107 results found
Olympios AV, Aunedi M, Mersch M, et al., 2022, Delivering net-zero carbon heat: Technoeconomic and whole-system comparisons of domestic electricity- and hydrogen-driven technologies in the UK, Energy Conversion and Management, Vol: 262, ISSN: 0196-8904
Proposed sustainable transition pathways for moving away from natural gas in domestic heating focus on two main energy vectors: electricity and hydrogen. Electrification would be implemented by using vapour-compression heat pumps, which are currently experiencing market growth in many countries. On the other hand, hydrogen could substitute natural gas in boilers or be used in thermally–driven absorption heat pumps. In this paper, a consistent thermodynamic and economic methodology is developed to assess the competitiveness of these options. The three technologies, along with the option of district heating, are for the first time compared for different weather/ambient conditions and fuel-price scenarios, first from a homeowner's and then from a whole-energy system perspective. For the former, two-dimensional decision maps are generated to identify the most cost-effective technologies for different combinations of fuel prices. It is shown that, in the UK, hydrogen technologies are economically favourable if hydrogen is supplied to domestic end-users at a price below half of the electricity price. Otherwise, electrification and the use of conventional electric heat pumps will be preferred. From a whole-energy system perspective, the total system cost per household (which accounts for upstream generation and storage, as well as technology investment, installation and maintenance) associated with electric heat pumps varies between 790 and 880 £/year for different scenarios, making it the least-cost decarbonisation pathway. If hydrogen is produced by electrolysis, the total system cost associated with hydrogen technologies is notably higher, varying between 1410 and 1880 £/year. However, this total system cost drops to 1150 £/year with hydrogen produced cost-effectively by methane reforming and carbon capture and storage, thus reducing the gap between electricity- and hydrogen-driven technologies.
Al Kindi A, Aunedi M, Pantaleo A, et al., 2022, Thermo-economic assessment of flexible nuclear power plants in future low-carbon electricity systems: Role of thermal energy storage, Energy Conversion and Management, Vol: 258, ISSN: 0196-8904
The increasing penetration of intermittent renewable power will require additional flexibility from conventional plants, in order to follow the fluctuating renewable output while guaranteeing security of energy supply. In this context, coupling nuclear reactors with thermal energy storage could ensure a more continuous and efficient operation of nuclear power plants, while at other times allowing their operation to become more flexible and cost-effective. This study proposes options for upgrading a 1610-MWel nuclear power plant with the addition of a thermal energy storage system and secondary power generators. The total whole-system benefits of operating the proposed configuration are quantified for several scenarios in the context of the UK’s national electricity system using a whole-system model that minimises the total system costs. The proposed configuration allows the plant to generate up to 2130 MWel during peak load, representing an increase of 32% in nominal rated power. This 520 MWel of additional power is generated by secondary steam Rankine cycle systems (i.e., with optimised cycle thermal efficiencies of 24% and 30%) and by utilising thermal energy storage tanks with a total heat storage capacity of 1950 MWhth. Replacing conventional with flexible nuclear power plants is found to generate whole-system cost savings between £24.3m/yr and £88.9m/yr, with the highest benefit achieved when stored heat is fully discharged in 0.5 h. At an estimated cost of added flexibility of £42.7m/yr, the proposed flexibility upgrades to such nuclear power plants appears to be economically justified with net system benefits ranging from £4.0m/yr to £31.6m/yr for the examined low-carbon scenarios, provided that the number of flexible nuclear plants in the system is small. This suggests that the value of this technology is system dependent, and that system characteristics should be adequately considered when evaluating the benefits of diffe
Bianco N, Mauro AW, Mauro GM, et al., 2022, A semi-empirical model for de-watering and cooling of leafy vegetables, Applied Thermal Engineering, Vol: 208, ISSN: 1359-4311
This paper presents a semi-empirical model for mass and heat transfer applied to de-watering and cooling of fresh leafy vegetables. This process aims at optimizing vegetables’ moisture content and temperature through the interaction with conditioned airflows to ensure proper storage and preservation. It is implemented in different modules – i.e., a first set of hot modules with hot air, a second set of cold modules with cold air – allowing to remove water from the vegetables and to achieve the desired temperature. A dedicated transfer model is developed to follow the evolution of the liquid droplets on the leaves during the process. It is based on water mass and energy balances on product and air sides, where the bed of leaves is treated as a porous medium. The mass and heat transfer coefficients are calibrated by comparison with experimental data. The model is validated with real data from the field, and a parametric analysis is implemented to show its potential application to optimize the process. The calibrated model presents satisfactory reliability – less than ±1.0 °C as average error for output temperature – according to the uncertainty of the approaches available in literature, thereby ensuring a robust performance assessment. This can support the process application in several fields of the agri-food industry with significant quality and productivity improvements. Finally, the model can be used to develop digital twins to foster the ongoing digitalization of the agri-food sector with a view to sustainability.
