Steam Cycle Research Articles

Design, energy, exergy, economy, and environment (4E) analysis, and multi-objective optimization of a novel integrated energy system based on solar and geothermal resources

Increasing energy consumption rates and concerns over environmental problems like global warming have led researchers to provide new energy supply solutions, one of which is the use of combined energy systems. Combining conventional fossil energy cycles with renewable cycles is one of the most effective ways to improve their performance and also help harvest green energy. To address this solution, in this paper, a hybrid novel energy system including a gas cycle, a steam cycle, two organic Rankine cycles (ORC), and a renewable cycle based on geothermal and solar energy sources using concentrating photovoltaic thermal panels (CPVT) is proposed. A comprehensive study has been conducted on this system from the perspective of energy, efficiency, economy, and the environment. Different fluids have been investigated for use in ORC subsystems in this study. Additionally, a parametric study has been conducted to determine how the cycle's overall performance is affected. Multi-objective optimization using the Non-dominated Sorting Genetic Algorithm second version (NSGA-II) has been performed based on the objective variables of exergy efficiency and capital costs. In this paper, Engineering Equation Solver (EES) and MATLAB are used for modeling and optimization. The results show that the best fluids to use in ORC are R123 in the first cycle and Ammonia in the second cycle, which energy efficiency, exergy efficiency, exergy destruction rate, and generated power in the base state for the whole cycle are 50.59%, 25.44%, 1537.35 kW and 524.66 kW, respectively. Also, the amount of annual capital cost and the amount of carbon dioxide emission from energy and exergy are 107,034 dollars, 11,672, and 35,401 kg per month, respectively. The optimization results indicate a 0.25% improvement in exergy efficiency and a 500$ annual capital cost reduction at the optimal point.

Availability and 6E assessment and optimal design of a novel cogeneration system based on integrated turbo compressor station - SOFC-solar-geothermal-steam and organic Rankine cycles with machine learning

A novel integrated cogeneration system for a real gas turbocompressor station has been proposed. Also, a new systematic approach has been introduced for analysis and optimization of the considered system based on using energy, electrochemical, exergy, exergoeconomic, exergoenvironmental, emergoeconomic, and emergoenvironmental analyses along with advanced exergy, economic and environmental evaluations, and availability assessment. In addition, a powerful machine learning tool has been employed to reduce optimization algorithm computational time.To show the ability of the proposed system and systematic approach, a gas injection station with three gas turbine (GT) drivers have been studied. To improve the performance from the thermodynamic, economic, and environmental points of view and to the application of renewable energies, the integrated system includes turbocompressors with solid oxide fuel cells (SOFC), steam, and organic Rankine cycles (SORCs) while using solar and geothermal energies has been proposed for the power and steam production. In addition, six-objective optimization has been done with a genetic algorithm, and finally, the availability assessment was applied for basic (turbocompressors) and the proposed cycle. To reduce the computational time of the optimization algorithm, the machine learning method has been employed to generate 6E objective functions.Results show the power generation is increased by about 60%, and 6370kg/h of process steam is produced. Five organic fluids were examined, and among them, R11 was found to be the best selection. Energy and exergy efficiencies increased by 12.8% and 10.8%, respectively, compared to the base cycle. Also, the results show that cost, environmental impact, and total emergy of electricity generation are 49.59 $/MWh, 26.99 Pts/MWh, and 4.09e12 sej/MWh. The advanced analysis states that REC1, LPSUP, and REC2 have the greatest potential for energetic, economic, and environmental improvements. In the optimal conditions, the results of the 6E analyses indicate that thermal and exergy efficiencies of 3.06% and 2.84%, and perspective of economic, environmental, and emergy per unit of power generation, 9.54%, 8.86%, and 9.05% of improvement is achieved, respectively. The availability of the proposed system was obtained at 87.28%, and the probability of failure of a GT is reduced by 0.14% compared to the base cycle, indicating the proposed plan's attractiveness.

CO2 Capture in a Thermal Power Plant Using Sugarcane Residual Biomass

The decarbonization of energy matrices is crucial to limit global warming below 2 °C this century. An alternative capable of enabling zero or even negative CO2 emissions is bioenergy with carbon capture and storage (BECCS). In this sense, the Brazilian sugar–energy sector draws attention, as it would be possible to combine the production of fuel and electricity from renewable biomass. This paper is the final part of a study that aimed to research carbon capture and storage (CCS) in energy systems based on sugarcane. The case studied is CCS in thermal power plants considering two different technologies: the steam cycle based on the condensing–extraction steam turbine (CEST) and the combined cycle integrated to biomass gasification (BIG-CC). The results for the thermal power plant indicate that the CO2 capture costs may be lower than those in cogeneration systems, which were previously studied. The main reasons are the potential scale effects and the minimization of energy penalties associated with integrating the CCS system into the mills. In the best cases, capture costs can be reduced to EUR 54–65 per ton of CO2 for the CEST technology and EUR 57–68 per ton of CO2 for the BIG-CC technology.

