Plant Capacity Factor Research Articles

Novel Recuperated Power Cycles for Cost-Effective Integration of Variable Renewable Energy

The ongoing transition to energy systems with high shares of variable renewables motivates the development of novel thermal power cycles that operate economically at low capacity factors to accommodate wind and solar intermittency. This study presents two recuperated power cycles with low capital costs for this market segment: (1) the near-isothermal hydrogen turbine (NIHT) concept, capable of achieving combined cycle efficiencies without a bottoming cycle through fuel combustion in the expansion path, and (2) the intercooled recuperated water-injected (IRWI) power cycle that employs conventional combustion technology at an efficiency cost of only 4% points. The economic assessment carried out in this work reveals that the proposed cycles increasingly outperform combined cycle benchmarks with and without CO2 capture as the plant capacity factor reduces below 50%. When the cost of fuel storage and delivery by pipelines is included in the evaluation, however, plants fired by hydrogen lose competitiveness relative to natural gas-fired plants due to the high fuel delivery costs caused by the low volumetric energy density of hydrogen. This important but uncertain cost component could erode the business case for future hydrogen-fired power plants, in which case the IRWI concept powered by natural gas emerges as a promising solution.

An exergoeconomic exploration of solar-geothermal integration

This study investigates the integration of a solar field using parabolic trough collectors into a binary geothermal plant with isopentane as the secondary fluid, employing the Engineering Equation Solver (EES) and System Advisor Model (SAM) for analysis. The investigation evaluates the performance of two Heat Transfer Fluids (HTFs)—Therminol VP-1 and molten salts—in hybrid configurations, emphasizing variations in solar field size and thermal storage capabilities. First, a direct correlation has been identified between second law efficiency and Levelized Cost of Energy (LCOE), demonstrating that increases in thermal storage from 0 to 12 h result in LCOE increments up to 33%. The study highlights that molten salts, achieving the lowest LCOE of 0.075 USD/kWh, enhance net energy output by up to 15.55% compared to Therminol VP-1, particularly under extended storage conditions. Additionally, the integration of larger solar fields and increased storage capacities significantly impacts the costs of high-pressure steam production, which rise from 33.02 to 50.55%. By expanding plant capacity factors up to 97% for Therminol and 93% for molten salts with optimal thermal storage and solar multiple configurations, the study demonstrates that molten salts enable greater annual power output despite lower capacity factors. This comprehensive analysis underscores the pivotal role of second law analysis in optimizing the economic and operational efficiencies of hybrid geothermal-solar power systems, offering significant insights for enhancing the design and economic viability of renewable energy integrations.

The role of direct air carbon capture in decarbonising aviation

Aviation is the most energy and carbon intensive mode of transport and the most difficult to decarbonise. Greenhouse gas emissions from aviation comprise around 2 % of global totals. The low energy density of current battery technologies presents significant technical challenges for use in the aviation sector. This study compares two use cases of direct air carbon capture to decarbonise aviation, from an economic and environmental perspective. The first is where continued use of fossil jet fuel is offset by capturing and sequestering CO2 from the atmosphere. The second is where CO2 captured from the atmosphere is used as a feedstock, in conjunction with hydrogen from electrolysis, to produce a synthetic jet fuel. Depending on input parameters such as electricity cost and plant capacity factor, the levelised cost of carbon capture and storage falls between €160/tCO2 to over €1300/tCO2, while the cost of synthetic fuel production falls between €2/kg of fuel and €12/kg of fuel. Due to the high electricity inputs for hydrogen production, the use of direct air capture to produce a synthetic jet fuel results in 9.8 times more greenhouse gas emissions than sequestering it for a given electricity emissions intensity. The results presented in this study indicate that offsetting continued fossil jet fuel use using direct air capture has the lowest cost of abatement but there are overall sustainability concerns surrounding this pathway. Furthermore, the estimated cost increases associated with decarbonisation may indicate that the age of low-cost flying will not persist in a net-zero future.