Romanos P, Al Kindi A, Pantaleo AM, et al., 2022, Flexible nuclear plants with thermal energy storage and secondary power cycles: Virtual power plant integration in a UK energy system case study, e-Prime - Advances in Electrical Engineering, Electronics and Energy, Vol: 2, Pages: 1-24, ISSN: 2772-6711
Electricity markets are fast changing because of the increasing penetration of intermittent renewable generation, leading to a growing need for the flexible operation of power plants to provide regulation services to the grid. Previous studies have suggested that conventional power plants (e.g., nuclear) may benefit from the integration of thermal energy storage (TES), as this enables greater flexibility. In conventional Rankine-cycle power plants, steam can be extracted during off-peak periods to charge TES tanks filled with phase-change materials (PCMs); at a later time, when this is required and/or economically favourable, these tanks can feed secondary thermal power plants to generate power, for example, by acting as evaporators of organic Rankine cycle (ORC) plants. This solution offers greater flexibility than TES-only solutions that store thermal energy and then release this back to the base power plant, as it allows both derating and over-generation. The solution is applied here to a specific case study of a 670 MW el nuclear power plant in the UK, which is a typical baseload power plant not intended for flexible operation. It is found a maximum combined power of 822 MW el can be delivered during peak demand, which is 23% higher than the base plant’s (nominal) rated power, and a maximum derating of 40%, i.e., down to 406 MW el during off-peak demand. An operational energy management strategy (EMS) is then proposed for optimising the charging of the TES tanks during off-peak demand periods and for controlling the discharging of the tanks for electricity generation during peak-demand periods. An economic analysis is performed to evaluate the potential benefits of this EMS. Profitability in the case study considered here can result when the average peak and off-peak electricity price variations are at least double those that occurred in the UK market in 2019 (with recent data now close to this), and when TES charge/discharge cycles are performed more than
Al Kindi A, Aunedi M, Pantaleo A, et al., 2021, Thermo-economic assessment of flexible nuclear power plants in the UK’s future low-carbon electricity system: role of thermal energy storage, 16th Conference on Sustainable Development of Energy, Water and Environment Systems, Publisher: SDEWES
Nuclear power plants are commonly operated as baseload units due to their low variable costs, high investment costs and limited ability to modulate their output. The increasing penetration of intermittent renewable power will require additional flexibility from conventional generation units, in order to follow the fluctuating renewable output while guaranteeing security of energy supply. In this context, coupling nuclear reactors with thermal energy storage could ensure a more continuous and efficient operation of nuclear power plants, while at other times allowing their operation to become more flexible and cost-effective. This study considers options for upgrading a 1610-MWel nuclear power plant with the addition of a thermal energy storage system and secondary power generators. The analysed configuration allows the plant to generate up to 2130 MWel during peak load, representing an increase of 32% in nominal rated power. The gross whole-system benefits of operating the proposed configuration are quantified over several scenarios for the UK’s low-carbon electricity system. Replacing conventional with flexible nuclear plant configuration is found to generate system cost savings that are between £24.3m/yr and £88.9m/yr, with the highest benefit achieved when stored heat is fully discharged in 0.5 hours (the default case is 1 hour). At an estimated cost of added flexibility of £42.7m/yr, the proposed flexibility upgrade to a nuclear power plant appears to be economically justified for a wide range of low-carbon scenarios, provided that the number of flexible nuclear units in the system is small.
