Experimental investigation of CO2 separation from lignite flue gases by 100 cm single Molten Carbonate Fuel Cell

The paper presents an experimental investigation of using a Molten Carbonate Fuel Cell (MCFC) to reduce CO₂ emission from the flue gas of a lignite fired boiler. The MCFC is placed in the flue gas stream and separates CO₂ from the cathode side to the anode side. As a result, a mixture of CO₂ and H₂O is obtained from which pure CO₂ can be obtained through condensation of water and carbon dioxide. The main advantages of this solution are: additional electricity generated, reduced CO₂ emissions and higher system efficiency. The results obtained show that the use of an MCFC could reduce CO₂ emissions by 90% with over 30% efficiency in additional power generation.     

Characteristics and economic evaluation of a CO2-capturing repowering system with oxy-fuel combustion for utilizing exhaust gas of molten carbonate fuel cell (MCFC)

A scale of 2.4 MW molten carbonate fuel cell (MCFC) was taken to construct a high-efficiency and economic power generation system without CO₂ emission for utilizing its exhaust gas. A conventional steam turbine power generation system (STPS) is evaluated and the net generated power (NGP) is estimated to be only 131 kW and the STPS is not economically feasible. A CO₂-caputuring repowering system is proposed, where low temperature steam produced at heat recovery steam generator (HRSG) by using the MCFC exhaust gas is utilized as a main working fluid of a gas turbine, and the temperature of the steam is raised by combusting fuel in a combustor by using pure oxygen, not the air. It is estimated that NGP of the proposed system is 253 kW, and CO₂ reduction amount is 583 t-CO₂/y, compared to 302 t-CO₂/y for the STPS and that the proposed system becomes economically feasible if a CO₂ emission credit higher than 20 $/t-CO₂ can be granted. It is also estimated, when its turbine inlet temperature is increased from 850 °C to 1000 °C, CO₂-capturing is not cost-consuming but becomes to be profitable, owing to improved power generation characteristics.     

Carbon dioxide separation from high temperature fuel cell power plants

High temperature fuel cell technologies, solid oxide fuel cells (SOFCs) and molten carbonate fuel cells (MCFCs), are considered for their potential application to carbon dioxide emission control. Both technologies feature electrochemical oxidisation of natural gas reformed fuels, avoiding the mixture of air and fuel flows and dilution with nitrogen and oxygen of the oxidised products; a preliminary analysis shows how the different mechanism of ion transport attributes each technology a specific advantage for the application to CO₂ separation. The paper then compares in the first part the most promising cycle configurations based on high efficiency integrated SOFC/gas turbine “hybrid” cycles, where CO₂ is separated with absorption systems or with the eventual adoption of a second SOFC module acting as an “afterburner”. The second part of the paper discusses how a MCFC plant could be “retrofitted” to a conventional fossil-fuel power station, giving the possibility of draining the majority of CO₂ from the stack exhaust while keeping the overall cycle electrical efficiency approximately unchanged.     

Biomass-fired cogeneration systems with CO2 capture and storage

In this study, we estimate and analyze the CO₂ mitigation costs of large-scale biomass-fired cogeneration technologies with CO₂ capture and storage. The CO₂ mitigation cost indicates the minimum economic incentive required (e.g. in the form of a carbon tax) to make the cost of a less carbon intensive system equal to the cost of a reference system. If carbon (as CO₂) is captured from biomass-fired energy systems, the systems could in principle be negative CO₂ emitting energy systems. CO₂ capture and storage from energy systems however, leads to reduced energy efficiency, higher investment costs, and increased costs of end products compared with energy systems in which CO₂ is vented. Here, we have analyzed biomass-fired cogeneration plants based on steam turbine technology (CHP-BST) and integrated gasification combined cycle technology (CHP-BIGCC). Three different scales were considered to analyze the scale effects. Logging residues was assumed as biomass feedstock. Two methods were used to estimate and compare the CO₂ mitigation cost. In the first method, the cogenerated power was credited based on avoided power production in stand-alone plants and in the second method the same reference output was produced from all systems. Biomass-fired CHP-BIGCC with CO₂ capture and storage was found very energy and emission efficient and cost competitive compared with other conversion systems.     

Technologies for increasing CO2 concentration in exhaust gas from natural gas-fired power production with post-combustion, amine-based CO2 capture

Enhanced CO₂ concentration in exhaust gas is regarded as a potentially effective method to reduce the high electrical efficiency penalty caused by CO₂ chemical absorption in post-combustion capture systems. The present work evaluates the effect of increasing CO₂ concentration in the exhaust gas of gas turbine based power plant by four different methods: exhaust gas recirculation (EGR), humidification (EvGT), supplementary firing (SFC) and external firing (EFC). Efforts have been focused on the impacts on cycle efficiency, combustion, gas turbine components, and cost. The results show that the combined cycle with EGR has the capability to change the molar fraction of CO₂ with the largest range, from 3.8 mol% to at least 10 mol%, and with the highest electrical efficiency. The EvGT cycle has relatively low additional cost impact as it does not require any bottoming cycle. The externally fired method was found to have the minimum impacts on both combustion and turbomachinery.     