Modeling of Capacity Factor in Rembang Coal-Fired Steam Power Plant Using Regression Modelin

Coal-Fired Steam Power Plant (PLTU) Rembang is an important power plant in the Central Java electricity system. Like other coal-fired steam power plants, fuel cost is the most significant expense when operating the PLTU Rembang. During the 2019-2021 period, the average fuel cost was 73.88% of total costs. One of the ways to reduce fuel costs is by improving the accuracy of fuel demand planning. Fuel procurement planning is very dependent on the projected amount of electricity sales from power plant, which is largely determined by the power plant's Capacity Factor (CF). However, PLTU Rembang does not have any CF prediction modeling. This research developed and compared four prediction models: random forest regression, support vector regression, multiple polynomial regression, and multiple linear regression. Based on the comparison of validation from the four prediction model with MAPE and R-squared parameters, the multiple linear regression models is the best model, with the lowest MAPE of 7.83% and the highest R-squared of 0.8814. This multiple linear regression model can be used to predict the CF of PLTU Rembang in the future so that fuel demand planning is more accurate.

Offshore Wind Power Resource Assessment in the Gulf of North Suez

Growing population, industrialization, and power requirements are adversely affecting the environment through increased greenhouse gases resulting from fossil fuel burning. Global greenhouse gas mitigation targets have led nations to promote clean and self-renewable sources of energy to address this environmental issue. Offshore wind power resources are relatively more attractive due to high winds, less turbulence, minimal visualization effects, and no interaction of infrastructure. The present study aims at conducting an offshore wind power resource assessment (OWPRA) at some locations in the Gulf of North Suez. For this purpose, the long-term hourly mean wind speed (WS) and wind direction above mean sea level (AMSL), as well as temperature and pressure data near the surface, are used. The data is obtained from ERA5 (fifth generation global climate reanalysis) at six (L1–L6) chosen offshore locations. The data covers a period of 43 years, between 1979 and 2021. The WS and direction are provided at 100 m AMSL, while temperature and pressure are available near water-surface level. At the L1 to L6 locations, the log-term mean WS and wind power density (WPD) values are found to be 7.55 m/s and 370 W/m2, 6.37 m/s and 225 W/m2, 6.91 m/s and 281 W/m2, 5.48 m/s and 142 W/m2, 4.30 m/s and 77 W/m2, and 5.03 and 115 W/m2 and at 100 m AMSL, respectively. The higher magnitudes of monthly and annual windy site identifier indices (MWSI and AWSI) of 18.68 and 57.41 and 12.70 and 42.94 at the L1 and L3 sites, and generally lower values of wind variability indices, are indicative of a favorable winds source, which is also supported by higher magnitudes of mean WS, WPD, annual energy yields, plant capacity factors, and wind duration at these sites. The cost of energy for the worst and the best cases are estimated as 10.120 USD/kWh and 1.274 USD/kWh at the L5 and L1 sites, corresponding to wind turbines WT1 and WT4. Based on this analysis, sites L1, L3, and L2 are recommended for wind farm development in order of preference. The wind variability and windy site identifier indices introduced will help decision-makers in targeting potential windy sites with more confidence.

Resources and Development Perspectives of Geothermal Energy in Central and South America

It is widely recognized that a large part of Central America and the whole Andean sector in South America, because of their geodynamic and volcanological conditions, have a very large geothermal potential. However, no systematic attempt has been made so far to quantify this potential, in order to provide an estimate of the reserves which are available in this region for the production of electric energy and for direct applications. The scope of the present paper is to make a first contribution in this direction. After a summary of the geological framework of the region, a categorization is made of Central and South America into type A, B and C "provinces" in accordance with a ranking of interest in descending order, depending on the expected quality of their geothermal resources. For the six type A provinces singled out in the whole region, and for the 15 preferential sectors located in them, a quantitative assessment to 3 km depth is made of the accessible resource bases. Furthermore, for each of the sectors above, the estimation is provided of the "potential reserves," subdivided into two main groups: high temperature reserves (T> 160°C), and intermediate-to-low temperature reserves (T< 160°C). For the first group, moreover, an estimation is made in terms of electric energy producible and capacity installable. The results of the estimation indicate that the minimum geothermoelectric potential of Central and South America altogether is of the order of 141-167 GWye (gigawatt- years electric), which corresponds to 5600-6700 MWe for a 25 year production period at a 100% plant capacity factor. Based on this very attractive, yet conservative, estimate, the present situation of the geothermal exploration in Central and South America is then reviewed, and the possible development targets are discussed in the light of medium- and long-term perspectives.