Richter M, Lombardi P, Arendarski B, et al., 2021, A Vision for Energy Decarbonization: Planning Sustainable Tertiary Sites as Net-Zero Energy Systems, ENERGIES, Vol: 14
Hassaan MA, El Nemr A, Elkatory MR, et al., 2021, Synthesis, characterization, and synergistic effects of modified biochar in combination with alpha-Fe2O3 NPs on biogas production from red algae pterocladia capillacea, Sustainability, Vol: 13, Pages: 1-22, ISSN: 2071-1050
This study is the first work that evaluated the effectiveness of unmodified (SD) and modified biochar with ammonium hydroxide (SD-NH2) derived from sawdust waste biomass as an additive for biogas production from red algae Pterocladia capillacea either individually or in combination with hematite α-Fe2O3 NPs. Brunauer, Emmett, and Teller, Fourier transform infrared, thermal gravimetric analysis, X-ray diffraction, transmission electron microscopy, Raman, and a particle size analyzer were used to characterize the generated biochars and the synthesized α-Fe2O3. Fourier transform infrared (FTIR) measurements confirmed the formation of amino groups on the modified biochar surface. The kinetic research demonstrated that both the modified Gompertz and logistic function models fit the experimental data satisfactorily except for 150 SD-NH2 alone or in combination with α-Fe2O3 at a concentration of 10 mg/L. The data suggested that adding unmodified biochar at doses of 50 and 100 mg significantly increased biogas yield compared to untreated algae. The maximum biogas generation (219 mL/g VS) was obtained when 100 mg of unmodified biochar was mixed with 10 mg of α-Fe2O3 in the inoculum.
El Nemr A, Hassaan MA, Elkatory MR, et al., 2021, Efficiency of Fe3O4 Nanoparticles with Different Pretreatments for Enhancing Biogas Yield of Macroalgae Ulva intestinalis Linnaeus, MOLECULES, Vol: 26
Olympios A, Krishnaswamy A, Stollery C, et al., 2021, Techno-economic comparison of hydrogen- and electricity-driven technologies for the decarbonisation of domestic heating, 16th Conference on Sustainable Development of Energy, Water and Environment Systems (SDEWES 2021)
Sustainable transition pathways currently being proposed for moving away from the use of natural gas and oil in domestic heating focus on two main energy vectors: electricity and hydrogen. The former transition would most likely be implemented using electric vapour-compression heat pumps, which are currently experiencing market growth in many industrialised countries. Electric heat pumps have proven to be an efficient alternative to gas boilers under certain conditions, but their techno-economic potential is highly dependent on the local climate conditions. Hydrogen-based heating systems, which could potentially utilise existing natural gas infrastructure, are being proposed as providing an attractive opportunity to maximise the use of existing assets to facilitate the energy-system transition. In this case, hydrogen can substitute natural gas in boilers or in thermally driven absorption heat pumps. Both heating system transition pathways may involve either installing new technologies at the household level or producing heat in centralised hubs and distributing it via district-heating systems. Although the potential of hydrogen in the context of heating decarbonisation has been explored in the past, a comprehensive comparison of electricity- and hydrogen-driven domestic heating options is lacking in literature. In this paper, a thermodynamic and economic methodology is developed to assess the competitiveness of a domestic-scale ammonia-water absorption heat pump driven by heat from a hydrogen boiler compared to a standalone hydrogen boiler, a classic vapour-compression heat pump and district heating, all from a homeowner’s perspective. Using a previously developed electric heat pump model, the different systems are compared for various climate conditions and fuel-price scenarios under a unified framework. The coefficient of performance of the absorption heat pump system under design conditions and the total system cost are found to be 1.4 and £5400, resp
Todaro L, Liuzzi S, Pantaleo AM, et al., 2021, Thermo-modified native black poplar (Populus nigra L.) wood as an insulation material, IFOREST-BIOGEOSCIENCES AND FORESTRY, Vol: 14, Pages: 268-273, ISSN: 1971-7458
