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Bardet–Biedl syndrome (BBS) is a rare autosomal recessive ciliopathy resulting in multiple organ dysfunctions, including chronic kidney disease (CKD). Despite the recent progress in the ’ciliopathy’ field, there is still little information on the mechanisms underlying renal disease. To elucidate these pathomechanisms, we conducted a translational study, including (i) the characterization of the urine metabolomic pattern of BBS patients and controls in a pilot and confirmation study and (ii) the proteomic analysis of the BBS10 interactome, one of the major mutated BBS genes in patients, in a renal-epithelial-derived cell culture model. The urine metabolomic fingerprinting of BBS patients differed from controls in both pilot and confirmation studies, demonstrating an increased urinary excretion of several monocarboxylates, including lactic acid (LA), at both early and late CKD stages. Increased urine LA was detected in the absence of both increased plasmatic LA levels and generalized proximal tubular dysfunction, suggesting a possible renal-specific defective handling. The inner medulla renal epithelial (IMCD3) cell line, where Bbs10 was stably invalidated, displayed an increased proliferative rate, increased ATP production, and an up-regulation of aerobic glycolysis. A mass spectrometry-based analysis detected several putative BBS10 interactors in vitro, indicating a potential role of BBS10 in several biological processes, including renal metabolism, RNA processing, and cell proliferation. The present study suggests that the urine metabolomic pattern of BBS patients may reflect intra-renal metabolic aberrations. The analysis of BBS10 interactors unveils possible novel functions, including cell metabolism.

The transition to a hydrogen-based mobility requires the development of an infrastructure that must be able to satisfy the hydrogen demand. In the short and medium term, the lack of the hydrogen distribution infrastructure can be overcome through the on-site hydrogen production. However, the costs of the plants for hydrogen production, storage and distribution are currently too high and, therefore, the levelized cost of hydrogen is high above all if it is produced by renewable sources. To reduce this cost and to sustain the economic profitability of the on-site hydrogen production and distribution plants, a strong policy support and investments are required. This paper is focused on the evaluation of an incentive strategy that can assure the economic sustainability of on-site hydrogen refueling stations powered by a grid-connected solar plant. The strategy is based on the economic valorization of the carbon dioxide equivalent emissions that are avoided by adopting the proposed hydrogen pathway in comparison to the gasoline one that represents the reference for the current European powertrain technologies and trends. These carbon dioxide equivalent emissions have been estimated by applying the Well-To-Wheel analysis and the Life Cycle Cost analysis has been used to estimate the economic incentive to be paid to the avoided emission by fixing the discounted pay-back period and the current hydrogen selling price. The WTW analysis results have shown that the annual avoided equivalent emissions of the hydrogen pathway are equal to 320 tons and the corresponding economic incentives are 65.72 €/tCO2eq and 327.49 €/tCO2eq, by considering the Discounted Pay Back Periods of 10 and 8 years, respectively. Moreover, these incentives allow to achieve the Levelized Cost of Hydrogen and the Profitability Index equal to 9.02 €/kg and 1.75 (10 years) and 7.86 €/kg and 2.12 (8 years), respectively. In conclusion, the proposed incentive strategy is a suitable option to support the on-site HRS powered by grid-connected solar plants which are a promising solution for a sustainable mobility.

The exploitation of the biomethane as transport fuel is receiving increasing attention in many European countries. Technologies and processes for improving the Biogas-to-biomethane production with a lower energy consumption and lower costs are objective of several techno-economic studies. In this paper two promising concepts for the biogas conversion are proposed and analyzed considering both technical and economic issues. The analysis regards the biogas upgrading by means of the chemical absorption with Hot Potassium Carbonate and the direct methanation of biogas by adding renewable hydrogen. In order to assess the feasibility of these technologies the numerical modelling has been applied for the plants designing. The energy results have then been used to assess the expected biomethane production price and a sensitivity analysis on the main parameters has been performed. Finally, economic performance of the options proposed will be evaluated under different market conditions.

Hydrogen refueling infrastructures with on-site production from renewable sources are an interesting solution for assuring green hydrogen with zero CO2 emissions. The main problem of these stations development is the hydrogen cost that depends on both the plant size (hydrogen production capacity) and on the renewable source. In this study, a techno-economic assessment of on-site hydrogen refueling stations (HRS), based on grid-connected PV plants integrated with electrolysis units, has been performed. Different plant configurations, in terms of hydrogen production capacity (50 kg/day, 100 kg/day, 200 kg/day) and the electricity mix (different sharing of electricity supply between the grid and the PV plant), have been analyzed in terms of electric energy demands and costs. The study has been performed by considering the Italian scenario in terms of economic streams (i.e. electricity prices) and solar irradiation conditions. The levelized cost of hydrogen (LCOH), that is the more important indicator among the economic evaluation indexes, has been calculated for all configurations by estimating the investment costs, the operational and maintenance costs and the replacement costs. Results highlighted that the investment costs increase proportionally as the electricity mix changes from Full Grid operation (100% Grid) to Low Grid supply (25% Grid) and as the hydrogen production capacity grows, because of the increasing in the sizes of the PV plant and the HRS units. The operational and maintenance costs are the main contributor to the LCOH due to the annual cost of the electricity purchased from the grid. The calculated LCOH values range from 9.29 €/kg (200 kg/day, 50% Grid) to 12.48 €/kg (50 kg/day, 100% Grid).

