Conferences 238 (2021): 10004. http://dx.doi.org/10.1051/e3sconf/202123810004.
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During renewable energy system design, parameters are generally fixed or characterized by a precise distribution. This leads to a representation that fails to distinguish between uncertainty related to natural variation (i.e. future, aleatory uncertainty) and uncertainty related to lack of data (i.e. present, epistemic uncertainty). Consequently, the main driver of uncertainty and effective guidelines to reduce the uncertainty remain undetermined. To assess these limitations on a grid-connected household supported by a photovoltaic-battery system, we distinguish between present and future uncertainty. Thereafter, we performed a robust design optimization and global sensitivity analysis. This paper provides the optimized designs, the main drivers of the variation in levelized cost of electricity and the effect of present uncertainty on these drivers. To reduce the levelized cost of electricity variance for an optimized photovoltaic array and optimized photovoltaic-battery design, improving the determination of the electricity price for every specific scenario is the most effective action. For the photovoltaic-battery robust design, the present uncertainty on the prediction accuracy of the electricity price should be addressed first, before the most effective action to reduce the levelized cost of electricity variance can be determined. Future work aims at the integration of a heat demand and hydrogen-based energy systems.
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Kalbasi, Rasool, Mehdi Jahangiri, and Ahmad Tahmasebi. "Comprehensive Investigation of Solar-Based Hydrogen and Electricity Production in Iran." International Journal of Photoenergy 2021 (June 9, 2021): 1–14. http://dx.doi.org/10.1155/2021/6627491.
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Hydrogen is a clean and environmentally friendly energy vector that can play an important role in meeting the world’s future energy needs. Therefore, a comprehensive study of the potential for hydrogen production from solar energy could greatly facilitate the transition to a hydrogen economy. Because by knowing the exact amount of potential for solar hydrogen production, the cost-effectiveness of its production can be compared with other methods of hydrogen production. Considering the above, it can be seen that so far no comprehensive study has been done on finding the exact potential of solar hydrogen production in different stations of Iran and finding the most suitable station. Therefore, in the present work, for the first time, using the HOMER and ArcGIS softwares, the technical-economic study of solar hydrogen production at home-scale was done. The results showed that Jask station with a levelized cost of energy equal to $ 0.172 and annual production of 83.8 kg of hydrogen is the best station and Darab station with a levelized cost of energy equal to $ 0.286 and annual production of 50.4 kg of hydrogen is the worst station. According to the results, other suitable stations were Bushehr and Deyr, and other unsuitable stations were Anzali and Khalkhal. Also, in 102 under study stations, 380 MW of solar electricity equivalent to 70.2 tons of hydrogen was produced annually. Based on the geographic information system map, it is clear that the southern half of Iran, especially the coasts of the Persian Gulf and the sea of Oman, is suitable for hydrogen production, and the northern, northeastern, northwestern, and one region in southern of Iran are unsuitable for hydrogen production. The authors of this article hope that the results of the present work will help the energy policymakers to create strategic frameworks and a roadmap for the production of solar hydrogen in Iran.
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Whiston, Michael M., Inês M. Lima Azevedo, Shawn Litster, Constantine Samaras, Kate S. Whitefoot, and Jay F. Whitacre. "Hydrogen Storage for Fuel Cell Electric Vehicles: Expert Elicitation and a Levelized Cost of Driving Model." Environmental Science & Technology 55, no. 1 (December 4, 2020): 553–62. http://dx.doi.org/10.1021/acs.est.0c04145.
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Schell, Lori Smith, Jeff G. Reed, Li Zhao, Jack Brouwer, and Scott Samuelsen. "Comparing the Levelized Cost of Returned Energy (LCORE) Values for Hydrogen-Based Conversion Pathways and Batteries." ECS Transactions 96, no. 1 (January 31, 2020): 43–69. http://dx.doi.org/10.1149/09601.0043ecst.