Palmitessa OD, Pantaleo MA, Santamaria P, 2021, Applications and Development of LEDs as Supplementary Lighting for Tomato at Different Latitudes, AGRONOMY-BASEL, Vol: 11
Fermo P, Artinano B, De Gennaro G, et al., 2021, Improving indoor air quality through an air purifier able to reduce aerosol particulate matter (PM) and volatile organic compounds (VOCs): Experimental results, ENVIRONMENTAL RESEARCH, Vol: 197, ISSN: 0013-9351
Hassaan MA, El Nemr A, Elkatory MR, et al., 2021, Enhancement of Biogas Production from Macroalgae Ulva latuca via Ozonation Pretreatment, ENERGIES, Vol: 14
Calise F, Cappiello FL, Vicidomini M, et al., 2021, Energy and economic assessment of energy efficiency options for energy districts: case studies in Italy and Egypt, Energies, Vol: 14, Pages: 1-24, ISSN: 1996-1073
In this research, a technoeconomic comparison of energy efficiency options for energy districts located in different climatic areas (Naples, Italy and Fayoum, Egypt) is presented. A dynamic simulation model based on TRNSYS is developed to evaluate the different energy efficiency options, which includes different buildings of conceived districts. The TRNSYS model is integrated with the plug-in Google SketchUp TRNSYS3d to estimate the thermal load of the buildings and the temporal variation. The model considers the unsteady state energy balance and includes all the features of the building’s envelope. For the considered climatic zones and for the different energy efficiency measures, primary energy savings, pay back periods and reduced CO2 emissions are evaluated. The proposed energy efficiency options include a district heating system for hot water supply, air-to-air conventional heat pumps for both cooling and space heating of the buildings and the integration of photovoltaic and solar thermal systems. The energy actions are compared to baseline scenarios, where the hot water and space heating demand is satisfied by conventional natural gas boilers, the cooling demand is met by conventional air-to-air vapor compression heat pumps and the electric energy demand is satisfied by the power grid. The simulation results provide valuable guidance for selecting the optimal designs and system configurations, as well as suggest guidelines to policymakers to define decarbonization targets in different scenarios. The scenario of Fayoum offers a savings of 67% in primary energy, but the associated payback period extends to 23 years due to the lower cost of energy in comparison to Naples.
Aunedi M, Pantaleo AM, Kuriyan K, et al., 2020, Modelling of national and local interactions between heat and electricity networks in low-carbon energy systems, Applied Energy, Vol: 276, Pages: 1-18, ISSN: 0306-2619
Decarbonisation of the heating and cooling sector is critical for achieving long-term energy and climate change objectives. Closer integration between heating/cooling and electricity systems can provide additional flexibility required to support the integration of variable renewables and other low-carbon energy sources. This paper proposes a framework for identifying cost-efficient solutions for supplying district heating systems within both operation and investment timescales, while considering local and national-level interactions between heat and electricity infrastructures. The proposed optimisation model minimises the levelised cost of a portfolio of heating technologies, and in particular Combined Heat and Power (CHP) and polygeneration systems, centralised heat pumps (HPs), centralised boilers and thermal energy storage (TES). A number of illustrative case studies are presented, quantifying the impact of renewable penetration, electricity price volatility, local grid constraints and local emission targets on optimal planning and operation of heat production assets. The sensitivity analysis demonstrates that the cost-optimal TES capacity could increase by 41–134% in order to manage a constraint in the local electricity grid, while in systems with higher RES penetration reflected in higher electricity price volatility it may be optimal to increase the TES capacity by 50–66% compared to constant prices, allowing centralised electric HP technologies to divert excess electricity produced by intermittent renewable generators to the heating sector. This confirms the importance of reflecting the whole-system value of heating technologies in the underlying cost-benefit analysis of heat networks.