Role of wind energy in sustainable development in coal-based systems: Case of Kosovo

Most of the countries in South-East Europe primarily depend on fossil fuels to cover their energy demands. The paper discusses the future perspective on wind energy in the country, where over 90% of energy is generated in coal-fired thermal power plants. Given the energy crisis, that has gripped the world, the possibility of covering the increased energy demand is being studied, especially during the winter. Based on current trends on energy generation, with just symbolic participation of wind, hydro and solar energy, the potential for maximization of the use of wind energy is considered, which means the use of each identified adequate location throughout the country. The main advantage here is that the maximum energy produced by wind is during winter when demand increases. This is important to know that Kosovo faces significant heating problems and its demand is covered with electricity. Analyzes prove that the country has a generous wind capacity, which reduces to a certain extent the need to import and even enables the export of energy under certain conditions. The potential installation capacity in Kosovo is 510.9 MW, of which 32.4 MW is currently in operating conditions. From the analysis made for the current wind farm in operation, the plant capacity factor is 31.8%. The study of the results indicates a direct correlation between the increase in load during the winter season and the electricity production by wind farms, thereby, the energy demand can be sufficiently covered.

Performance of an adiabatic pre-cooling system for concentrating solar power plants in arid areas

An adiabatic pre-cooling (AP) mechanical draft system for concentrating solar power (CSP) plants in arid regions is investigated. The cooling system amalgamates advantages of both dry and adiabatic cooling into a single system. We aim to demonstrate the system’s potentially advantageous spray water consumption characteristics and cooling performance, as it compares to conventional dry and wet-cooling, for arid-area CSP plants. This is done by investigating the AP system’s performance in isolation, via simulation and experimental validation, and a case study simulating performance of a 100 MW arid-area CSP plant with AP, dry and wet-cooling. Our primary contributions entail: analysing AP, dry and wet-cooling and CSP performance with hourly temporal resolution, from which annual hourly statistical summaries are presented, and quantifying AP and CSP performance in response to AP target saturation levels. Our performance assessment ambit includes: power cycle thermal efficiency, cooling or spray water consumption, gross output, parasitic consumption, plant capacity factor and intensive capital expenditure. Our main results show that: increased AP saturation beyond ≈80 % yields insignificant power cycle thermal efficiency enhancement, with gross output stabilising at >70 % saturation. Nonetheless, at 99 % saturation, AP boosts power cycle thermal efficiency by 1.61 % above dry-cooling, consumes 14.61 % less water than wet-cooling, and can increase power block capital cost by 14.19 % before the plant’s intensive capital expenditure equals that with dry-cooling. Furthermore, a 10 percentage point increase in AP saturation level increases the intensive cooling water consumption by ≈26.75 % on average, reduces the cooling parasitic energy consumption by ≈5.37 % on average, and raises the plant capacity factor by ≈0.35 % on average.

Assessing Predictions of Australian Offshore Wind Energy Resources from Reanalysis Datasets

Offshore wind farms are a current area of interest in Australia due to their ability to support its transition to renewable energy. Climate reanalysis datasets that provide simulated wind speed data are frequently used to evaluate the potential of proposed offshore wind farm locations. However, there has been a lack of comparative studies of the accuracy of wind speed predictions from different reanalysis datasets for offshore wind farms in Australian waters. This paper assesses wind speed distribution accuracy and compares predictions of offshore wind turbine power output in Australia from three international reanalysis datasets: BARRA, ERA5, and MERRA-2. Pressure level data were used to determine wind speeds and capacity factors were calculated using a turbine bounding curve. Predictions across the datasets show consistent spatial and temporal variations in the predicted plant capacity factors, but the magnitudes differ substantially. Compared to weather station data, wind speed predictions from the BARRA dataset were found to be the most accurate, with a higher correlation and lower average error than ERA5 and MERRA-2. Significant variation was seen in predictions and there was a lack of similarity with weather station measurements, which highlights the need for additional site-based measurements.