In the context of the European decarbonization strategy, hydrogen is a key energy carrier in the medium to long term. The main advantages deriving from a greater penetration of hydrogen into the energy mix consist in its intrinsic characteristics of flexibility and integrability with alternative technologies for the production and consumption of energy. In particular, hydrogen allows to: i) decarbonise end uses, since it is a zero-emission energy carrier and can be produced with processes characterized by the absence of greenhouse gases emissions (e.g. water electrolysis); ii) help to balancing electricity grid supporting the integration of non-programmable renewable energy sources; iii) exploit the natural gas transmission and distribution networks as storage systems in overproduction periods. However, the hydrogen injection into the natural gas infrastructures directly influences thermophysical properties of the gas mixture itself, such as density, calorific value, Wobbe index, speed of sound, etc [1]. The change of the thermophysical properties of gaseous mixture, in turn, directly affects the end use service in terms of efficiency and safety as well as the metrological performance and reliability of the volume and gas quality measurement systems. In this paper, the authors present the results of a study about the impact of hydrogen injection on the properties of the natural gas mixture. In detail, the changes of the thermodynamic properties of the gaseous mixtures with different hydrogen content have been analysed. Moreover, the theoretical effects of the aforementioned variations on the accuracy of the compressibility factor measurement have been also assessed.

This paper presents the economic assessment of novel refueling stations, in which through advanced and high efficiency technologies, the polygeneration of more energy services like hydrogen, electricity and heat is carried out on-site. The architecture of these polygeneration plants is realized with a modular structure, organized in more sections. The primary energy source is ammonia that represents an interesting fuel for producing more energy streams. The ammonia feeds directly the SOFC that is able to co-generate simultaneously electricity and hydrogen by coupling a high efficiency energy system with hydrogen chemical storage. Two system configurations have been proposed considering different design concepts: in the first case (Concept_1) the plant is sized for producing 100 kg/day of hydrogen and the power section is sized also for self-sustaining the plant electric power consumption, while in the second one (Concept_2) the plant is sized for producing 100 kg/day of hydrogen and the power section is sized for self-sustaining the plant electric power consumption and for generating 50 kW for the DC fast charging. The economic analysis has been carried out in the current and target scenarios, by evaluating, the levelized cost of hydrogen (LCOH), the levelized cost of electricity (LCOE), the Profitability Index (PI), Internal rate of Return (IRR) and the Discounted Payback Period (DPP). Results have highlighted that the values of the LCOH, for the proposed configurations and economic scenarios, are in the range 6–10 €/kg and the values of the LCOE range from 0.447 €/kWh to 0.242 €/kWh. In terms of PI and IRR, the best performance is achieved in the Concept_1 for the current scenario (1.89 and 8.0%, respectively). On the contrary, in the target scenario, thanks to a drastic costs reduction the co-production of hydrogen and electricity as useful outputs, becomes the best choice from all economic indexes and parameters considered.

The maritime transportation sector is one of the main contributors to global emissions of greenhouse gases (GHGs), volatile organic compounds (VOCs), particulate matter (PM), hazardous air pollutants, NOX and SOX. In particular, it is estimated that the CO2 emissions in this sector are about 1 Gt every year. The International Maritime Organization (IMO) adopted stringent emission limits in its Tier III regulation, most notably on NOX and SOX emissions and pledged to reach a reduction in greenhouse gas (GHG) emissions from international shipments by at least 50% by the year 2050, compared to 2008 emissions. For emission control areas (ECAs) these requirements are particularly strict and will be difficult to meet with traditional diesel engines and bunker fuels. Therefore, ship owners need to adopt solutions to bring emissions within these and other future limits by means of environmentally friendly fuels and high efficiency propulsion technologies. In this context, hydrogen and fuel cells play a crucial role, thanks to their low criteria pollutant and GHG emission. This paper presents a techno-economic feasibility study for replacing the conventional diesel engine powertrain, usually employed in Ro-Pax ferries, with an innovative system based on polymer electrolyte membrane fuel cell (PEMFC) technology. The ferry is actually powered by four diesel engines, which deliver a total output of 37.8 MW. The ferry also has two auxiliary engines which give an output of 4.0 MW and also two 2.0 MW bow thrusters for its manoeuvring. The energy analysis has allowed to define the hydrogen consumption for each cruise, as well as the optimal size of the innovative propulsion system. In particular, The PEMFC powertrain is sized at the same maximum power output as the main diesel engine and, thanks to the modular architecture of fuel cells and their flexible performance at partial load, the auxiliary engines are not contemplated. Moreover, in order to identify the best solution in terms of ship’s weight and space requirements, two hydrogen storage solutions based on compressed hydrogen technology and liquefied hydrogen technology, have been analyzed and compared. The economic assessment has been carried out by estimating the CAPEX and OPEX for each H2 storage technology by considering short-term, mid-term and long-term scenarios (from 2020 to 2050).