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Gil, Juan D., Jerónimo Ramos-Teodoro, José A. Romero-Ramos, Rodrigo Escobar, José M. Cardemil, Cynthia Giagnocavo, and Manuel Pérez. "Demand-Side Optimal Sizing of a Solar Energy–Biomass Hybrid System for Isolated Greenhouse Environments: Methodology and Application Example." Energies 14, no. 13 (June 22, 2021): 3724. http://dx.doi.org/10.3390/en14133724.
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The water–energy–food nexus has captured the attention of many researchers and policy makers for the potential synergies between those sectors, including the development of self-sustainable solutions for agriculture systems. This paper poses a novel design approach aimed at balancing the trade-off between the computational burden and accuracy of the results. The method is based on the combination of static energy hub models of the system components and rule-based control to simulate the operational costs over a one-year period as well as a global optimization algorithm that provides, from those results, a design that maximizes the solar energy contribution. The presented real-world case study is based on an isolated greenhouse, whose water needs are met due to a desalination facility, both acting as heat consumers, as well as a solar thermal field and a biomass boiler that cover the demand. Considering the Almerian climate and 1 ha of tomato crops with two growing seasons, the optimal design parameters were determined to be (with a solar fraction of 16% and a biomass fraction of 84%): 266 m2 for the incident area of the solar field, 425 kWh for the thermal storage system, and 4234 kW for the biomass-generated power. The Levelized Cost of Heat (LCOH) values obtained for the solar field and biomass boiler were 0.035 and 0.078 €/kWh, respectively, and the discounted payback period also confirmed the profitability of the plant for fuel prices over 0.05 €/kWh. Thus, the proposed algorithm is useful as an innovative decision-making tool for farmers, for whom the burden of transitioning to sustainable farming systems might increase in the near future.
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Moore, Jared, and Noah Meeks. "Hourly modelling of Thermal Hydrogen electricity markets." Clean Energy 4, no. 3 (September 2020): 270–87. http://dx.doi.org/10.1093/ce/zkaa014.
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Abstract The hourly operation of Thermal Hydrogen electricity markets is modelled. The economic values for all applicable chemical commodities are quantified (syngas, ammonia, methanol and oxygen) and an hourly electricity model is constructed to mimic the dispatch of key technologies: bi-directional power plants, dual-fuel heating systems and plug-in fuel-cell hybrid electric vehicles. The operation of key technologies determines hourly electricity prices and an optimization model adjusts the capacity to minimize electricity prices yet allow all generators to recover costs. We examine 12 cost scenarios for renewables, nuclear and natural gas; the results demonstrate emissions-free, ‘energy-only’ electricity markets whose supply is largely dominated by renewables. The economic outcome is made possible in part by seizing the full supply-chain value from electrolysis (both hydrogen and oxygen), which allows an increased willingness to pay for (renewable) electricity. The wholesale electricity prices average $25–$45/MWh, or just slightly higher than the assumed levelized cost of renewable energy. This implies very competitive electricity prices, particularly given the lack of need for ‘scarcity’ pricing, capacity markets, dedicated electricity storage or underutilized electric transmission and distribution capacity.
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Serra, Fabio, Marialaura Lucariello, Mario Petrollese, and Giorgio Cau. "Optimal Integration of Hydrogen-Based Energy Storage Systems in Photovoltaic Microgrids: A Techno-Economic Assessment." Energies 13, no. 16 (August 11, 2020): 4149. http://dx.doi.org/10.3390/en13164149.
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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.
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Acakpovi, Amevi, Patrick Adjei, Nana Yaw Asabere, Robert Adjetey Sowah, and David Mensah Sackey. "Techno-Economic Evaluation of Hydrogen Fuel Cell Electricity Generation Based on Anloga (Ghana) Wind Regime." International Journal of Energy Optimization and Engineering 10, no. 3 (July 2021): 47–69. http://dx.doi.org/10.4018/ijeoe.2021070103.