Hassaan MA, Pantaleo A, Santoro F, et al., 2020, Techno-Economic Analysis of ZnO Nanoparticles Pretreatments for Biogas Production from Barley Straw, ENERGIES, Vol: 13
Wang K, Pantaleo AM, Herrando M, et al., 2020, Spectral-splitting hybrid PV-thermal (PVT) systems for combined heat and power provision to dairy farms, Renewable Energy, Vol: 159, Pages: 1047-1065, ISSN: 0960-1481
Dairy farming is one of the most energy- and emission-intensive industrial sectors, and offers noteworthy opportunities for displacing conventional fossil-fuel consumption both in terms of cost saving and decarbonisation. In this paper, a solar-combined heat and power (S–CHP) system is proposed for dairy-farm applications based on spectral-splitting parabolic-trough hybrid photovoltaic-thermal (PVT) collectors, which is capable of providing simultaneous electricity, steam and hot water for processing milk products. A transient numerical model is developed and validated against experimental data to predict the dynamic thermal and electrical characteristics and to assess the thermoeconomic performance of the S–CHP system. A dairy farm in Bari (Italy), with annual thermal and electrical demands of 6000 MWh and 3500 MWh respectively, is considered as a case study for assessing the energetic and economic potential of the proposed S–CHP system. Hourly simulations are performed over a year using real-time local weather and measured demand-data inputs. The results show that the optical characteristic of the spectrum splitter has a significant influence on the system’s thermoeconomic performance. This is therefore optimised to reflect the solar region between 550 nm and 1000 nm to PV cells for electricity generation and (low-temperature) hot-water production, while directing the rest to solar receivers for (higher-temperature) steam generation. Based on a 10000-m2 installed area, it is found that 52% of the demand for steam generation and 40% of the hot water demand can be satisfied by the PVT S–CHP system, along with a net electrical output amounting to 14% of the farm’s demand. Economic analyses show that the proposed system is economically viable if the investment cost of the spectrum splitter is lower than 75% of the cost of the parabolic trough concentrator (i.e., <1950 €/m2 spectrum splitter) in this application. The influenc
Cremi MR, Pantaleo AM, van Dam KH, et al., 2020, Optimal design and operation of an urban energy system applied to the Fiera Del Levante exhibition centre, Applied Energy, Vol: 275, Pages: 1-22, ISSN: 0306-2619
To move from centralised fossil fuel-based energy systems, synergies between distributed renewable generation, storage and demand-side strategies can be exploited to lower environmental impact and costs. This paper proposes an optimisation model for the techno-economic assessment of energy management strategies with a short-term investment horizon aimed at business managers and decision-makers in the commercial sector. The main novelty is the selection of a combination of on-site technologies and peak shaving strategies to minimise energy costs under time-of-use electricity tariffs, and the adaptation of a general methodology for a specific socio-technical context under seasonal loads. The “Fiera del Levante” exhibition centre in the city of Bari is selected due to the high seasonality of its electricity demand. The optimal solution uses a combined system with photovoltaics, diesel-fired and gas-fired combined-heat-and-power, including part-load operation and electric storage. The cost minimisation scenario reports up to 20% cost savings and 35% carbon emission savings with a 1MWp photovoltaic plant, compared to the baseline. This presents a five-year return on investment of 75%, and levelized cost of energy of €0.14 kWh−1. When coupled with a lithium-ion battery, solar energy brings up to 60% carbon emission savings through load shifting strategies, though this reduces the five-year return on investment by 9%. This hybrid setup is not financially competitive in the Italian retail market, but a hypothetical 25% rise of the grid import prices would make it economically viable. The proposed model is flexible and can be adapted to commercial end-users, providing decision-support in urban energy systems under local conditions.