Energy,exergy, and environmental (3E) assessments of an integrated molten carbonate fuel cell (MCFC), Stirling engine and organic Rankine cycle (ORC) cogeneration system fed by a biomass-fueled gasifier

In this paper, a novel syngas-fed combined cogeneration plant, integrating a biomass gasifier, a molten carbonate fuel cell (MCFC), a heat recovery steam generator (HRSG) unit, a Stirling engine, and an organic Rankine cycle (ORC), is introduced and thermodynamically analyzed to recognize its potentials compared to the previous solo/combined systems. For the proposed system, energetic, exergetic as well as environmental evaluations are performed. Based on the results, the gasifier and the fuel cell have a significant contribution to the exergy destruction of the system. Through a parametric study, the current density and the stack temperature difference are known as the main effective factors on the plant performance. Meanwhile, dividing the whole system into three sub-models, i.e., model (1): power production plant including the gasifier and MCFC without including Stirling engine, HRSG, and ORC unit, model (2): the cogeneration system without ORC unit, and model (3): the whole cogeneration system, an environmental impact assessment is carried out regarding CO₂ emission. Considering paper as biomass revealed that maximum value of exergy efficiency is 50.18% with CO₂ emissions of 28.9 × 10⁻² t.MWh⁻¹ which compared to the solo MCFC system indicates 28.40% increase and 13.3 × 10⁻² t.MWh⁻¹ decrease in exergy efficiency and CO₂ emission, respectively.     

CO<Subscript>2</Subscript> mitigation in coal gasification cogeneration systems with integration of the shift reaction,CO<Subscript>2</Subscript> absorption and methanol production

Cogeneration of electricity and liquid fuel can achieve higher efficiencies than electricity generation alone in Integrated Gasification Combined Cycle (IGCC), and cogeneration systems are also expected to mitigate CO₂ emissions. A proposed methanol-electricity cogeneration system was analyzed in this paper using exergy method to evaluate the specified system. A simple cogeneration scheme and a complicated scheme including the shift reaction and CO₂ removal were compared. The results show that the complicated scheme consumes more energy, but has a higher methanol synthesis ratio with partial capture of CO₂. In those methanol and electricity cogeneration systems, the CO₂ mitigation is not merely an additional process that consumes energy and reduces the overall efficiency, but is integrated into the methanol production.     

Thermoeconomic analysis of pressurized hybrid SOFC systems with CO2 separation

In this paper, the results of the thermodynamic and economic analyses of distributed power generation plants (1.5 MWe) are described and compared. The results of an exergetic analysis are also reported, as well as the thermodynamic details of the most significant streams of the plants. The integration of different hybrid solid oxide fuel cell (SOFC) system CO₂ separation technologies characterizes the power plants proposed. A hybrid system with a tubular SOFC fed with natural gas with internal reforming has been taken as reference plant. Two different technologies have been considered for the same base system to obtain a low CO₂ emission plant. The first technology involved a fuel decarbonization and CO₂ separation process placed before the system feed, while the second integrated the CO₂ separation and the energy cycle. The first option employed fuel processing, a technology (amine chemical absorption) viable for short-term implementation in real installations while the second option provided the CO₂ separation by condensing the steam from the system exhaust. The results obtained, using a Web-based Thermo Economic Modular Program software, developed by the Thermochemical Power Group of the University of Genoa, showed that the thermodynamic and economic impact of the adoption of zero emission cycle layouts based on hybrid systems was relevant.     

Comparison study on different ITM‐integrated MCFC hybrid systems with CO2 recovery using sweep gas

Previous study shows the ITM (oxygen ion transfer membrane)‐integrated MCFC (molten carbonate fuel cell) hybrid system with CO₂ recovery can maintain high efficiency; however, the oxygen partial pressure on the ITM permeate side is usually 1 atm, which requires a very high pressure ratio of the ITM air compressor in order to separate the oxygen; using the sweep gas can solve this problem. In this paper the ITM‐integrated MCFC hybrid systems with CO₂ recovery using different sweep gases are studied. With the Aspen plus software, two systems with different sweep gases are established, and their performances are compared with the benchmark system without sweep gas; the effects of key parameters on the optimum system performance are also investigated. Results show that compared with the benchmark system, the efficiencies of the systems with sweep gases are increased and the pressure ratios of the air compressors are decreased; the system using pure CO₂ as sweep gas can improve the system efficiency by 1.25%, which is superior to the system using the mixture gas of CO₂ and H₂O as sweep gas. Achievements from this paper will provide a valuable reference for CO₂ recovery from the MCFC hybrid power system with lower energy consumption. Copyright © 2016 John Wiley & Sons, Ltd.     