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This paper assesses the performance of electricity generation using wind/hydrogen/fuel-cell technology. The intermittency of renewables, especially wind, and the need for storage of excess energy make them unattractive for continuous generation of electricity. This paper focuses on the wind resource of Anloga (Ghana) and the potential of hydrogen production from water electrolysis. The assessment of this system covers three main areas including the potential energy generation, environmental impacts, and economic impacts. The paper adopted analytical models of energy generation of fuel cell and hydrogen technologies and further performs their assessment using HOMER software. It was revealed that the annual electricity production from the hydrogen fuel cell is 25,999kW/yr, with an annual capacity shortage of 392kW/yr representing a 10% capacity shortage. The levelized cost of electricity was 0.602$/kWh and the emissions have been completely minimized as compared to diesel generation plants.
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Reyes-Belmonte, Miguel Ángel, Alejandra Ambrona-Bermúdez, and Daniel Calvo-Blázquez. "Flexible Electricity Dispatch of an Integrated Solar Combined Cycle through Thermal Energy Storage and Hydrogen Production." Thermo 1, no. 1 (June 8, 2021): 106–21. http://dx.doi.org/10.3390/thermo1010008.
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In this work, the flexible operation of an Integrated Solar Combined Cycle (ISCC) power plant has been optimized considering two different energy storage approaches. The objective of this proposal is to meet variable users’ grid demand for an extended period at the lowest cost of electricity. Medium temperature thermal energy storage (TES) and hydrogen generation configurations have been analyzed from a techno-economic point of view. Results found from annual solar plant performance indicate that molten salts storage solution is preferable based on the lower levelized cost of electricity (0.122 USD/kWh compared to 0.158 USD/kWh from the hydrogen generation case) due to the lower conversion efficiencies of hydrogen plant components. However, the hydrogen plant configuration exceeded, in terms of plant availability and grid demand coverage, as fewer design constraints resulted in a total demand coverage of 2155 h per year. It was also found that grid demand curves from industrial countries limit the deployment of medium-temperature TES systems coupled to ISCC power plants, since their typical demand curves are characterized by lower power demand around solar noon when solar radiation is higher. In such scenarios, the Brayton turbine design is constrained by noon grid demand, which limits the solar field and receiver thermal power design.
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Oldenbroek, Vincent, Gilbert Smink, Tijmen Salet, and Ad J. M. van Wijk. "Fuel Cell Electric Vehicle as a Power Plant: Techno-Economic Scenario Analysis of a Renewable Integrated Transportation and Energy System for Smart Cities in Two Climates." Applied Sciences 10, no. 1 (December 23, 2019): 143. http://dx.doi.org/10.3390/app10010143.
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Renewable, reliable, and affordable future power, heat, and transportation systems require efficient and versatile energy storage and distribution systems. If solar and wind electricity are the only renewable energy sources, what role can hydrogen and fuel cell electric vehicles (FCEVs) have in providing year-round 100% renewable, reliable, and affordable energy for power, heat, and transportation for smart urban areas in European climates? The designed system for smart urban areas uses hydrogen production and FCEVs through vehicle-to-grid (FCEV2G) for balancing electricity demand and supply. A techno-economic analysis was done for two technology development scenarios and two different European climates. Electricity and hydrogen supply is fully renewable and guaranteed at all times. Combining the output of thousands of grid-connected FCEVs results in large overcapacities being able to balance large deficits. Self-driving, connecting, and free-floating car-sharing fleets could facilitate vehicle scheduling. Extreme peaks in balancing never exceed more than 50% of the available FCEV2G capacity. A simple comparison shows that the cost of energy for an average household in the Mid Century scenario is affordable: 520–770 €/year (without taxes and levies), which is 65% less compared to the present fossil situation. The system levelized costs in the Mid Century scenario are 71–104 €/MWh for electricity and 2.6–3.0 €/kg for hydrogen—and we expect that further cost reductions are possible.