Olympios AV, Pantaleo AM, Sapin P, et al., 2020, On the value of combined heat and power (CHP) systems and heat pumps in centralised and distributed heating systems: Lessons from multi-fidelity modelling approaches, Applied Energy, Vol: 274, Pages: 1-19, ISSN: 0306-2619
This paper presents a multi-scale framework for the design and comparison of centralised and distributed heat generation solutions. An extensive analysis of commercially available products on the UK market is conducted to gather information on the performance and cost of a range of gas-fired combined heat and power (CHP) systems, air-source heat pumps (ASHPs) and ground-source heat pumps (GSHPs). Data-driven models with associated uncertainty bounds are derived from the collected data, which capture cost and performance variations with scale (i.e., size and rating) and operating conditions. In addition, a comprehensive thermoeconomic (thermodynamic and component-costing) heat pump model, validated against manufacturer data, is developed to capture design-related performance and cost variations, thus reducing technology-related model uncertainties. The novelty of this paper lies in the use of multi-fidelity approaches for the comparison of the economic and environmental potential of important heat-generation solutions: (i) centralised gas-fired CHP systems associated with district heating network; (ii) gas-fired CHP systems or GSHPs providing heat to differentiated energy communities; and (iii) small-scale micro-CHP systems, ASHPs or GSHPs, installed at the household level. The pathways are evaluated for the case of the Isle of Dogs district in London, UK. A centralised CHP system appears as the most profitable option, achieving annual savings of £13 M compared to the use of decentralised boilers and a levelised cost of heat equal to 31 £/MWhth. However, if the carbon intensity of the electrical grid continues to reduce at current rates, CHP systems will only provide minimal carbon savings compared to boilers (<6%), with heat pumps achieving significant heat decarbonisation (55–62%). Differentiating between high- and low-performance and cost heat pump designs shows that the former, although 25% more expensive, have significantly lower annualised
Sokolnikova P, Lombardi P, Arendarski B, et al., 2020, Net-zero multi-energy systems for Siberian rural communities: A methodology to size thermal and electric storage units, RENEWABLE ENERGY, Vol: 155, Pages: 979-989, ISSN: 0960-1481
Olympios A, Hoisenpoori P, Mersch M, et al., 2020, Optimal design of low-temperature heat-pumping technologies and implications to the whole energy system, The 33rd International Conference on Efficiency, Cost, Optimization, Simulation and Environmental Impact of Energy Systems.
This paper presents a methodology for identifying optimal designs for air-source heat pumps suitable for domestic heating applications from the whole-energy system perspective, accounting explicitly for a trade-off between cost and efficiency, as well as for the influence of the outside air temperature during off-design operation. The work combines dedicated brazed-plate and plate-fin heat-exchanger models with compressor efficiency maps, as well as equipment costing techniques, in order to develop a comprehensive technoeconomic model of a low-temperature air-source heat pump with a single-stage-compressor, based on the vapour-compression cycle. The cost and performance predictions are validated against manufacturer data and a non-linear thermodynamic optimisation model is developed to obtain optimal component sizes for a set of competing working fluids and design conditions. The cost and off-design performance of different configurations are integrated into a whole-energy system capacity-expansion and unit-dispatch model of the UK power and heat system. The aim is to assess the system value of proposed designs, as well as the implications of their deployment on the power generation mix and total transition cost of electrifying domestic heat in the UK as a pathway towards meeting a national net-zero emission target by 2050. Refrigerant R152a appears to have the best design and off-design performance, especially compared to the commonly used R410a. The size of the heat exchangers has a major effect on heat pump performance and cost. From a wholesystem perspective, high-performance heat pumps enable a ~20 GW (~10%) reduction in the required installed power generation capacity compared to smaller-heat-exchanger, low-performance heat pumps, which in turn requires lower and more realistic power-grid expansion rates. However, it is shown that the improved performance as a result of larger heat exchangers does not compensate overall for the increased technology cost, with
Al Kindi A, Markides C, Pantaleo A, et al., 2020, Optimal system configuration and operation strategies of flexible hybrid nuclear-solar power plants, The 33rd International Conference on Efficiency, Cost, Optimization, Simulation and Environmental Impact of Energy Systems, Publisher: ECOS
Nuclear power plants are commonly used for baseload power supply due to their high reliability, low variable costs, as well as relatively low thermal efficiencies and limited load-following capabilities; especially, in the case of light water reactors. At the same time, concentrating solar power (CSP) technology is gaining attention, but is still considered an intermittent source of power with a limited availability factor. In an effort to propose a very different performance characteristic for both technologies, a hybrid power system combining nuclear and CSP plants and integrated with a thermal energy storage system is considered in this paper. The integration of the technologies is achieved by adding an indirect solar superheater and a solar reheater to a small modular nuclear reactor (NuScale). The work includes modelling of the integrated hybrid system, thermodynamic performance analysis and operational optimization aimed at maximizing the profitability of such a hybrid power plant in Oman. The results show that the hybrid system has the potential to deliver more efficient and flexible power (operating between 55% and 100% of nominal load) with the nuclear reactor operated continuously at its full rated power. The hybridization concept can potentially produce a competitive levelized cost of electricity, especially with the integration of thermal energy storage. The study concludes that the installation of such a system in Oman is not yet economically viable unless electricity tariffs increase by 70% to UK levels.