Power to substitute natural gas (PtSNG) is a promising technology to store intermittent renewable electricity as synthetic fuel. Power surplus on the electric grid is converted to hydrogen via water electrolysis and then to SNG via CO2 methanation. The SNG produced can be directly injected into the natural gas infrastructure for long-term and large-scale energy storage. Because of the fluctuating behaviour of the input energy source, the overall annual plant efficiency and SNG production are affected by the plant operation time and the standby strategy chosen. The re-use of internal (waste) heat for satisfying the energy requirements during critical moments can be crucial to achieving high annual efficiencies. In this study, the heat recovery from a PtSNG plant coupled with wind energy, based on proton exchange membrane electrolysis, adiabatic fixed bed methanation and membrane technology for SNG upgrading, is investigated. The proposed thermal recovery strategy involves the waste heat available from the methanation unit during the operation hours being accumulated by means of a two-tanks diathermic oil circuit. The stored heat is used to compensate for the heat losses of methanation reactors, during the hot-standby state. Two options to maintain the reactors at operating temperature have been assessed. The first requires that the diathermic oil transfers heat to a hydrogen stream, which is used to flush the reactors in order to guarantee the hot-standby conditions. The second option entails that the stored heat being recovered for electricity production through an Organic Rankine Cycle. The electricity produced is used to compensate the reactors heat losses by using electrical trace heating during the hot-standby hours, as well as to supply energy to ancillary equipment. The aim of the paper is to evaluate the technical feasibility of the proposed heat recovery strategies and how they impact on the annual plant performances. The results showed that the annual efficiencies on an LHV basis were found to be 44.0% and 44.3% for the thermal storage and electrical storage configurations, respectively.

The recent application of proteomics and metabolomics to clinical medicine has demonstrated their potential role in complementing genomics for a better understanding of diseases' patho-physiology. These technologies offer the clear opportunity to identify risk factors, disease-specific or stage-specific biomarkers and to predict therapeutic response. This article is an overview of the recent insights obtained by metabolomic and proteomic studies in inherited kidney disorders. Proteomics studies have allowed the definition of a detailed picture of protein composition, post-translational modifications and interactions in kidney-derived samples, improving our understanding of renal physiology, especially of tubular transport and primary cilium-related functions. Studies on patients' urine samples and experimental models of inherited kidney diseases have provided clues suggesting novel potential pathological mechanisms and biomarkers of disease, for example in polycystic kidney disease. Metabolomic-based studies have been recently applied to assess biological system disturbances caused by specific genetic mutations resulting in inherited kidney disorders. These studies have been mainly carried out on mouse and rat models of cystic and metabolic disorders (such as Fabry disease), and on patients' urine samples. They have provided a significant contribution in understanding disease pathophysiology, promoting the discovery of aberrant biochemical pathways and contributing to the development of targeted therapies.

Ammonia is a particularly promising hydrogen carrier due to its relatively low cost, high energy density, its liquid storage and to its production from renewable sources. Thus, in recent years, great attention is devoted to this fuel for realizing next generation refueling stations according to a carbon-free energy economy. In this paper a distributed onsite refueling station (200 kg/day of hydrogen filling 700-bar HFCEVs (Hybrid Fuel Cell Electric Vehicles) with about 5 kg of hydrogen in 5 min), based on ammonia feeding, is studied from the energy and economic point of views. The station is designed with a modular configuration consisting of more sections: i) the hydrogen production section, ii) the electric energy supplier section, iii) the compression and storage section and the refrigeration/dispenser section. The core of the station is the hydrogen production section that is based on an ammonia cracking reactor and its auxiliaries; the electric energy demand necessary for the station operation (i.e. the hydrogen compression and refrigeration) is satisfied by a PEMFC (Proton-Exchange Membrane Fuel Cell) power module. Energy performance, according to the hydrogen daily demand, has been evaluated and the estimation of the levelized cost of hydrogen (LCOH) has been carried out in order to establish the cost of the hydrogen at the pump that can assure the feasibility of this novel refueling station.

The use of biogas to produce “green hydrogen” represents an interesting solution for assuring sustainability in the energy and mobility sectors with lower costs and a continuous production. In this study, two hydrogen production plants using biogas as primary source, are studied and compared by applying the energy and exergy analyses for both the overall plant and components. The plants are designed as polygeneration systems able to produce high-pressure hydrogen, heat, and electricity for self-sustaining the energy consumption for purification, compression, and storage of the produced hydrogen. In this sense, these plants are proposed as on-site hydrogen production plants for the development of novel refueling stations. The two proposed plants differ for the hydrogen production process: i) a biogas-to-hydrogen plant through steam reforming, ii) a biogas-to-hydrogen plant through autothermal reforming. The results of the study have highlighted that the steam reforming-based configuration allows for achieving the best performance in terms of hydrogen production energy-based efficiency (59.8%) and hydrogen production exergy-based efficiency (59.4%). Moreover, the steam reforming-based configuration represents the best solution also considering the co-production of heat and hydrogen (energy-based efficiency 73.5% and exergy-based efficiency 64.4%), while the ATR-based layout, globally more exothermic, can be adopted when a larger local heat demand exists (energy-based efficiency 73.9% and exergy-based efficiency 54.8%).