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Farzaneh. "Design of a Hybrid Renewable Energy System Based on Supercritical Water Gasification of Biomass for Off-Grid Power Supply in Fukushima." Energies 12, no. 14 (July 15, 2019): 2708. http://dx.doi.org/10.3390/en12142708.
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This paper proposes an innovative hydrogen-based hybrid renewable energy system (HRES), which can be used to provide electricity, heat, hydrogen, and water to the small community in remote areas. The HRES introduced in this study is based on the integration of solar power generation, hydrogen generation from supercritical water gasification (SCWG) of wet biomass feedstock, hydrogen generation from solar water electrolysis, and a fuel cell to convert hydrogen to electricity and heat. The wet biomass feedstock contains aqueous sludge, kitchen waste, and organic wastewater. A simulation model is designed and used to investigate the control strategy for the hydrogen and electricity management through detailed size estimation of the system to meet the load requirements of a selected household area, including ten detached houses in a subject district around the Shinchi station located in Shinchi-machi, Fukushima prefecture, Japan. As indicated by results, the proposed HRES can generate about 47.3 MWh of electricity and about 2.6 ton of hydrogen per annum, using the annual wet biomass consumption of 98 tons, with a Levelized Cost of Energy (electricity and heat) of the system at 0.38 $/kWh. The implementation of the proposed HRES in the selected residential area has GHG emissions reduction potential of about 21 tons of CO2-eq per year.
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Acakpovi, Amevi, Patrick Adjei, Nnamdi Nwulu, and Nana Yaw Asabere. "Optimal Hybrid Renewable Energy System: A Comparative Study of Wind/Hydrogen/Fuel-Cell and Wind/Battery Storage." Journal of Electrical and Computer Engineering 2020 (December 15, 2020): 1–15. http://dx.doi.org/10.1155/2020/1756503.
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This paper performs a technoeconomic comparison of two hybrid renewable energy supplies (HRES) for a specific location in Ghana and suggests the optimal solution in terms of cost, energy generation capacity, and emissions. The two HRES considered in this paper were wind/hydrogen/fuel-cell and wind/battery storage, respectively. The necessity of this study was derived from the rise and expansion of hybrid renewable energy supply in a decentralised network. The readiness to embrace these new technologies is apparently high, but the best combination for a selected location that brings optimum benefits is not obvious and demands serious technical knowledge of their technical and economic models. In the methodology, an analytical model of energy generation by the various RE sources was first established, and data were collected about a rural-urban community in Doderkope, Ghana, to test the models. HOMER software was used to design the two hybrid systems based on the same load profiles, and results were compared. It turns out that the HRES 1 (wind/hydrogen/fuel-cell) had the lowest net present cost (NPC) and levelized cost of electricity (COE) over the project life span of 25 years. The energy reserve with the HRES 2 (wind/battery storage) was huge compared to that with the HRES 1, about 270% bigger. Furthermore, with respect to the emissions, the HRES 2 was environmentally friendlier than the HRES 1. Even though the battery storage seems to be more cost-effective than the hydrogen fuel-cell technology, the latter presents some merits regarding system capacity and emission that deserve greater attention as the world looks into more sustainable energy storage systems.
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Singh, Nirala, and Eric W. McFarland. "Erratum to “Levelized cost of energy and sensitivity analysis for the hydrogen–bromine flow battery” [J. Power Sources 288 (2015) 187–198]." Journal of Power Sources 296 (November 2015): 1. http://dx.doi.org/10.1016/j.jpowsour.2015.07.036.
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Rezaei, Mostafa, Udaya Dampage, Barun K. Das, Omaima Nasif, Piotr F. Borowski, and Mohamed A. Mohamed. "Investigating the Impact of Economic Uncertainty on Optimal Sizing of Grid-Independent Hybrid Renewable Energy Systems." Processes 9, no. 8 (August 23, 2021): 1468. http://dx.doi.org/10.3390/pr9081468.