Hamedani SR, Villarini M, Colantoni A, et al., 2020, Environmental and Economic Analysis of an Anaerobic Co-Digestion Power Plant Integrated with a Compost Plant, ENERGIES, Vol: 13
Pantaleo A, Villarini M, Colantoni A, et al., 2020, Techno-Economic Modeling of Biomass Pellet Routes: Feasibility in Italy, ENERGIES, Vol: 13
Pantaleo AM, Camporeale S, Sorrentino A, et al., 2020, Hybrid solar-biomass combined Brayton/organic Rankine-cycle plants integrated with thermal storage: Techno-economic feasibility in select Mediterranean areas, Renewable Energy, Vol: 147, Pages: 2913-2931, ISSN: 1879-0682
This paper presents a thermodynamic analysis and techno-economic assessment of a novel hybrid solar-biomass power-generation system configuration composed of an externally fired gas-turbine (EFGT) fuelled by biomass (wood chips) and a bottoming organic Rankine cycle (ORC) plant. The main novelty is related to the heat recovery from the exhaust gases of the EFGT via thermal energy storage (TES), and integration of heat from a parabolic-trough collectors (PTCs) field with molten salts as a heat-transfer fluid (HTF). The presence of a TES between the topping and bottoming cycles facilitates the flexible operation of the system, allows the system to compensate for solar energy input fluctuations, and increases capacity factor and dispatchability. A TES with two molten salt tanks (one cold at 200 °C and one hot at 370 °C) is chosen. The selected bottoming ORC is a superheated recuperative cycle suitable for heat conversion in the operating temperature range of the TES. The whole system is modelled by means of a Python-based software code, and three locations in the Mediterranean area are assumed in order to perform energy-yield analyses: Marseille in France, Priolo Gargallo in Italy and Rabat in Morocco. In each case, the thermal storage that minimizes the levelized cost of energy (LCE) is selected on the basis of the estimated solar radiation and CSP size. The results of the thermodynamic simulations, capital and operational costs assessments and subsidies (feed-in tariffs for biomass and solar electricity available in the Italian framework), allow estimating the global energy conversion efficiency and the investment profitability in the three locations. Sensitivity analyses of the biomass costs, size of PTCs, feed-in tariff and share of cogenerated heat delivered to the load are also performed. The results show that the high investment costs of the CSP section in the proposed size range and hybridization configuration allow investment profitability only in the
Clairand J-M, Briceno-Leon M, Escriva-Escriva G, et al., 2020, Review of Energy Efficiency Technologies in the Food Industry: Trends, Barriers, and Opportunities, IEEE ACCESS, Vol: 8, Pages: 48015-48029, ISSN: 2169-3536
Hassaan MA, Pantaleo A, Tedone L, et al., 2019, Enhancement of biogas production via green ZnO nanoparticles: experimental results of selected herbaceous crops, CHEMICAL ENGINEERING COMMUNICATIONS, Vol: 208, Pages: 242-255, ISSN: 0098-6445
Romanos P, Pantaleo A, Markides C, 2019, Energy management and enhanced flexibility of power stations via thermal energy storage and secondary power cycles, 11th International Conference on Applied Energy
The operation of power plants must meet a series of requirements in order to enable the increasing penetration of intermittent renewable energy and the consequent intensifying demand for flexible generation. It is proposed here that during off-peak demand, steam can be extracted from Rankine-cycle power stations for the charging of thermal storage tanks that contain suitable phase-change materials (PCMs); during peak demand time, these thermal energy storage (TES) tanks can act as the heat sources of secondary thermal power plants in order to generate power, for example as evaporators of organic Rankine cycle (ORC) plants that are suitable for power generation at reduced temperatures and smaller scales. This type of solution offers greater flexibility than TES-only solutions that store thermal energy and then release this back to the base power station, in that it allows both derating andover-generation compared to the base power-station. The approach is here applied to a case study of a 670-MW rated nuclear power station, since nuclear power stations are generally suitable for baseload generation and the proposed system configuration could increase the operational flexibility of such plants.
