• Energy Research

This study regards the integration of a PV powered air-conditioning system with a thermal energy storage (TES) system. The integration will be performed: a) feeding a heat pump with PV electricity during hours of high solar radiation and energy demand, b) feeding a heat pump with PV electricity and storing thermal energy in a TES system during hours of high solar radiation and low electricity demand and c) feeding the air-conditioning system directly with the thermal energy stored in case of low (or null) PV production and high energy demand. Comparing the load profiles with the PV production forecasts allowed to evaluate energy deficit and surplus on an hourly basis and to define the TES storage capacity. Various low temperature TES systems were analyzed and compared, in particular: a) a direct storage with water, b) a storage with water and solid material and c) a storage with water and PCM. With the aim of maximizing energy self-consumption and self-sufficiency, daily or multi-day TES were evaluated, with reference to a winter availability of excess electricity.

This study is aimed at a succinct review of practical impacts of grid integration of renewable energy systems on effectiveness of power networks, as well as often employed state-of-the-art solution strategies. The renewable energy resources focused on include solar energy, wind energy, biomass energy and geothermal energy, as well as renewable hydrogen/fuel cells, which, although not classified purely as renewable resources, are a famous energy carrier vital for future energy sustainability. Although several world energy outlooks have suggested that the renewable resources available worldwide are sufficient to satisfy global energy needs in multiples of thousands, the different challenges often associated with practical exploitation have made this assertion an illusion to date. Thus, more research efforts are required to synthesize the nature of these challenges as well as viable solution strategies, hence, the need for this review study. First, brief overviews are provided for each of the studied renewable energy sources. Next, challenges and solution strategies associated with each of them at generation phase are discussed, with reference to power grid integration. Thereafter, challenges and common solution strategies at the grid/electrical interface are discussed for each of the renewable resources. Finally, expert opinions are provided, comprising a number of aphorisms deducible from the review study, which reveal knowledge gaps in the field and potential roadmap for future research. In particular, these opinions include the essential roles that renewable hydrogen will play in future energy systems; the need for multi-sectoral coupling, specifically by promoting electric vehicle usage and integration with renewable-based power grids; the need for cheaper energy storage devices, attainable possibly by using abandoned electric vehicle batteries for electrical storage, and by further development of advanced thermal energy storage systems (overviews of state-of-the-art thermal and electrochemical energy storage are also provided); amongst others.

Abstract Small-scale fixed-bed coal and biomass gasifiers represent an attractive option for distributed combined heat and power generation. As known, gasification phenomena are very complex, involving drying, devolatilization, pyrolysis, heterogeneous and homogenous reactions, with a large number of intermediate and final products. Gasification processes are also influenced by reaction kinetics and fluid-dynamical effects, such as temperature and concentration gradients. For this reason, simulation models are able to predict gasifiers performance under the assumption of thermodynamic equilibrium only if the gasification process takes place at a known temperature and the reaction time is lower than the reactants residence time. As a consequence, for fixed-bed gasifiers equilibrium models must consider drying and devolatilization taking place at lower temperature in the heat transfer zone, where solid feed is heated by syngas. Therefore, moisture and volatiles are not involved in the gasification reactions since they are released before reaching the reaction zone. Several models based on steady-state and one-dimensional representations have been developed to reproduce gasification processes in fixed-bed reactors. These models have been found adequate to provide information for engineering design and process optimization. In this framework a steady-state simulation model has been developed at the Department of Mechanical Chemical and Materials Engineering (DIMCM) of the University of Cagliari by using the Aspen Plus computer code for predicting performance of small-scale up-draft fixed-bed coal gasifiers. The model can be used to evaluate the mass and energy balance in each zone of the gasifier and the main characteristics of the syngas produced by the gasification process (composition, mass flow, temperature, heating value, etc.). This paper describes the model and presents the main results of a parametric analysis, which shows how the gasification process is influenced by the main operating parameters. Moreover, the results of the model have been compared with the experimental results of an up-draft gasifier fed with an lignite from Alaska. The above-mentioned gasifier is part of a pilot gasification and gas treatment plant built at the Sotacarbo Research Centre in Sardinia, Italy. The comparison shows that the model well represents the performance of the pilot-scale unit.