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One of the many barriers to decarbonization and decentralization of the energy sector in developing countries is the economic uncertainty. As such, this study scrutinizes economics of three grid-independent hybrid renewable-based systems proposed to co-generate electricity and heat for a small-scale load. Accordingly, the under-study systems are simulated and optimized with the aid of HOMER Pro software. Here, a 20-year average value of discount and inflation rates is deemed a benchmark case. The techno-economic-environmental and reliability results suggest a standalone solar/wind/electrolyzer/hydrogen-based fuel cell integrated with a hydrogen-based boiler system is the best alternative. Moreover, to ascertain the impact of economic uncertainty on optimal unit sizing of the nominated model, the fluctuations of the nominal discount rate and inflation, respectively, constitute within the range of 15–20% and 10–26%. The findings of economic uncertainty analysis imply that total net present cost (TNPC) fluctuates around the benchmark value symmetrically between $478,704 and $814,905. Levelized energy cost varies from an amount 69% less than the benchmark value up to two-fold of that. Furthermore, photovoltaic (PV) optimal size starts from a value 23% less than the benchmark case and rises up to 55% more. The corresponding figures for wind turbine (WT) are, respectively, 21% and 29%. Eventually, several practical policies are introduced to cope with economic uncertainty.
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Stone, K. W., C. W. Lopez, and R. E. McAlister. "Economic Performance of the SCE Stirling Dish." Journal of Solar Energy Engineering 117, no. 3 (August 1, 1995): 210–14. http://dx.doi.org/10.1115/1.2847788.
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In 1982 McDonnell Douglas Aerospace (MDA) and United Stirling AB (USAB) of Sweden formed a joint venture to develop and market a solar Stirling dish system. Eight modules were built and extensively tested from 1984 to 1988. Power production and daily energy-conversion efficiency as determined by field testing were characterized and modeled into a computer program. Included in this simulation are models of mirror soiling rate, wind spillage loss, mirror washing, and other maintenance outage time, operation and maintenance (O&M) costs, and equipment purchase cost. An economic model of a hybrid (combustion) receiver has been included in the simulation for illustrating the value of using solar energy when available and other fuels such as methane, natural gas, hydrogen, etc. when solar energy is not available or adequate. This paper describes the simulation and presents comparisons of the simulation to test data. The simulation also estimates both the O&M expenses and levelized energy costs for different production volumes.
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Kornbluth, Kurt, Jason Greenwood, Eddie Jordan, Zach McCaffrey, and Paul A. Erickson. "Economic feasibility of hydrogen enrichment for reducing NOx emissions from landfill gas power generation alternatives: A comparison of the levelized cost of electricity with present strategies." Energy Policy 41 (February 2012): 333–39. http://dx.doi.org/10.1016/j.enpol.2011.10.054.
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Valencia, Guillermo, Aldair Benavides, and Yulineth Cárdenas. "Economic and Environmental Multiobjective Optimization of a Wind–Solar–Fuel Cell Hybrid Energy System in the Colombian Caribbean Region." Energies 12, no. 11 (June 3, 2019): 2119. http://dx.doi.org/10.3390/en12112119.
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A hybrid system was analyzed and optimized to produce electric energy in non-interconnected zones in the Colombian Caribbean region, contributing to the reduction of greenhouse gas emissions and the improvement in efficient energy management. A comparative analysis of the performance of hybrid was conducted using a proposed model, built with historical data for meteorological conditions, wind speed, and solar radiation. The model is integrated by a Southwest Wind Power Inc. wind turbine AIR 403, a proton-exchange membrane fuel cell (PEM), an electrolyzer, a solar panel, and a regulator based on proportional, integral, and derivative (PID) controllers to manipulate oxygen and hydrogen flow entering in the fuel cell. The transient responses of the cell voltage, current, and power were obtained for the demand of 200 W under changes in solar radiation and wind speed for each day of the year 2013 in different meteorological stations, such as Ernesto Cortissoz airport, Puerto Bolívar, Alfonso Lopez airport, and Simon Bolívar airport. Through the adjustment of the hydrogen and oxygen flow into the fuel cell, the maximum contribution of power generation from the fuel cell was presented for the Simon Bolívar airport in November with a value of 158.35 W (9.45%). Multiobjective design optimization under a Pareto diagram front is presented for each place studied to minimize the levelized cost of energy and CO2 emission, where the objective control variables are the number of panel and stack in the photovoltaic (PV) system and PEM.