Power and cogeneration technology environomic performance typification in the context of CO2 abatement part I: Power generation

In this series of two articles, the concepts and approaches of environomic (thermodynamic, economic and environmental) performance ‘Typification’ of power generation technologies (Part I) and of combined heat and power (CHP) cogeneration technologies (Part II) in the context of CO₂ abatement are introduced. A methodology is then proposed for a flexible and fast project based power or CHP cogeneration system design evaluation though post-optimization integration of the operating and capital costs. This allows to effectively deal with the uncertainty of the project specific design and operation conditions (fuel, electricity and heat selling prices, project financial conditions such as investment amortization periods, annual operating hours, etc). Furthermore, the uncertainties linked to the external cost such as the CO₂ tax level under a tax scheme or the CO₂ permit price in the emission trading market can be assessed.     

Post-combustion carbon dioxide capture: Evolution towards utilization of nanomaterials

Carbon dioxide (CO₂) is not the gas that gives the most severe global warming impact among the greenhouse gases (GHGs). However, its highest annual emission into the atmosphere makes it the most imperative anthropogenic GHG. This elevated emission is primarily coming from fossil fuel power plants. Hence, post-combustion CO₂ removal from power plants becomes crucial in global warming mitigation as it can be retrofitted directly into an existing plant. CO₂ removal technology nowadays is utilizing solvent-based sorbents, such as amine solutions and ionic liquids. Many extensive research works have been carrying out to improve the constraints of existing technology. In this paper, a general review on existing CO₂ removal technologies, existing research works on CO₂ removal sorbents was done. In conjunction with that, we will look into the potential and development of nanomaterials as CO₂ removal sorbents in the future. Nanomaterials have shown their potentials in CO₂ capture with its high surface area and adjustable properties and characteristics. Many limitations in existing technology were found improvable by nanomaterials.     

Trade-off in emissions of acid gas pollutants and of carbon dioxide in fossil fuel power plants with carbon capture

This paper investigates the impact of capture of carbon dioxide (CO₂) from fossil fuel power plants on the emissions of nitrogen oxides (NO_X) and sulphur oxides (SO_X), which are acid gas pollutants. This was done by estimating the emissions of these chemical compounds from natural gas combined cycle and pulverized coal plants, equipped with post-combustion carbon capture technology for the removal of CO₂ from their flue gases, and comparing them with the emissions of similar plants without CO₂ capture. The capture of CO₂ is not likely to increase the emissions of acid gas pollutants from individual power plants; on the contrary, some NO_X and SO_X will also be removed during the capture of CO₂. The large-scale implementation of carbon capture is however likely to increase the emission levels of NO_X from the power sector due to the reduced efficiency of power plants equipped with capture technologies. Furthermore, SO_X emissions from coal plants should be decreased to avoid significant losses of the chemicals that are used to capture CO₂. The increase in the quantity of NO_X emissions will be however low, estimated at 5% for the natural gas power plant park and 24% for the coal plants, while the emissions of SO_X from coal fired plants will be reduced by as much as 99% when at least 80% of the CO₂ generated will be captured.     

Efficiency enhancement of pressurized oxy‐coal power plant with heat integration

The oxy‐coal combustion with carbon dioxide capture and sequestration is among the promising clean coal technologies for reducing CO₂ emissions. Because most of oxy‐coal power plants need to cope with energy penalties from air separation and CO₂ compressor units, the pressurized combustion is added to reduce the electricity demand for the CCS system, and the waste heat of the pressurized flue gas is recovered by the heat integration technique to increase the power generation from steam turbines. Finally, the efficiency enhancement of a 100 MW_e‐scale power plant is successfully validated by Aspen Plus simulation. Copyright © 2014 John Wiley & Sons, Ltd.     

Multiobjective optimization for exergoeconomic analysis of an integrated cogeneration system

In this paper, a novel cogeneration system integrating Kalina cycle, CO₂ chemical absorption, process, and flash‐binary cycle is proposed to remove acid gases in the exhaust gas of solid oxide fuel cell (SOFC) system, improve the waste heat utilization, and reduce the cold energy consumed during CO₂ capture. In the CO₂ chemical absorption process, the methyldiethanolamine (MDEA) aqueous solution is utilized as a solvent, and feed temperature and absorber pressure are optimized via Aspen Plus software. The single‐objective and multiobjective optimization are carried out for the flash‐binary cycle subsystem. Results show that when the multiobjective optimization is applied to identify the exergoeconomic condition, the cogeneration system can simultaneously satisfy the high thermodynamic cycle efficiency and also the low product unit cost. The optimal results of the exergy efficiency, product unit cost, and normalized CO₂ emissions obtained by Pareto chart were 75.84%, 3.248 $/GJ, and 13.14 kg/MWhr, respectively.     