The energy consumption in the residential sector, due to appliance electricity consumption, space heating, space cooling, and hot water usage, represents, in terms of total primary energy, around 40% in industrialized societies with similar contribution to carbon dioxide emissions. In order to achieve the greenhouse gas emission reduction goal, it is essential to develop strategies to make electricity, heating, and cooling in buildings more efficient and sustainable. In response to this issue, combined heat/cooling and power (cogeneration/trigeneration) systems are a solution since they generate simultaneously both useful heat and electricity from a single energy source. In recent years, fuel cell-based systems have gained great attention for application in the residential sector (0.5–5 kW) because, with respect to conventional power generation technologies, offer significant operational advantages, such as higher efficiencies, reduced noise and vibration, flexibility of fuel use lower emissions. Among the different types of fuel cells, solid oxide fuel cells (SOFCs) and proton exchange membrane fuel cell (PEMFCs) are the most suitable technologies for early market introduction, attracting the most attention and investment. Thus in this chapter, SOFC and PEMFC (both low and high temperature) microcogeneration/trigeneration systems are presented and examined by considering plant configurations, components, working conditions as well as operational strategies. Moreover, in the case of trigeneration applications different schemes for the absorption chilling unit are evaluated.

Onco-nephrology is an emerging field in medicine. Patients with cancer may suffer from kidney diseases because of the cancer itself and cancer-related therapy. It is critical for nephrologists to be knowledgeable of cancer biology and therapy in order to be fully integrated in the multidisciplinary team and optimally manage patients with cancer and kidney diseases. In a recent international meeting, the key issues in this challenging clinical interface were addressed, including many unresolved basic science questions, such as the high tumor incidence in kidney transplant recipients. To this end, 70 highly qualified faculty members were gathered from all over the world to discuss these issues in 8 plenary sessions, including 5 keynote lectures. In addition, 48 young nephrologists and oncologists were invited to present their original observations that were highlighted in 2 large poster sessions.

Polygeneration systems, designed for providing multiple energy services like hydrogen, heat and electricity, represent a possible solution for the transition to sustainable low-carbon energy systems, thanks to a substantial increase in the overall efficiency. A further step to reach zero-carbon energy systems can be done by using renewables as primary sources. In this study a biogas-based polygeneration system for the combined hydrogen, heat and electricity production is designed and analyzed from energy and economic points of view. The system consists of four sections: a biogas processing unit consisting in an autothermal reactor and a water gas shift reactor, an SOFC power unit, a hydrogen separation unit and a hydrogen compression/storage unit. The syngas generated in the autothermal reforming reactor is split in two fluxes: the first one is sent to the SOFC power unit for generating electricity and heat, the second one is sent to the water gas shift reactor to increase the hydrogen content. The hydrogen rich gas exiting the shifter, purified in the hydrogen separation unit (hydrogen quality is equal to 99.995%), is then compressed up to 820 bars and stored. The system behavior and the energy performances have been investigated by using the numerical simulation based on thermo-electrochemical models. Four operating conditions, related to different SOFC loads (from 30% to 100%), have been analyzed. The evaluated overall efficiencies range from 68.5% to 72.3% and the energy saving, calculated with respect to the separate production of hydrogen, heat and electricity, ranges from about 8% to 26%. The economic assessment, carried out by estimating the total capital investment and the plant profitability, has been performed by analyzing different management strategies (Base Load, Peaker, Ancillary Service and Mobility) and accounting for different technological development levels and market scenarios. Results show that the hydrogen production is the main contributor to the system economic sustainability thanks to the highest prices of hydrogen with respect to the electricity ones.

In this paper the tecno-economic assessment of two novel hydrogen production plants for small refueling stations is analyzed and compared. In the first one renewable ammonia, that is the hydrogen carrier, is cracked in a Solid Oxide Fuel Cell (SOFC) power unit that cogenerates the required hydrogen and the electric power needed for the hydrogen separation and storage. In the second one the hydrogen production is based on the autothermal reforming of the biogas obtained from an anaerobic digester and the electric power consumption for the hydrogen separation and storage is supplied by an SOFC power unit fed with part of the syngas exiting the biogas processing unit. In both the plant configurations the product hydrogen is separated by means of a Pd-Ag membrane separation unit and is compressed up to 820 bars by using an ionic compression system. The economic performance comparison is based on the evaluation of the levelized cost of the hydrogen (LCOH) for a decentralized hydrogen refueling station (HRS).