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Carpenter, Chris. "Study Assesses Potential of Renewable Energy in Power Sector." Journal of Petroleum Technology 73, no. 07 (July 1, 2021): 65–66. http://dx.doi.org/10.2118/0721-0065-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21348, “The Color of Energy: The Competition To Be the Energy of the Future,” by Hon Chung Lau, National University of Singapore, prepared for the 2021 International Petroleum Technology Conference, held virtually 23 March–1 April. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. The author of the complete paper, for the purposes of this study, characterizes energies as brown, blue, or green. Brown energies are carbon dioxide (CO2)-emitting fossil fuels, such as gas, oil, or coal. Blue energies use carbon capture and storage (CCUS) technologies to remove the emitted CO2 from brown energies. Green energies are zero- or low-CO2-emitting renewable energies. By analyzing the CO2 intensity and levelized cost of energy of energy carriers of different colors, the author shows that renewable energies are best used in replacing fossil fuels in the power sector, where they have the greatest effect in reducing CO2 emission. Overview By 2017, only 11% of the world’s final consumption came from renewable energies, 85% came from fossil fuel, and 4% came from nuclear energy. Energy consumption can be divided into three sectors: power, transport, and thermal. At the time of writing, 26.4% of global power (electricity) consumption comes from renewable energies. In this sphere, renewable energies are making the most significant contribution in reducing CO2 emission. Forty-one percent of CO2 emission comes from electricity and heat, 21% from transport, and 21% from industry. Consequently, the key to global decarbonization is to decarbonize these three sectors. Green Energy Is Preferred Green energies consist of six major types: solar photovoltaic, solar thermal, wind, hydroelectricity, geothermal, and biomass. If 1 kWh of electricity generated by renewable energy (with the exception of biomass) is used to replace 1 kWh of electricity generated by fossil fuel, the net CO2 savings will amount to 0.8, 0.6, and 0.4 kg for replacing coal, oil, and natural gas, respectively. However, if 1 kWh of renewable electricity is used to generate green hydrogen (H2), which is then used for heat generation in industry, it will yield roughly 0.8 kWh of thermal energy, which replaces the same amount of thermal energy by natural gas. This amounts to a CO2 savings of only 0.16 kg CO2/kWh. Consequently, renewable power has the highest CO2 savings effect if it is used to replace fossil fuel for power generation rather than to replace fossil fuel for heat generation. Decarbonizing the Power Sector The power sector is easiest to decarbonize. The three methods foreseen to decarbonize the power sector are nuclear power, blue electricity generated by fossil-fuel power plants equipped with CCUS, and green electricity produced by renewables. The use of nuclear power plants is a country-specific issue. The dual challenge of nuclear plant safety and nuclear waste storage is a key sustainability issue. Recently, interest has been renewed in the idea of increasing investment in nuclear energy for decarbonizing the power sector. It is noteworthy that the countries for whom more than a quarter of their power generation is provided by nuclear energy are all in Europe.
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Rezaei, Mostafa, Ali Mostafaeipour, and Mehdi Jahangiri. "Economic assessment of hydrogen production from sea water using wind energy: A case study." Wind Engineering, August 3, 2020, 0309524X2094439. http://dx.doi.org/10.1177/0309524x20944391.