Performance Evaluation of a Hydro-Power Plant

Abstract: The electrical power generation of any country drives the economy of that country. Sufficient electrical power supply plays an important role for industrial development and growth of any country. The epileptic state of electricity supply in Nigeria arising partly from power generation plants’ inability to operate at installed capacity led to the investigation and evaluation of hydro – power plant operational performances in a bid to suggest ways the generation capacity of these plants can be well utilized. This study evaluated the performance of Shiroro Hydro-Power Plant on monthly basis employing the relevant fluid mechanics models; the appropriate performance indices such as plant efficiency, capacity factor, utilization factor and overall efficiency were evaluated. Data obtained from the plant inventory records include daily power generation, daily hydrological data such as water discharge rate and gross operating head. The net head, the hydraulic power and the theoretical power developed by the flowing water were estimated to aid the evaluation of the plant performance indices. The results of the study for the period under review showed that the plant efficiency for 2019 varied from 43.56% to 85.83% with an average of 65.65% and 41.81% to 86.66% with an average of 65.99% for 2020. The capacity factor of the plant for 2019 varied from 25.74% to 66.78% with an average of 47.85% and 22.65% to 67.15% with an average of 49.44% for 2020 against standard practices of 50% to 80%. The plant utilization factor for 2019 varied from 42.51% to 79.95% with an average of 66.1% and 29.38% to 73.35% with an average of 62.44% for 2020 against standard practices of over 95%. From these results, it can be concluded that the generating plants were underutilized. This is due to inadequate routine maintenance, equipment fault development, low load demand from the national grid and low headwater elevation (water drought). Evaluation of the overall efficiency of the plant showed an average of 55.74% for 2019 and an average of 56.02% for 2020 against standard practices of 80% and above. This indicated a shortfall of 24.26% and 23.98% and above of energy conversion from the hydraulic power developed by the falling water. Also, out of the 600MW installed capacity and a possible energy consumption of 5,270,400MWh annually, only 2,520,243MWh of energy was consumed from the plant for 2019 and 2,606,206MWh for 2020. The overall results revealed that the potential capacity of the generating plant remains unutilized. Measures to improve the performance indices and overall efficiency of the plant have been suggested in this study.

Cost Analysis of Implementing In-Pipe Hydro Turbine in the United Arab Emirates Water Network

Water transmission lines have potential reserved energy, which is usually lost. Therefore, targeting this clean energy to produce electricity to power up the auxiliaries and utilities of water plants or consumers is financially and environmentally beneficial. This paper aims to investigate the feasibility of installing an inline hydropower system in an existing transmission water pipe. It analyzes the feasibility of implementing a mini-hydropower plant in the transmission line of Liwa’s reservoir in the UAE. The maximum possible power harvested is 218.175 kW at the given water flow rate and net head. The payback period and the return on investment are analyzed based on different scenarios related to capital investment, operation, maintenance cost, and plant capacity factor. It is found that the payback period ranges between one to six years, where the return on investment can be as high as 85%. Furthermore, the expected CO2 emissions saving for this project is calculated to be between 395 and 1939 tons per year.

Performance evaluation of grid-connected photovoltaic system for Kuttiady village in Kerala, India.

To combat the adverse environmental effects of fossil fuel burning for power generation and to conserve it for strategic use, new, clean, and renewable energy sources are being utilized for power generation. The study presents techno-economic analysis of a grid-connected solar photovoltaic (PV) power plant to partially meet the energy consumption of the people of Kuttiady village in Kerala, India. The proposed 2315.5kW installed capacity PV is found to be feasible for the village and can produce 3878.3 MWh of energy annually while the demand is 4044.86 MWh at a plant capacity factor of 19.1% and cost of energy of 290.73 $/MWh. The performance of the proposed PV plant measured in terms of final yield (4.59h), reference yield (5.64h), and performance ratio (82%) is compatible and even higher with many such plants in India and other countries. Economic sensitivity analysis is also performed by varying the interest, discount, and inflation rates to check their effect on cost of energy, benefit cost ratio, and payback period. As the interest and discount rates decrease, the cost of energy and payback period also decreases while benefit cost ratio increases. The proposed plant can help in avoiding around 785 tons of greenhouse gases entering the local atmosphere of the Kuttiady village.