This paper focuses on a biofuel-based Multi-Energy System generating electricity, heat and hydrogen. The proposed system, that is conceived as refit option for an existing anaerobic digester plant in which the biomass is converted to biogas, consists of: i) a fuel processing unit, ii) a power production unit based on the SOFC (Solid Oxide Fuel Cell) technology, iii) a hydrogen separation, compression and storage unit. The aim of this study is to define the operating conditions that allow optimizing the plant performances by applying the exergy analysis that is an appropriate technique to assess and rank the irreversibility sources in energy processes. Thus, the exergy analysis has been performed for both the overall plant and main plant components and the main contributors to the overall losses have been evaluated. Moreover, the first principle efficiency and the second principle efficiency have been estimated. Results have highlighted that the fuel processor (the Auto-Thermal Reforming reactor) is the main contributor to the global exergy destruction (9.74% of the input biogas exergy). In terms of overall system performance the plant has an exergetic efficiency of 53.1% (it is equal to 37.7% for the H2 production).

This paper focuses on the performance assessment of a novel and efficient EES (electric energy storage) system based on ReSOC (reversible solid oxide cell) technology. The ReSOC is an electrochemical energy conversion device working at high temperature (600-1000°C) that can operate reversibly either as a fuel cell (SOFC) or as an electrolyzer (SOEC). In this study, a ReSOC unit fed by mixtures of CH4, CO, H2O and H2 is proposed and analyzed. In particular, in the SOFC mode, where electricity is generated, the reactant gas, mainly formed by CH4 and H2, is converted into a mixture of H2O and CO2. The exhausts from the SOFC are used as the reactant gas for the SOEC operation. During the electrolysis process, CH4 can be also produced thanks to the methanation reaction that, under proper operating conditions, occurs at the cathode of the solid oxide cell. The ReSOC unit behavior is investigated by developing a thermo-electrochemical model, able to predict its performance (i.e. roundtrip efficiency, polarization curve, thermally self-sustaining conditions) under different operating conditions. The ReSOC model, built with a modular architecture, is performed through thermodynamic, thermochemical and electrochemical sub-models taking into account mass and energy balances, chemical reactions (reforming, shifting reactions and methanation) and electro-chemical relationships. Available literature data have been used for the model validation and a calibration procedure has been performed in order to evaluate the best fitting values for the model parameters. Furthermore, in order to estimate the thermoneutral conditions in SOEC operating mode, the ReSOC thermal behavior has been analyzed under different operating temperatures. Results pointed out that, by feeding the cell with a syngas mixture, the reforming reaction (in the SOFC mode) and the methanation reaction (in the SOEC mode) allow to simplify the cell thermal management. Moreover, the best performance in terms of stack roundtrip efficiency (about 70%), can be reached operating the ReSOC at low temperature (700°C).

In this paper the integration of the energy production from programmable (biomass, waste) and not programmable (solar, wind) renewable sources is examined as an opportunity for increasing the share of electricity from renewable power plants, in order to overcome the major obstacles to their extensive penetration into the grid. The integration is performed by using hydrogen from intermittent renewable energy powered-electrolysis as gasification medium in conventional or advanced gasification systems for the waste treatment. The proposed integrated energy system consists of three main sections: i) the hydrogen production island; ii) the gasification island; iii) the power island. The assessment of the system performance has been conducted by considering two gasification technologies: hydro-gasification and hydro-plasma gasification. The performances comparison has been carried out in terms of syngas composition, energy consumptions and electric efficiency. Results have pointed out that the electric efficiencies of the integrated energy systems are in the range of 40% and 43%. Furthermore, it is found that by combining the storage of intermittent renewable energy sources with a waste gasification combined cycle power plant it is possible to achieve better performance with respect to the performance that can be obtained by storage and waste to energy systems operating separately.

In this paper a small-scale combined heat, hydrogen and power (CHHP) system, in which ammonia is used as a fuel for a solid oxide fuel cell (SOFC) to produce 100 kg/day of hydrogen (for refueling up to 20–30 fuel cell vehicles) as well as electricity for electric vehicles fast charging and heat for local use, is proposed. The study is carried out by means of experimental and numerical analysis; in particular, the behaviour of a single solid oxide cell fed by ammonia is investigated through experimental tests, while the design and the performance assessment of the proposed CHHP plant configurations are predicted by means of a thermo-electrochemical model, properly developed. The employed methodology and procedure are based on the SOFC power unit “sizing approach” that is performed through two different design concepts: (a) the minimum SOFC power unit size that allows to produce hydrogen and electricity for self-sustaining the electric power demand of the system; (b) the minimum SOFC power unit size that allows to produce hydrogen, to satisfy the system electric power demand and to supply electricity for EVs fast charging. Results in terms of performance (referred to the high heating values of input and output fuels) highlight that low values of electrical efficiency (14% for Concept_2) and thermal efficiency (≤15% for Concept_1 and Concept_2) are achieved, due to the high conversion of ammonia in hydrogen (the hydrogen production efficiencies are 70% and 42%, respectively), while the trigeneration efficiencies are high (81% and 71%). © 2018 Elsevier Ltd

Microbial fuel cells (MFCs) technology represents a new approach to the sustainable electric power production, thanks to the advantages of its green features. The performance and the cost efficiency of a MFC are affected by several factors, such as the reactor architecture, the microbial microflora and the “costs per power” ratio of the electrodes. For example, cathodes powered by platinum as catalyzer are really efficient, but also expensive. In this study, two materials for cathode were examined: i) an economical biochar-based material (BC), ii) an activated carbon (AC) cathode with a nickel mesh current collector and a polytetrafluoroethylene (PTFE) binder to limit oxygen diffusion to the anodic compartment. The performances were evaluated in terms of power density and current density.