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This study seeks to scrutinize the economic aspects of establishing the proposed system for producing electricity and hydrogen in the nominated city. For this, levelized cost of wind-generated electricity, levelized cost of seawater desalinated using wind energy, levelized cost of wind-powered hydrogen, payback period of investing on electricity, and hydrogen production are predicted. The results indicated that levelized cost of wind-generated electricity would vary from 0.0208 to 0.053 US$/kWh under different cases and scenarios. This range regarding levelized cost of seawater desalinated using wind energy was between 0.0147 and 0.0404 US$/m3 and also the amount of levelized cost of wind-powered hydrogen was guessed to be from 7.0074 to 10.5667 US$/kg. All values of payback period calculated as to wind electricity were less than half of the project lifetime. In addition, payback period of generating hydrogen was arguable only for the turbine with a rated power of 900 kW.
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Romeri, Mario Valentino. "Hydrogen Fuel Cell Powertrain Levelized Cost of Electricity." SSRN Electronic Journal, 2012. http://dx.doi.org/10.2139/ssrn.2006758.
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Nordin, Nur Dalilah, and Hasimah Abdul Rahman. "An Economic Analysis of Small-Scale Standalone Photovoltaic System with Hydrogen Storage System." Journal of Energy and Safety Technology (JEST) 1, no. 1 (August 1, 2018). http://dx.doi.org/10.11113/jest.v1n1.3.
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This paper proposes design steps in obtaining the optimal size of a standalone photovoltaic (PV) system, which is able to meet a predetermined power load requirement. The keys of the system sizing are primarily to satisfy a specific load demand that depends on the power generated from the installed PV system and also to maintain hydrogen storage state of charge. A case study was conducted using Kuala Lumpur's meteorological data and a typical rural area load profile of 2.215 kWh. An economic analysis on the system was performed in order to determine system feasibility. The levelized cost of energy for the proposed system was RM1.98/kWh. However, the results showed that if the same configuration used absorbent glass mat (AGM) battery as the backup power supply, the system cost and levelized cost of energy is lower. Therefore, a sensitivity analysis of the electrolyzer and fuel cell efficiencies towards levelized cost of energy for the proposed system was executed. The result indicates that unless the efficiency of hydrogen storage technologies significantly increases in the future, the system will not be feasible to be implemented in Malaysia.
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Minutillo, M., A. Perna, A. Forcina, S. Di Micco, and E. Jannelli. "Analyzing the levelized cost of hydrogen in refueling stations with on-site hydrogen production via water electrolysis in the Italian scenario." International Journal of Hydrogen Energy, December 2020. http://dx.doi.org/10.1016/j.ijhydene.2020.11.110.
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Sangarunlert, W., S. Sukchai, A. Pongtornkulpanich, A. Nathakaranakule, and T. Luschtinetz. "Technical and Economic Evaluation of a Formic Acid/Hydrogen Peroxide Fuel Cell System With Pt-M/C as Anode Catalyst." Journal of Fuel Cell Science and Technology 8, no. 6 (September 26, 2011). http://dx.doi.org/10.1115/1.4004641.
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Cell performance of formic acid/hydrogen peroxide (HCOOH/H2O2) fuel cell, using commercial Pt-Ru/C, and prepared Pt-M/C (M = Ir, Mo, Co, Ag, W, Ni, Sn) bimetallic catalysts as anode catalysts are experimentally investigated and reported in this paper. Corresponding to cell performance, electrocatalytic activity of the system using commercially available and prepared catalysts is evaluated by linear sweep voltammetry technique (LSV). The result shows that the system using 20%Pt-10%Sn/C yields better formic acid oxidation reaction than that of other Pt-M/C bimetallic catalysts, but it is inferior to that of 20%Pt-10%Ru/C commercial catalyst. In addition, the cell performance of HCOOH/H2O2 fuel cell with various catalyst compositions of Pt and Sn content, in portions of 10:20, 15:15, and 20:10, respectively, is also studied. Comparison among those catalysts, 15%Pt-15%Sn/C yields better cell performance than the others. Levelized energy cost (LEC) and sensitivity analysis on LEC are also assessed.