SOFC-VPSA System for Power Generation with CO2 Separation

To meet “net zero” emission target for greenhouse gases in the year 2050, it is essential to retrieve most of the produced CO2 from emission intensive activities and store it permanently underground. This study considers integration of a 10 kW solid oxide fuel cell (SOFC) system with vacuum pressure swing adsorption (VPSA). In the integrated system, a small amount of electricity needed for the VPSA directly comes from SOFC system. The oxygen produced by VPSA is used to complete the oxidation of the unconverted fuel from the anodic side of SOFC, and then CO2 is separated automatically after the water condensation. Moreover, in this study, SOFC with VPSA has been optimized for minimizing the energy requirement and number of heat exchangers. Eight heat exchangers have been sized. Finally, the integrated system has waste heat available, to valorise the waste heat of the system, a steam cycle has been integrated for producing around additional electricity, to improve the overall efficiency. Finally, economic analysis has been performed, to understand its market competitiveness.

Performance assessment and multiobjective optimization of a biomass waste-fired gasification combined cycle for emission reduction

The use of renewable fuels leads to reduction in the use of fossil fuels and environmental pollutants. In this study, the design and analysis of a CCPP based on the use of syngas produced from biomass is discussed. The studied system includes a gasifier system to produce syngas, an external combustion gas turbine and a steam cycle to recover waste heat from combustion gases. Design variables include syngas temperature, syngas moisture content, CPR, TIT, HRSG operating pressure, and PPTD. The effect of design variables on performance components such as power generation, exergy efficiency and total cost rate of the system is investigated. Also, through multi-objective optimization, the optimal design of the system is done. Finally, it is observed that at the final decisioned optimal point, the produced power is 13.4 MW, the exergy efficiency is 17.2%, and the TCR is 118.8 $/h.

Life cycle analyses of SOFC/gas turbine hybrid power plants accounting for long-term degradation effects

In this study, cradle-to-product life cycle analyses were conducted for a variety of natural-gas-based and coal-based SOFC power plant conceptual designs, while also accounting for long-term SOFC degradation. For each type of plant, four base case designs were considered: a standalone SOFC plant, a standalone SOFC plant with a steam cycle, an SOFC/GT hybrid plant, and an SOFC/GT hybrid plant with a steam cycle. The boundary of each base case was subsequently expanded to include either wet cooling or dry cooling options and DC to AC conversion, and was subjected to additional cradle-to-product life cycle analyses. The environmental impact results were computed using ReCiPe 2016 (H) and TRACI 2.1 V1.05 in SimaPro. The main factors affecting the midpoint impacts between cases were the plant efficiency and total SOFC manufacturing required over the plant's lifetime, which were both strongly connected to long-term degradation effects. The findings also showed that the standalone SOFC plant with a steam cycle (which featured higher plant efficiency) had lower midpoint impacts with respect to global warming potential and fossil resource scarcity, which were largely the product of plant operation. The case with the longer SOFC stack lifetime (e.g., a SOFC/GT hybrid power plant with a steam cycle) had lower midpoint impacts with respect to fine particulate matter formation, terrestrial acidification, terrestrial ecotoxicity, and mineral resource scarcity due to the large proportion of midpoint contributed by SOFC manufacturing. Ultimately, the SOFC/GT hybrid plant with a steam cycle was found to be the best option, as it had the lowest ReCiPe endpoint impact (4.5%–42% lower than the other cases)among both the natural gas-based and coal-based cases.

Computational analysis of nuclear desalination system under various configurations

Abstract The research addressed the economic evaluation of nuclear energy, coal, oil and natural gas in various cycle configurations with different distillation technologies. A comparison between fossil and nuclear energy sources is discussed. A comprehensive review of all desalination plants using fossil and nuclear energy with cogeneration is also included and discussed. Computational model was used to evaluate nuclear and non-nuclear desalination plants. Four possibilities were discussed. In this first case, a nuclear gas cycle integrated with a MED desalination plant was found to have the lowest cost in the gas cycle. While the nuclear steam cycle integrated with RO has the lowest cost compared to oil and natural gas. In the third case, the combined nuclear cycle was discussed and it was found that the combined nuclear cycle associated with RO has the lowest cost. In the last case, the evaluation of a heat-only desalination plant was conducted among all sources, and it was found that the nuclear plant with RO and MED has the lowest cost. In addition, the completed nuclear desalination plant was subjected to five scenarios to calculate and estimate at which capacity the plant provides the best values. The results show that nuclear desalination with gas cycle is the most economical among the oil and natural gas options.