Hybrid systems combine two or more power generating devices and make use of the synergism to generate maximum power and offer very high efficiencies. The aim of this work is to investigate the performance achievable from a small-scale hybrid power plant based on the integration between a micro gas turbine (MGT) and a solid oxide fuel cell (SOFC) fed by the syngas generated by a biomass downdraft gasifier (BG). The thermal energy needed to reach the turbine inlet temperature is supplied by the exhausts coming from a catalytic burner in which the SOFC anode and cathode off-gases are burnt. The hybrid BG-SOFC/MGT plant, based on a simplified configuration and realized considering components commercially available, is designed for optimizing not only the electric power generation, but also the thermal power production, in accordance with the promotion of decentralized CHP plants. The performance assessment has been carried out by means of a numerical model, based on thermodynamic/thermochemical approaches and realized by integrating the models of each plant section, developed by using the Aspen Plus software package. The models validation, performed by using experimental data, demonstrates that the results produced are close to those obtained from each unit, so that the overall integrated model can provide a sufficiently accurate prediction of the expected actual hybrid power plant. The effects of some operating parameters on cogeneration performances, such as the MGT pressure ratio and the S/C (steam to carbon) in the SOFC unit, have been evaluated and analyzed. Results show that the best performances are achieved by assuming the MGT pressure ratio equal to 4.5 and the S/C equal to 0. In this case the electric power is 262 kW (SOFC supplies 180 kW), the thermal power is 405 kW and the electric (AC) and cogeneration efficiencies are 35% and 88%, respectively.

The Reversible Solid Oxide Cell (ReSOC), operating under electrolysis and fuel cell modes, is a promising technology that, thanks to high efficiency and fuel flexibility, can be applied in the development of Electric Energy Storage (EES) systems. Several critical issues are required to be addressed, which are specific to ReSOC, such as oxidant electrode performance and reversibility, set of materials, cell/stack design and operating parameters suitable for reversible operation. Moreover, the optimal system design, to demonstrate the feasibility of the technology as well as the Balance of Plant (BoP) components at high operating temperatures, are also challenging factors. Therefore, the objective of this work is to propose an HEES (Hydrogen-based Electric Energy Storage) system for distributed scale energy storage applications (100–200 kW) by taking into account some of these challenging issues. The proposed system consists of (i) the BoP section needed for the energy storage, (ii) the ReSOC module operating in reversible mode, (iii) the BoP section needed for the energy production. In order to guarantee a competitive roundtrip efficiency, the design of the solid oxide cell unit and of the supporting auxiliary systems (BoP components) has been performed without external heat sources for the heating of feeding streams and for the thermal requirements of the ReSOC during its operation in the electrolysis mode. The study has been carried out by developing a steady-state thermo-electrochemical model that has been built with a modular architecture. The model, validated by means of experimental data, has been used to assist the system designing and the thermal management optimization to ensure high performances from electric and thermal points of view. Results highlight that the proposed system is able to store and use the renewable energy with a roundtrip efficiency of 60%. Moreover, thanks to the optimized thermal integration, additional heat is available for cogeneration purpose, with a cogeneration efficiency of 91%.

In this study the performances of small cogeneration power plants fed by biomass and based on conventional and advanced technologies are presented. Three system configurations have been considered and analyzed. They are characterized by: a) a biomass gasification (G) unit, based on down-draft technology; b) a power unit, based on the SOFC technology or on the micro gas turbine (MGT) technology or on a hybrid configuration SOFC-MGT; c) a thermal recovery unit. The energy analysis of the proposed power plants has been conducted by using thermochemical/thermodynamic models able to study the integrated systems and each unit in terms of operating and performance parameters. © 2017 The Authors.

In this paper a generalized model, based on system-level approach, for predicting the High Temperature Fuel Cells (HTFCs) behavior and performance is presented. The system-level model allows to forecast the HTFC performance under different operating conditions (cell temperature, anode off-gas recirculation, reactants temperatures, fuel and oxidant utilization factors, etc.) and cell design (tubular and planar configurations and with co-flow, counter-flow and cross-flow arrangements). Mass and energy balances are solved by considering both the electrochemical (i.e. electro-oxidation of hydrogen) and thermochemical reactions (i.e. reforming and shifting reactions) which occur in the anode and cathode sides and by applying different equations systems to take into account the type of fuel cell (MCFC or SOFC). The ability of the proposed model in the HTFCs performance prediction is pointed out by the model validation carried out by using experimental data and by analyzing the impact of the model calibration parameters on the cell voltage calculation carried out by means of a sensitivity analysis. Numerical results show that the model allows to characterize the behavior of the HTFCs with a good approximation so, thanks to the simplicity of the simulation procedure and to the small computational time efforts, it can be a useful tool for predicting the performance of hybrid power plants or more complex systems in which the fuel cell is one of the main components.