The marginal abatement cost of co-producing biomethane, food and biofertiliser in a circular economy system

Biomethane from anaerobic digestion of agricultural feedstock is a versatile energy vector for decarbonising agriculture, heavy transport and heat. To lower costs and increase the emission-savings potential, photosynthetic biogas upgrading, cogenerating microalgae with biomethane is investigated here. In a first-of-its-kind work, this paper reports the enviro-economic performance and the marginal (CO2) abatement cost (MAC) of a polygeneration plant co-producing energy (biomethane), food (Spirulina powder) and bio-fertiliser (digestate) from agricultural feedstock using photosynthetic biogas upgrading at small, medium, and industrial scales. A negative MAC at industrial scale (3 MW biomethane), highlighted the environmental and economic benefit (net present value > 11.5 million€ and internal rate of return >40%) of the process as a low-carbon technology over conventional biomethane production processes at a biomethane sale price of 3 c€/kWh (comparable to natural gas). The operational expenditure, including the cost of the Spirulina cultivation medium and the plant capacity factor had the highest influence on its profitability. Replacing beef as a complete food with Spirulina powder maximised the emission savings rather than replacing beef protein with Spirulina protein. Economic allocation as opposed to energy allocation ensured that the levelised cost and specific greenhouse gas emissions of biomethane (<5 c€/kWh; < 3.5 gCO2-eq/MJ), Spirulina powder (<68 €/kg; < 4 kgCO2-eq/kg) and digestate (<5.60 €/tonne; < 0.41 kgCO2-eq/kg-nitrogen) are better than market-available alternatives across all scales. Trading emission savings from biomethane in the European Union emission trading system should allow the financial viability of smaller-scale processes by 2030.

Development of Geothermal Equipment for and Construction of the Verkhne-Mutnovsk and Mutnovsk Geothermal Power Plants

Modern geothermal power generation systems have reached considerable commercial maturity and are successfully competing with other energy generation methods. Geothermal energy has a number of advantages: low cost of electricity, independence from climatic conditions, and high environmental friendliness. The geothermal power plant (GeoPP) capacity factor is well above the levels of this indicator for energy technologies that use other renewable energy sources. In Russia, there are prerequisites for effective use of geothermal energy for supplying power to remote and isolated regions that have huge reserves of geothermal resources. The article summarizes and analyzes the experience gained from development of domestic geothermal equipment and construction of modern geothermal power plants: the Verkhne-Mutnovsk GeoPP and Mutnovsk GeoPP. The geothermal fluid features influencing the design and process solutions applied in developing a GeoPP are considered. The principles of designing the block-modular Verkhne-Mutnovsk GeoPP are described, and the advantages and high efficiency of the steam treatment plant for ensuring reliable operation of the Verkhne-Mutnovsk GeoPP and Mutnovsk GeoPP turbine units are noted. The design features of the turbine flow paths at the Mutnovsk GeoPP with a capacity of 25 MW and Verkhne-Mutnovsk GeoPP with a capacity of 4 MW are given. The characteristics of unique air-cooled condensers for the Verkhne-Mutnovsk GeoPP and direct-contact condensers for the Mutnovsk GeoPP are presented. The further development lines of the Verkhne-Mutnovsk and Mutnovsk GeoPPs have been determined.

Life cycle assessment of geothermal plants targeting the lower carboniferous limestone reservoir in northern Belgium

The majority of heating in Belgium and Europe originates from natural gas. Deep geothermal heating (DGH) can provide a low carbon alternative to fossil-fired heating. However, the site-specific geological conditions are determinant for DGH development, requiring in-depth assessments to fully understand the potential environmental impacts. This study presents a comprehensive environmental assessment of DGH in Northern Belgium, where growing interest in DGH is observed. Based on an already developed DGH plant, three scenarios are defined depicting current and future DGH developments in Northern Belgium. Twelve Life Cycle Assessment (LCA) impact indicators and the inter-connected geo-technical aspects are investigated. An LCA on the three scenarios is performed, followed by a detailed hotspot analysis. Also, the impact variability is estimated with global sensitivity analysis, followed by variance-based global sensitivity analysis to assess this variability. The global warming (GW) impact of the already developed DGH plant is relatively low (27 kg CO2-eq/MWhth) and is driven (>80%) by the electricity consumed to run the pumps and the well development. The GW impact is lower for the expected future DGH development (11 kg CO2-eq/MWhth) because of shallower reservoir conditions and better permeability that lead to lower pumping needs. A wide impact variability is found, governed (>80%) by the plant capacity, capacity factor and pumping needs. The GW impact ranges from 4 to 130 kg CO2-eq/MWhth. Utilization of DGH in Northern Belgium can lead to a decarbonized heating mix. The environmental impacts of DGH can be reduced by exploiting shallower reservoirs with better permeability to reduce the impacts of well development and the pumping needs of the plant and by supplying the plant with renewable energy sources.