Carbon capture and storage (CCS) represents a key solution to control the global warming reducing carbon dioxide emissions from coal-fired power plants. This study reports a comparative performance assessment of different power generation technologies, including ultrasupercritical (USC) pulverized coal combustion plant with postcombustion CO2 capture, integrated gasification combined cycle (IGCC) with precombustion CO2 capture, and oxy-coal combustion (OCC) unit. These three power plants have been studied considering traditional configuration, without CCS, and a more complex configuration with CO2 capture. These technologies (with and without CCS systems) have been compared from both the technical and economic points of view, considering a reference thermal input of 1000 MW. As for CO2 storage, the sequestration in saline aquifers has been considered. Whereas a conventional (without CCS) coal-fired USC power plant results to be more suitable than IGCC for power generation, IGCC becomes more competitive for CO2-free plants, being the precombustion CO2 capture system less expensive (from the energetic point of view) than the postcombustion one. In this scenario, oxy-coal combustion plant is currently not competitive with USC and IGCC, due to the low industrial experience, which means higher capital and operating costs and a lower plant operating reliability. But in a short-term future, a progressive diffusion of commercial-scale OCC plants will allow a reduction of capital costs and an improvement of the technology, with higher efficiency and reliability. This means that OCC promises to become competitive with USC and also with IGCC.

Abstract This paper focuses on the evaluation of the potential benefits arising from the integration of Ultra Super Critical (USC) steam power plants with Carbon Capture and Storage (CCS) and concentrating solar systems. In particular, it reports on a comparative performance analysis of different integrating approaches, based on the design of the solar field to produce low-pressure saturated steam for the CCS solvent regeneration process and intermediate-pressure saturated and superheated steam for the introduction in the steam cycle. For the two different technical solutions, the comparative study calculates the increase in the annual energy production and net efficiency due to the solar energy contribution as a function of solar field size and for two different CO 2 removal efficiencies. The study demonstrates that the integration of concentrating solar collectors can partially offset the efficiency penalties due to CO 2 removal in USC power plants and that the most efficient approach is based on the production of superheated steam while lesser benefits can be achieved by producing low-pressure saturated steam for the solvent regeneration process. It also demonstrates that the introduction of the steam produced by the solar field greatly affects the performance of the power plant that operates in an “off design” mode. For this reason, to avoid an excessive increase in the turbine steam mass flow, the solar energy contribution to the annual electricity production cannot exceed 2–3%. Overall, integration with the solar section can improve the efficiency of the USC-CCS power plant by about 1 percentage point. Finally, the results of a preliminary economic analysis show that the solar assisted USC-CCS configuration may be able to operate with competitive solar energy production costs, especially with reduced solar field costs. In particular, the marginal levelized energy production cost of the most efficient solar assisted USC-CCS configuration is lower than that of the reference USC-CCS power plant for solar field costs lower than 110–115 €/m 2 .

AbstractThe widespread diffusion of renewable energy sources calls for the development of high-capacity energy storage systems as the A-CAES (Adiabatic Compressed Air Energy Storage) systems. In this framework, low temperature (100°C–200°C) A-CAES (LT-ACAES) systems can assume a key role, avoiding some critical issues connected to the operation of high temperature ones.In this paper, two different LT-ACAES configurations are proposed. The two configurations are characterized by the same turbomachines and compressed air storage section, while differ in the TES section and its integration with the turbomachinery. In particular, the first configuration includes two separated cycles: the working fluid (air) cycle and the heat transfer fluid (HTF) cycle. Several heat exchangers connect the two cycles allowing to recover thermal energy from the compressors and to heat the compressed air at the turbine inlet. Two different HTFs were considered: air (case A) and thermal oil (case B). The second configuration is composed of only one cycle, where the operating fluid and the HTF are the same (air) and the TES section is composed of three different packed-bed thermal storage tanks (case C). The tanks directly recover the heat from the compressors and heat the air at each turbine inlet, avoiding the use of heat exchangers.The LT-ACAES systems were modelled and simulated using the ASPEN-Plus and the MATLAB-Simulink environments. The main aim of this study was the detailed analysis of the reciprocal influence between the turbomachinery and the TES system; furthermore, the performance evaluation of each plant was carried out assuming both on-design and off-design operating conditions. Finally, the different configurations were compared through the main performance parameters, such as the round-trip efficiency.A total power output of around 10 MW was set, leading to a TES tank volume ranging between 500 and 700 m3. The second configuration with three TES systems appears to be the most promising in terms of round-trip efficiency since the energy produced during the discharging phase is greater. In particular, the round-trip efficiency of the LT-ACAES ranges between 0.566 (case A) to 0.674 (case C). Although the second configuration assures the highest performance, the effect of operating at very high pressures inside the tanks should be carefully evaluated in terms of overall costs.