The development of fuel cells is promised to enable the distributed generation of electricity in the near future. However, the infrastructure for production and distribution of hydrogen, the fuel of choice for fuel cells, is currently lacking. Efficient production of hydrogen from fuels that have existing infrastructure (e.g., natural gas, gasoline or LPG) would remove a major drawback to use fuel cells for distributed power generation. The aim of this paper is to define the better operating conditions of an innovative hydrogen generation system (the fuel processing system, FP) based on LPG steam reforming, equipped with a membrane shift reactor, and integrated with a PEMFC (Proton Exchange Membrane Fuel Cell) stack of 5 kWel. With respect to the conventional hydrogen generation systems, the use of membrane reactors (MRs) technology allows to increase the hydrogen generation and to simplify the FP-PEMFC plant, because the CO removal system, needed to reduce the CO content at levels required by the PEMFC, is avoided. Therefore, in order to identify the optimal operating conditions of the FP-PEMFC system, a sensitivity analysis on the fuel processing system has been carried out by varying the main operating parameters of both the reforming reactor and the membrane water gas shift reactor. The sensitivity analysis has been performed by means of a thermochemical model properly developed. Results show that the thermal efficiency of the fuel processing system is maximize (82.4%, referred to the HHV of fuels) at a reforming temperature of 800 °C, a reforming pressure of 8 bar, and an S/C molar ratio equal to 6. In the nominal operating condition of the PEMFC stack, the FP-PEMFC system efficiency is 36.1% (39.0% respect to the LHV).

In this paper, the first experimental investigations on a pre-commercial natural gas steam reformer have been presented. The fuel processor unit contains the elements as follows: desulfurizer, steam reformer reactor, CO shift converter, CO preferential oxidation (PROX) reactor, steam generator, burner and heat exchangers. The fuel processor produces 45 Nl/min of syngas in which the hydrogen concentration is about 75 vol.% and the other chemical species are nitrogen, carbon dioxide and methane. The CO concentration is below 1 ppmv, so that this reforming system is suitable for the integration with a PEM fuel cell stack. The experimental activity has been conducted in a test station, properly designed to measure the behaviour of the fuel processor. The laboratory test facility is equipped by a National Instruments Compact DAQ real-time data acquisition and control system running Labview™ software. Several measurement instruments and controlling devices have been installed. Furthermore, a gas chromatograph is used to measure the product gas composition during the tests. The aim of this work has been to analyze the behaviour of this pre-commercial steam reforming unit during its operation cycle in different operating conditions (full and partial loads) in order to study its integration with a PEM fuel cell for developing a high efficiency microcogeneration system for residential applications.

In Part A of this two-paper work, a novel approach for treatment of CO2 from fossil fired power plants was studied. This approach consists of flue gases utilization as co-reactants in a catalytic process, the tri-reforming process, to generate a synthesis gas suitable in chemical industries for production of chemicals (methanol, DME, ammonia and urea, etc.). In particular, the further conversion of syngas to a transportation fuel, such as methanol, is an attractive solution to introduce near zero-emission technologies (i.e. fuel cells) in vehicular applications. In fact, the methanol can be used in DMFC (Direct Methanol Fuel Cell) or as fuel for on-board reforming to produce hydrogen for PEMFC (Proton Exchange Membrane Fuel Cell). Thus, in order to analyze the tri-reforming process, integrated systems, ITRPPs (Integrated Tri-Reforming Power Plants) for co-generation of electrical power and synthesis gas were defined and their performances were investigated. The integrated systems consist of a power island, based on a thermal power plant (a steam turbine power plant, ITRPP-SC, and a gas turbine combined cycle ITRPP-CC), and a methane tri-reforming island. This paper (Part B) focuses on the methanol synthesis process by using the syngas produced by the methane tri-reforming island. Therefore, the ITRPP plant configurations have been modified adding the methanol synthesis island and the performances of these integrated plants, that co-produce electrical power and methanol, have been evaluated. The energy and environmental analysis has been carried out by means of a numerical approach which has allowed to calculate the syngas composition, to define the energy and mass balances and to estimate the CO2 emissions for each configurations. Furthermore, the conventional technology for methanol generation, based on methane steam reforming with carbon dioxide addition, has been analysed and the performances of integrated systems (ISRPP, Integrated Steam Reforming Power Plant), that consist of a power island with a CO2 capture unit, the methane reforming island and the methanol synthesis island, have been investigated. Results point out that the energy and environmental sustainability of the integrated plants, based on the tri-reforming technology for the co-generation of electrical power and methanol, depends on the flue gases composition. Thus, the tri-reforming process can be considered a promising approach for treatment of CO2 when the exhausts contain low oxygen concentrations (i.e. flue gases from steam cycle power plant).