Herrando M, Pantaleo AM, Wang K, et al., 2019, Solar combined cooling, heating and power systems based on hybrid PVT, PV or solar-thermal collectors for building applications, Renewable Energy, Vol: 143, Pages: 637-647, ISSN: 0960-1481
A modelling methodology is developed and used to investigate the technoeconomic performance of solar combined cooling, heating and power (S-CCHP) systems based on hybrid PVT collectors. The building energy demands are inputs to a transient system model, which couples PVT solar-collectors via thermal-store to commercial absorption chillers. The real energy demands of the University Campus of Bari, investment costs, relevant electricity and gas prices are used to estimate payback-times. The results are compared to: evacuated tube collectors (ETCs) for heating and cooling provision; and a PV-system for electricity provision. A 1.68-MWp S-CCHP system can cover 20.9%, 55.1% and 16.3% of the space-heating, cooling and electrical demands of the Campus, respectively, with roof-space availability being a major limiting factor. The payback-time is 16.7 years, 2.7-times higher than that of a PV-system. The lack of electricity generation by the ETC-based system limits its profitability, and leads to 2.3-times longer payback-time. The environmental benefits arising from the system’s operation are evaluated. The S-CCHP system can displace 911 tonsCO2/year (16% and 1.4× times more than the PV-system and the ETC-based system, respectively). The influence of utility prices on the systems’ economics is analysed. It is found that the sensitivity to these prices is significant.
Pantaleo A, Simpson M, Rotolo G, et al., 2019, Thermoeconomic optimisation of small-scale organic Rankine cycle systems based on screw vs. piston expander maps in waste heat recovery applications, Energy Conversion and Management, Vol: 200, ISSN: 0196-8904
The high cost of organic Rankine cycle (ORC) systems is a key barrier to their implementation in waste heat recovery (WHR) applications. In particular, the choice ofexpansion device has a significant influence on this cost, strongly affecting the economic viabilityof an installation. In this work, numerical simulations and optimisation strategies are used to compare the performance and profitability of small-scale ORC systems using reciprocating-piston orsingle/two-stage screw expanders whenre covering heat from the exhaust gases of a 185-kWinternal combustion engine operating in baseload mode. The study goes beyond previous work by directly comparingthese small-scaleexpanders fora broad range of working fluids, and by exploring the sensitivity of project viability to key parameters such as electricity price and onsite heat demand.For the piston expander, a lumped-massmodel and optimisation based on artificial neural networks are used to generate performance maps, while performance and cost correlations from the literature are used for the screw expanders. The thermodynamic analysisshows that two-stage screw expanders typically deliver more power than either single-stage screw or piston expanders due to their higher conversion efficiencyat the required pressure ratios. The best fluids areacetone and ethanol, as these provide a compromise between the exergy losses in the condenser and in the evaporatorin this application. The maximum net power output isfound to be 17.7kW, from an ORC engine operating withacetone anda two-stage screw expander. On the other hand, the thermoeconomic optimisation shows that reciprocating-piston expandersshow a potential for lowerspecific costs, and sincesuchan expander technology is not mature, especially at these scales, this finding motivates further consideration of this component. A minimum specific investment cost of 1630€/kW is observed for an ORC engine with a pisto
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