Hybrid chemical-physical vapor deposition of highly durable environmental barrier coatings

Environmental barrier coatings (EBCs) are needed to protect SiC based ceramic matrix composites (CMCs) from steam attack in next generation aircraft engines. In this study, EBCs consisting of a dense Yb2Si2O7 top coat and a columnar structure silicon bond coat were deposited using a hybrid chemical-physical vapor deposition process. X-ray diffraction (XRD) and scanning electron microscopy (SEM) were used to characterize the coating phase composition and microstructure. The as-deposited Yb-Si-O coating is highly amorphous, and it transformed to crystalline Yb2Si2O7 and Yb2SiO5 phases after 1300 °C heat treatment in air. The durability of Yb2Si2O7/Si EBC was evaluated in a steam cycling test in flowing 90% H2O (g) + 10% air at 1316 °C, and the EBC survived 1000 1-h steam cycles without failure, which demonstrated the excellent durability of the hybrid vapor deposited Yb2Si2O7/Si EBC.

Pressure Vessel Design for High Temperature and Pressure Testing on Supercritical Carbon Dioxide

Abstract Supercritical carbon dioxide CO2 has been proposed as working fluid in various types of power plants, thanks to its potential higher efficiency and cost reduction with respect to well-known technology of steam cycles. However, the high operating temperature and pressure conditions pose significant concerns in terms of compatibility of supercritical CO2 with the high-temperature sections of the power block. Typically, to address this problem, experiments are proposed, where samples of different materials are kept in contact with the supercritical CO2 in a pressure vessel in order to test the material compatibility. This research deals with designing an innovative openable pressure vessel capable of withstanding the high temperatures (700 °C) and the pressures (100 bar) typical of those power plants. The results obtained by analytical calculation and the finite element method are consistent. The results obtained with both methods are generalizable and the methodology is applicable to any removable pressure vessel that must withstand 100 bar of pressure and a temperature of 700 °C, application field that is outside the ASME B&PV Code Section VIII division 1, standard usually used for the design of nonnuclear pressure vessels. It is important to emphasize that the use of a removable container allows to reduction of the costs of compatibility tests since otherwise, after each test, the pressure vessel would be disposed of. In addition, this allows a reduction of the environmental impact due to the fact that the new container will not be disposed of after each use.

A Genetic Algorithm approach for optimization of geothermal power plant production: Case studies of direct steam cycle in Kamojang

Indonesia has enormous geothermal potential, but it only contributes 5% to Indonesia's energy matrix. During 37 years of operation, PT. Pertamina Geothermal Energy Kamojang area has been operating to produce electricity and is currently capable of supplying and distributing electricity to the Java-Bali area with a capacity of 60 MWe. However, this can run into a decrease in the efficiency and effectiveness of system performance due to energy losses in several geothermal power plant components during energy conversion. In this case, exergy analysis at PT. Pertamina Geothermal Energy Kamojang area Unit 4 direct-dry steam cycle was done on each component and state. This aims to know the energy and exergy stream and where it happened irreversibly at the component. The biggest irreversibility value occurred at the turbine and main condenser, with a value of 21,693.890 kW and 21,688.148 kW. The total irreversibility of all systems is 58,326.201 kW, while the total exergy inlet systems is 119,308.457 kW, so the value efficiency exergy obtained is 51.13%. Based on the environment as dead state analysis, an efficiency exergy value is inversely proportional to the irreversibility value and ascending environment temperature. System optimization was done with the genetic algorithm method, with variable values at the pressure wellhead and inlet turbine for the overall exergy efficiency value. The value obtained from optimization is 11.98 bar at the wellhead and 10.023 bar at the inlet turbine, and the overall efficiency exergy increased by 51.22%.