The waste management is become a very crucial issue in many countries, due to the ever-increasing amount of waste material, both domiciliary and industrial, generated. The main strategies for the waste management are the increase of material recovery (MR) which can reduce the landfill disposal, the improvement of energy recovery (ER) from waste and the minimization of the environmental impact. Recent studies have focused on an innovative technology, the plasma gasification, that has been demonstrated as one of the most effective and environmentally friendly methods for solid waste treatment and energy utilization. In this paper, a plasma gasification process based on plasma torch technology has been investigated by developing a thermochemical model (EPJ, EquiPlasmaJet) able to estimate both the syngas composition and the energy required for the gasification reactions. The EPJ model has been employed to predict the syngas composition and the energy balance of a RDF (refuse derived fuel) plasma arc gasification reactor using air as plasma gas, and, in order to define the optimal operating conditions three different configurations have been investigated. Results show that, in the better plant solution, the plasma gasification efficiency is 69.1% (LHV) and the lower heating value of the syngas generated is about 9 MJ/kg. Furthermore in order to evaluate the suitability of this technology for energy recovery from solid wastes, the integration of the optimum plasma gasification system (PGS) with a gas turbine combined cycle (GTCC) has been analysed and the performance of the resulting integrated plasma gasification combined cycle (IPGCC) has been evaluated. The system efficiency (31% LHV) is very high in comparison with the efficiency of conventional technologies based on waste incineration (20%).

Recent studies have demonstrated the possibility of an efficient and clean employment of fossil fuels by using a new concept of cogeneration of power and hydrogen. This concept is based on the considerations that steam power plants discharge heat by condensing steam, while coal gasification plants require steam to produce hydrogen: an integration of these systems results in a very high conversion efficiency. This two-part paper analyses these plants, the so-called combined power and hydrogen (CPH) systems, and compares their performances with a plant for only hydrogen production, the integrated gasifier for hydrogen production (IGHP) plant, by means of new parameters, the marginal efficiency and the apparent efficiency. The use of these parameters requires the definition of a IGHP reference plant, which must be designed to maximize the hydrogen production with minimum power consumption. Thus, Part A investigates the IGHP plants to define the reference plant, Part B analyses and evaluates different plant configurations of CPH systems by comparison with the IGHP reference plant. In order to identify the thermodynamically favourable operating conditions for the IGHP plant (maximum hydrogen production with minimum power consumption), a sensitivity analysis has been conducted at a gasification temperature of 1350 °C, varying the gasification pressure from 1 to 80 bar, the steam to carbon ratio at the gasifier, S / C , from 0.1 to 0.9, and the steam to carbon ratio at the water–gas shift reactors, S SHIFT / C , from 0.6 to 1.2. Results show that the hydrogen production depends significantly on the steam to carbon ratio at both the gasifier and the shift reactors, while the influence of gasification pressure is negligible even though it is a very important factor to minimize the power consumption (or to generate electrical power). Better performances are achieved for a gasification pressure of 70 bar, a S / C ratio of 0.2, and a S SHIFT / C ratio equal to 1.2. The hydrogen production efficiency, referred to the HHV, is 72%.

Energy systems based on fuel cells technology can have a strategic role in the range of small-size power generation for the sustainable energy development. In order to enhance their performance, it is possible to recover the “waste heat” from the fuel cells, for producing or thermal power (cogeneration systems) or further electric power by means of a bottoming power cycle (combined systems). In this work an advanced system based on the integration between a HT-PEMFC (high temperature polymer electrolyte membrane fuel cell) power unit and an ORC (organic Rankine cycle) plant, has been proposed and analysed as suitable energy power plant for supplying electric and thermal energies to a stand-alone residential utility. The system can operate both as cogeneration system, in which the electric and thermal loads are satisfied by the HT-PEMFC power unit and as electric generation system, in which the low temperature heat recovered from the fuel cells is used as energy source in the ORC plant for increasing the electric power production. A numerical model, able to characterize the behavior and to predict the performance of the HT-PEMFC/ORC system under different working conditions, has been developed by using the AspenPlus™ code.

In this paper conventional and advanced biomass gasification power plants designed for small cogeneration application are defined. The CHP plants consist of a gasification unit, that employs a downdraft gasifier, and a power unit based on a microturbine in the case of conventional configuration, and on a solid oxide fuel cell module, in the case of advanced configuration. The plants are sized to supply about 100 kW of electrical power. In order to investigate and to analyze the performances of the two plant configurations, in terms of thermal and electrical efficiencies, numerical models have been developed by using thermochemical and thermodynamic codes.

This paper deals with a system-level modelling for the performance prediction of power units based on fuel cells that are designed to work witha syngas or with a fuel that can contain CO, such as HT-PEMFCs, MCFCs and SOFCs. The model solves mass and energy balances and allows to estimate the polarization curves by applying mathematical equations that take into account the different type of fuel cell. The empirical coefficients of the model equations have been tuned by using available experimental data.