Negative emission power plants: Techno-economic analysis of a biomass-based integrated gasification solid oxide fuel cell/gas turbine system for power, heat, and biochar co-production—part 2

In our previous work (Part I), we evaluated the thermodynamic models of the biomass-fed integrated gasification solid oxide fuel cell system with a carbon capture and storage (BIGFC/CCS) unit. In this work (Part II), the techno-economic analysis of the proposed negative emission power plants is carried out. Levelized cost of electricity, net present value (NPV), payback period, internal rate of return (IRR), and levelized cost of negative carbon (LCNC) are the key economic parameters evaluated. The results of a series of sensitivity analysis show the impact of gasification agents and stepwise increase in biochar co-production on the performance of the system. The total overnight cost is estimated to be 6197 $/kW and 5567 $/kW for the air and steam-oxygen gasification BIGFC/CCS systems, respectively. Steam-oxygen gasification is found to be more economically beneficial than air gasification one for all of the cases studied. Economically viable biochar co-production cases are identified to ascertain the influence of capital cost, operating cost, biomass cost, plant capacity factor, and tax. Moreover, the effect of the carbon credit scenario on the economic indicators is also reported. The results show that the most effective economic performance from the steam-oxygen gasification case reported an NPV of 3542 M$, an IRR of 24.2%, and a payback period of 3.3 years, with an LCNC of -322.5$/t of CO2. Compiling the results from Part I and Part II shows that it is easier to achieve negative emission using the steam-oxygen gasification of a BIGFC/CCS system. These results are expected to be helpful for stakeholders in identifying appealing negative emissions power plant projects for near and long-term future investments.

Net-metering and Feed-in-Tariff policies for the optimum billing scheme for future industrial PV systems in Bangladesh

In this paper, the economic sustainability of net billing and feed-in-tariff (all energy buy/sell) method is analyzed in comparison with the current net-metering for the industrial PV systems in Bangladesh. Three billing methods are compared according to plant capacity factor, excess energy transfer, levelized cost of energy (LCOE), net present value (NPV), payback period, and profitability index (PI) for the analysis of optimum billing scheme. The highest plant capacity factor and minimum LCOE are found for the large PV system in Chattogram. Out of three methods, all energy buy/sell exhibits the NPV which is USD 5.85 million and PI of 2.54 at the minimum 4.9 years discounted payback time for the large PV system in Chattogram. The sensitivity analysis of solar irradiation at six other regional areas, bill escalation rate, and discount factor is performed to observe the impact on annual energy production and NPV. For both systems, all three assessed methods are found economically feasible, but the net metering is attained as the least profitable in comparison with net billing and all energy buy/sell schemes. From various analyses, it is found that the adaption of these two schemes in the present guideline can enhance industrial PV production in Bangladesh.