A new integration scheme for CO2 capture in low-rank coal fired power plants with energy savings

Integration of CO2 capture process into a fossil fuel fired power plant leads to an unavoidable efficiency loss. Thus, optimization of the integration scheme is of great necessity to reduce the efficiency loss. This study proposes a new integration scheme for a low-rank coal (LRC) fired power plant with CO2 capture system of solid amine-based sorbents, specifically including a steam cycle, a CO2 capture system and a LRC pre-drying process. By suitable system integration, the low-quality heat in the CO2 capture system could be used to replace the high-quality waste heat of flue gas for LRC pre-drying, thus achieving great energy savings. Compared to the conventional integration scheme, the thermal and exergy analyses show that the new integration scheme efficiently recovers the low-quality heat in the CO2 capture system to generate more power output and the corresponding efficiency loss is reduced by 2.66%. Economic analysis shows that the economic benefits from the new integration scheme outweigh the disadvantages of the investment increase, and the cost of electricity (COE) and the cost of CO2 avoided (COA) are reduced by 5.95 $/MWh and 8.32 $/tCO2.

The potential of retrofitting existing coal power plants: A case study for operation with green iron

Storing electrical energy for long periods and transporting it over long distances is an essential task of the necessary transition to a CO2-free energy economy. An oxidation–reduction cycle based on iron and its oxides represents a very promising technology in this regard. The present work assesses the potential of converting an existing modern coal-fired power plant to operation with iron. For this purpose, a systematic retrofit study is carried out, employing a model that balances all material and energy fluxes in a state-of-the-art coal-fired power plant. Particular attention is given to components of the burner system and the system’s heat exchanger. The analysis provides evidence that main components such as the steam generator and steam cycle can be reused with moderate modifications. Major modifications are related to the larger amounts of solids produced during iron combustion, for instance in the particle feeding and removal systems. Since the high particle densities and lower demand for auxiliary systems improve the heat transfer, the net efficiencies of iron operation can be one to two percentage points better than coal operation, depending on operating conditions. This new insight can significantly accelerate the introduction of this innovative technology by guiding future research and the development of the retrofit option.

Exergoecological Evaluation of Power Generation in Steam Cycles Fed by Biomass

One of the methods to reduce environmental impacts is to use renewable resources such as biomass or even waste. In this work, a novel power generation system in biomass-powered steam cycles was proposed, comprising biomass gasification, a steam turbine, a pump and a condenser. A biomass feedstock (rice husk) was used in the gasifier as input fuel. The devised system was analyzed taking into account the sustainability evaluation that includes thermodynamic and environmental parameters. An energetic, exergetic and exergoecological analysis was carried out. In addition, a detailed sensitivity analysis was performed to assess the effects of varying operating parameters on system efficiency. According to the results, the energy and exergetic efficiencies of the system had a value of 23,680% and 12,830%, respectively, where the boiler and the turbine presented the highest average environmental impact per input and output exergy. The components with the highest environmental impact index associated with exergy destruction were the condenser and the boiler, representing 99,82%, demonstrating profit margins in the formation of pollutants and exergy destruction. The entire system had a total ecological impact of 2,614 mPt/s and can be reduced mainly by improving its exergetic efficiency. Exergoecological assessments can be used to support power generation in complex cycles, especially to reduce the generation of environmental pollution.

A techno-economic assessment of the reutilisation of municipal solid waste incineration ash for CO2 capture from incineration flue gases by calcium looping

Waste-to-Energy (WtE) through municipal solid waste (MSW) incineration is a key waste management strategy to reduce the mass and volume of landfilled wastes, especially for land-constrained areas such as urban centres. However, this process releases large amounts of CO2 into the atmosphere and the ash that remains after burning, which contains a variety of metals and minerals, is often sent to the landfill after some metal recovery. In this study, the CaO containing ash is used to derive sorbents for the calcium looping (CaL) process for post-combustion CO2 capture and storage (CCS), and a techno-economic assessment was performed to preliminarily probe the feasibility of retrofitting a CaL plant using ash-derived sorbents to capture CO2 from a 200MWth WtE plant, as a possible means to decarbonise WtE plants. The analysis was performed through process modelling of the CaL plant using 4 different supplementary fuels in the calciner, namely, biomass charcoal (BC), solid recovered fuel (SRF), coal, and natural gas (NG). At the base purge ratio of 5%, all the cases show increases in the levelised cost of electricity (LCOE) over the base WtE, ranging from 184 (NG) to 246 (BC) USD/MWhe. The sale of additional electricity generated from the heat recovery steam cycle could slightly mitigates the capital intensiveness of the process, resulting in a levelised cost of carbon abatement (LCCA) range of USD 89 (SRF) to 184 (coal)/tCO2, which is competitive with other bioenergy with CO2 capture and storage (BECCS) technologies. The biogenic fuels also result in lower specific primary energy consumption per CO2 avoided (SPECCA) of 5.6 (BC) and 6.8 (SRF) MJLHV/tCO2, which are comparable to values from other CCS technologies and CaL implementation studies. Sensitivity analysis of 14 economic and process parameters reveals that further improvements can be achieved through optimisation of the energy intensive sub-processes, such as cryogenic air separation and CO2 compression and purification. Tighter solid heat integration (SHI) concepts were also modelled and are shown to effectively reduce fuel and O2 requirements by up to 22.2%, thereby lowering annualised costs by up to 11.9%. In addition, this paper highlights the importance of regulatory support through favourable policies such as higher carbon pricing and CO2 credit trading to push the development and adoption of negative emission technologies to meet global decarbonisation targets.