Abstract Solid oxide fuel cell–micro-gas turbine (SOFC–MGT) hybrid power plants integrate a solid oxide fuel cell and a micro-gas turbine and can achieve efficiencies of over 60% even for small power outputs (200–500 kW). The SOFC–MGT systems currently developed are fueled with natural gas, which is reformed inside the same stack, but the use of alternative fuels can be an interesting option. In particular, as the reforming temperature of methanol and di-methyl-ether (DME) (200–350 °C) is significantly lower than that of natural gas (700–900 °C), the reformer can be sited outside the stack. External reforming in SOFC–MGT plants fueled by methanol and DME enhances efficiency due to improved exhaust heat recovery and higher voltage produced by the greater hydrogen partial pressure at the anode inlet. The study carried out in this paper shows that the main operating parameters of the fuel reforming section (temperature and steam-to-carbon ratio (SCR)) must be carefully chosen to optimise the hybrid plant performance. For the stoichiometric SCR values, the optimum reforming temperature for the methanol fueled hybrid plant is approximately 240 °C, giving efficiencies of about 67–68% with a SOFC temperature of 900 °C (the efficiency is about 72–73% at 1000 °C). Similarly, for DME the optimum reforming temperature is approximately 280 °C with efficiencies of 65% at 900 °C (69% at 1000 °C). Higher SCRs impair stack performance. As too small SCRs can lead to carbon formation, practical SCR values are around one for methanol and 1.5–2 for DME.

Currently, energy storage systems are considered a key solution when mismatch occurs between energy supply and demand, allowing a more efficient energy deployment and use. The present paper is focused on the study of a latent heat thermal energy storage (LHTES) system based on a packed bed of encapsulated phase change material (PCM) of spherical shape, conceived as an auxiliary component of a micro-grid to be built in a Research Center located in southwestern Sardinia (Italy). The main purpose of this work was to perform numerical simulations for predicting the performance of the TES system, designed to store the surplus thermal energy produced during the weekend by a heat pump fed by a photovoltaic (PV) plant. The stored energy would then be utilized during the weekdays to integrate the air-conditioning system supply. The numerical simulations were based on a one-dimensional (1-D) two-equation transient model, able to return the thermocline profile of the water and the PCM separately. The behavior of the LHTES device during charge and discharge phases was reproduced, as well as during the standby periods. Finally, two characteristic indexes of the PV system were evaluated, to investigate the effect of TES on grid interchanges, self-consumption, and self-sufficiency.

Abstract The use of concentrating solar technologies for supplying the heat and power demand of a typical dairy factoryis investigated in this paper.A yearly-based performance analysis iscarried out considering different values of solar field collecting area and thermal energy storage capacity with reference to a typical meteorological data setof a Sardinian location. Specific simulation models are developed for each section of the plant. Moreover, a novel energy management strategy isdeveloped for the determination of the priority order between thermal and electrical demand. The results demonstrate that concentrating solar technologies could be a promising option if power and heat are both required. In particular, the presence of the energy storage section provides important flexibility features to the plant and by suitably setting the control variable, the energy management strategy allows to give priority to the heat or to the electrical demand of the dairy.