Implications of HALEU fuel on the design of SMRs and micro-reactors

Since the construction of the first commercial nuclear power plant in 1957, the nuclear power industry has operated under the philosophy of economy of scale - the idea that increased power plant size accounts for higher economic efficiency. However, there has been a recent shift in direction; small modular reactors (SMRs) and micro-reactors are being considered as potentially wise investments for commercial power producers in that they can provide advantages that large-scale reactors may not possess in terms of reactor safety and investment risk. However, this may come at the risk of a higher levelized cost of electricity (LCOE). LCOE may be reduced by enriching the fuel passed its regulated limit of 5 wt% (w/o) 235U. The high assay low-enriched uranium (HALEU) fuel (5–20 w/o 235U) is introduced to increase the plant capacity factor, which thereby decrease fuel supply costs and reduce the LCOE. While decreasing plant LCOE seems like a clear advantage, several issues may result from increasing enrichments to the HALEU level in an SMR or micro-reactor design. This paper aims to shed light on these issues and address how they may affect the overall reactor design by using HALEU fuels in these reactors.This paper first discusses the notable effects on a reactor design with higher enrichment, then analyzes a SMR case study based on the NuScale’s 160 MWth SMR design. The case study reveals that the SMR with higher enriched fuel was able to double both fuel burnup and cycle time with an average core enrichment of 8.34 w/o and a maximum average assembly enrichment of 9.10 w/o. Moreover, this higher enriched core was found to operate with a maximum global peaking factor of 1.86, well below the published limit of 2.0. Likewise, the maximum axial flux offset of −2.4% and the maximum boron concentration of 1757 ppm both remain within their respective safety constraints. Notable fission poisons, such as 149Sm and 135Xe, were also found to sharply increase in the HALEU core. Additionally, the average fuel temperature and peak cladding temperature fell within their respective safety constraints. Core-averaged flux, fluence, cladding creep, and post-shutdown decay heat were also investigated. Lastly, the higher enriched core was found to reduce LCOE by approximately 1.23 $/MWh.

Performance evaluation of a 20 MW grid-coupled solar park located in the southern oceanic environment of Ghana

In line with government efforts to increase renewable energy in the energy generation mix to 10 percent by the year 2030 and to promote cleaner production in the power sector, ambitious efforts are being made to promote the implementation of utility-scale solar PV plants with ample policy backing. However, performance information is not readily available since implemented large-scale projects are few. This study examines the performance characteristics of a 20 MW grid-tied solar PV plant located about 2 km away from the Gulf of Guinea at the Southern part of Ghana. The study uses a combination of PVsyst simulation and analysis of monitored data spanning the year 2018. The site meteorological data was obtained through NASA satellite and Meteonorm 7.1 station. Monitored data analysis showed that the power plant delivered a total annual energy of 26,480 MWh to the utility grid, whilst simulations gave total annual energy of 29,154 MWh. The final PV array yield values of 3.68 kWh/kWp/d and 4.06 kWh/kWp/d were obtained from the monitored and predicted analysis. Monitored data analysis gave plant performance ratio and capacity factor values of 72.8% and 15.1% whilst simulations produced 80.2% performance ratio and 16.6% capacity factor. The actual and simulated annual average system losses recorded were 0.056 h/d and 0.065 h/d, and the monitored and predicted overall system efficiencies obtained were 11.39% and 12.32%. Carbon emissions savings analysis revealed that the power plant saved 12,181 metric tons in the year 2018. The study gives an insight into valuable performance statistics, seasonal and year-round response relative to the coastal southern part of Ghana. The monitored data and operating experience of the PV system can be applied for the deployment of future large-scale projects in the southern part of Ghana, including other oceanic tropical climate regions in the world.

Thermal energy storage with phase change materials in solar power plants. Economic analysis

Thermal energy storage (TES) increases concentrating solar power (CSP) plant capacity factors, but more important, improves dispatchability; therefore, reducing the capital cost of TES systems is very important to reduce cost of energy and serve as an enabler for commercial solar power plants. After presenting the concept of a novel cascade PCM configuration of CSP and demonstrating it energy efficiency, it is needed to develop a thoughtful economic evaluation of the concept. The goal of this paper was to investigate this system through annual modelling, engineering procurement company price quotes, and levelized cost metric comparison with a baseline case, the commercial two-tank molten salt storage system. Simulation results show that this new PCM concept decrease levelized costs of storage. The baseline of using shell and tube heat exchangers for PCM storage offers a reduction in capital and levelized cost, but this paper also shows that there are further cost reduction possibilities, as shown in the scenarios presented here, such as thermal conductivity enhancement, encapsulation of the PCM, or modification of the material to improve its thermal properties. Therefore, although the basic shell and tube PCM system has been shown to offer a cost savings, the 1.8% reduction in LCOE may not be worth the risk of further development. The shell and tube system should be a jumping off point to more appropriate technologies. The variants studied are likely to yield cost reductions in cost performance quotient (CPQ) as high at 80% and in LCOE as high as 10%, representing an unprecedented and valuable avenue of CSP plant cost reduction.