Plant and system-level performance of combined heat and power plants equipped with different carbon capture technologies

Installing carbon capture and storage (BECCS) capability at existing biomass-fired combined heat and power (bio-CHP) plants with substantial emissions of biogenic CO2 could achieve significant quantities of the negative CO2 emissions required to meet climate targets. However, it is unclear which CO2 capture technology is optimal for extensive BECCS deployment in bio-CHP plants operating in district heating (DH) systems. This is in part due to inconsistent views regarding the perceived value of high-exergy energy carriers at the plant level and the extended energy system to which it belongs. This work evaluates how a bio-CHP plant in a DH system performs when equipped with CO2 capture systems with inherently different exergy requirements per unit of CO2 captured from the flue gases. The analysis is based upon steady-state process models of the steam cycle of an existing biomass-fired CHP plant as well as two chemical absorption-based CO2 capture technologies that use hot potassium carbonate (HPC) and amine-based (monoethanolamine or MEA) solvents. The models were developed to quantify the plant energy and exergy performances, both at the plant and system levels. In addition, heat recovery from the CO2 capture and conditioning units was considered, as well as the possibility of integrating large-scale heat pumps into the plant or using domestic heat pumps within the local DH system. The results show that the HPC process has more recoverable excess heat (∼0.99 MJ/kgCO2,captured) than the MEA process (0.58 MJ/kgCO2,captured) at temperature levels suitable for district heating, which is consistent with values reported in previous similar comparative studies. However, using energy performance within the plant boundary as a figure of merit is biased in favor of the HPC process. Considering heat and power, the energy efficiency of the bio-CHP plant fitted with HPC and MEA are estimated to be 90% and 76%, respectively. Whereas considering exergy performance within the plant boundary, the analysis emphasizes the significant advantage the amine-based capture process has over the HPC process. Higher exergy efficiency for the CHP plant with the MEA capture process (∼35%) compared to the plant with the HPC process (∼26%) implies a relatively superior ability of the plant to adapt its product output, i.e., heat and power production, and negative-CO2 emissions. Furthermore, advanced amine solvents allow the BECCS plant to capture well beyond 90% of its total CO2 emissions with relatively low increased specific heat demand.

Design and Thermal-Hydraulic Evaluation of Integrated Steam Generator with Serpentine-Tube Configuration for Prevention of Sodium-Water Reaction

Although sodium-cooled fast reactors (SFRs) can have inherently enhanced safety features, there is a concern regarding unexpected events arising from a sodium-water reaction (SWR) in a Rankine cycle steam generator. Innovative concepts of integrated steam generators (ISGs), including an intermediate heat exchanger, have been suggested for eliminating an SWR by employing an intermediate fluid between liquid sodium and steam/water system. In this study, we propose an ISG designed with a novel tube configuration: a serpentine tube-type integrated steam generator (S-ISG). Furthermore, we developed a dedicated one-dimensional thermal-hydraulic analysis code for the specific design evaluation of the S-ISGs. The evaluation results are reported with reasonable explanations and compared with the results obtained using a conventional CFD tool to analyze local thermal-hydraulic characteristics that cannot be shown in the one-dimensional analyses. The proposed S-ISG has an inherent advantage for modularization as well as prevention of SWR; therefore, it is characterized by its ability to improve operational efficiency even in the case of repair, despite the low space efficiency. The results demonstrate that the component developed in this study can serve as an option to maintain cost efficiency while enhancing the public acceptability of an SFR.

Automated drainage system for thermoelectric power plant

<span lang="EN-US">The Chilca 2 thermoelectric power plant, located in the province of Lima, Peru, has an open cycle gas turbine and a combined cycle steam turbine, whose combined capacity is 112.8 MW (Mega Watts). This plant requires auxiliary equipment for its operation, which is why it consists of electrical systems, lubrication system, hydraulic ventilation, pumps, vacuum systems and drainage of condensate generated by the difference in temperature in the steam conductor. Said drainage system is inside a 5-meter-deep basement that, being exposed to the elements, is exposed to falling drops of water that are generated by the vapors that are released due to the difference in temperature, repeatedly flooding and exposing to hazards that affect the normal operation of the thermoelectric plant. The proposed solution is based on the philosophy of a feedback control system, which uses a programmable logic controller (PLC) Siemens 1214AC/DC/Relay programmable logic controller, which, through a frequency inverter, activates the drainage pumps; the frequency range at which the variator works is linked to a 4-position level sensor. The result shows that it was possible to activate the frequency variator in a controlled manner through frequencies of 10 Hz, 30 Hz </span><span lang="EN-US">and 60 Hz, in this way a sustained operation of the drainage system is guaranteed.</span>

Concept design, parameter analysis, and thermodynamic evaluation of a novel integrated gasification chemical-looping combustion combined cycle power generation system

Integrated gasification chemical-looping combustion (IGCLC) is a potential combustion technology with innate CO2 separation for solid fuels. Coupling this technology with coal-fired power plants is expected to greatly alleviate the high efficiency penalty induced by CO2 capture. This study proposes an innovative system called integrated gasification CLC combined cycle (IGCLCCC) that highly integrates a gasification system, a CLC system, a combined cycle, an ultra-supercritical steam cycle, and a CO2 capture system. In the proposed system, the oxygen-depleted stream from air reactor and flue gas from fuel reactor enter the combined cycle and ultra-supercritical steam cycle, respectively, for power generation. The energy and mass balances of the proposed system are determined by process simulation. The relationship between the performance of subsystems and system efficiency is studied by parameter analysis. Results indicate that the net efficiency penalty (0.3 percentage points) of the proposed system is 4.3 to 13.2 percentage points less than those of the conventional CO2 capture power plants, and the power consumption of specific CO2 capture is minimized to 8.3 kWeh/t. Besides, its net efficiency is as high as 45.0%, which is comparable to that of the natural gas combined cycle power plant with a 90% CO2 capture rate. This work provides a new sight into the design of the low-carbon and efficient power generation system.

Energy, exergy, economic and environmental (4-E) analyses of plasma gasification steam cycle integrated molten carbonate fuel cell for hydrogen and power co-generation based on residual waste feedstocks

Two newly emerging technologies: (a) plasma gasification and (b) molten carbonate fuel cell (MCFC) are integrated for hydrogen and power production for various system configurations. Due to the emission concerns of fossil fuels, wastes such as refused derived fuel (RDF) is chosen as feedstock. The simulation of the power plants is performed using Aspen plus and consequently, 4-E (energy, exergy, economic and environmental) analyses are executed. The highest energy and exergy efficiencies attained are 54.12% and 52.02% for the system Syngas:CH4 [PSA: MCFC], respectively. Moreover, the cost of electricity considering all the configurations is ranged between 77.48 and 107.93 $/MWh while the LCOH is between 1.01 and 3.94 $/kg. Likewise, introduction of MCFC for 0:100 [PSA: MCFC] case reduced the annual CO2 emissions ∼5 times than of 100:0. Therefore, the 4-E analyses reported that integrated plasma gasification with MCFC introducing waste as feed could possibly favour H2 and power co-generation and a cleaner environment.

Techno-economic comparison of DEMO power conversion systems

The transition to low-carbon technologies lies in the support of modern energy sources, which are also represented by fusion power plants. One of the first fusion power plants will be the European Union DEMOnstration fusion power plant. Among the key attributes that influence the entire design of this power plant, belongs the power conversion system. In addition to the classic Rankine steam cycle, it is possible to use different cooling media, such as supercritical CO2 in the Brayton cycle. The advantages of supercritical CO2 are mainly in the compactness of the power conversion system, that is, lower investment costs for the entire power plant while maintaining the high efficiency of the entire power plant. The key question that can influence the choice of the power conversion system is the levelized cost of electricity. The direct cost of the supercritical CO2 cycles is lower compared to the Rankine steam cycles, in general. On the other hand, supercritical CO2 cycles for the DEMOnstration fusion power plant offer slightly lower efficiency (by approximately 1.5 percentage points), which negatively influences supercritical CO2 cycles levelized cost of electricity by 10%–20% against Rankine steam cycles.