Performance evaluation of integrated gasification solid oxide fuel cell/gas turbine systems including carbon dioxide capture

In this study, system layouts for integrated gasification solid oxide fuel cell/gas turbine (IG-SOFC/GT) systems were proposed and their performance was comparatively evaluated. A baseline IGCC was simulated, and the calculation models were validated. Based on the IGCC system, two IG-SOFC/GT system layouts with different SOFC thermal management methods were established, and their performance was analyzed. The IG-SOFC/GT systems were found to produce much higher power and better efficiency than the IGCC. With regard to SOFC thermal management, the exit gas recirculation scheme showed better performance than the cathode heat exchange scheme. The impact of CO₂ capture was investigated in both the IGCC and IG-SOFC/GT systems, and the penalties in power output and efficiency due to pre-combustion CO₂ capture were found to be milder in the IG-SOFC/GT systems than in the IGCC. An IG-SOFC/GT system adopting oxy-combustion-based CO₂ capture was proposed, and its thermal efficiency was predicted to be sensibly higher than the system with pre-combustion CO₂ capture. Its net power output was predicted to be less than that of the system with pre-combustion technology, but was still much larger than that of the IGCC with pre-combustion CO₂ capture.     

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

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

Effect of sulfur contaminants on MCFC performance

Molten carbonate fuel cells (MCFC) used as carbon dioxide separation units in integrated fuel cell and conventional power generation can potentially reduce carbon emission from fossil fuel power production. The MCFC can utilize CO₂ in combustion flue gas at the cathode as oxidant and concentrate it at the anode through the cell reaction and thereby simplifying capture and storage. However, combustion flue gas often contains sulfur dioxide which, if entering the cathode, causes performance degradation by corrosion and by poisoning of the fuel cell. The effect of contaminating an MCFC with low concentrations of both SO₂ at the cathode and H₂S at the anode was studied. The poisoning mechanism of SO₂ is believed to be that of sulfur transfer through the electrolyte and formation of H₂S at the anode. By using a small button cell setup in which the anode and cathode behavior can be studied separately, the anodic poisoning from SO₂ in oxidant gas can be directly compared to that of H₂S in fuel gas. Measurements were performed with SO₂ added to oxidant gas in concentrations up to 24 ppm, both for short-term (90 min) and for long-term (100 h) contaminant exposure. The poisoning effect of H₂S was studied for gas compositions with high- and low concentration of H₂ in fuel gas. The H₂S was added to the fuel gas stream in concentrations of 1, 2 and 4 ppm. Results show that the effect of SO₂ in oxidant gas was significant after 100 h exposure with 8 ppm, and for short-term exposure above 12 ppm. The effect of SO₂ was also seen on the anode side, supporting the theory of a sulfur transfer mechanism and H₂S poisoning. The effect on anode polarization of H₂S in fuel gas was equivalent to that of SO₂ in oxidant gas.     

Combined cycle versus one thousand diesel power plants: pollutant emissions,ecological efficiency and economic analysis

The increase in the use of natural gas in Brazil has stimulated public and private sectors to analyse the possibility of using combined cycle systems for generation of electrical energy. Gas turbine combined cycle power plants are becoming increasingly common due to their high efficiency, short lead times, and ability to meet environmental standards. Power is produced in a generator linked directly to the gas turbine. The gas turbine exhaust gases are sent to a heat recovery steam generator to produce superheated steam that can be used in a steam turbine to produce additional power. In this paper a comparative study between a 1000 MW combined cycle power plant and 1000 kW diesel power plant is presented. In first step, the energetic situation in Brazil, the needs of the electric sector modification and the needs of demand management and integrated means planning are clarified. In another step the characteristics of large and small thermoelectric power plants that use natural gas and diesel fuel, respectively, are presented. The ecological efficiency levels of each type of power plant is considered in the discussion, presenting the emissions of particulate material, sulphur dioxide (SO₂), carbon dioxide (CO₂) and nitrogen oxides (NO_x).     

Natural gas combined cycle with exhaust gas recirculation and CO2 capture at part-load operation

This paper aims to evaluate part-load operation of a natural gas combined cycle (NGCC) power plant with exhaust gas recirculation (EGR) and a CO₂ capture plant. Several studies have demonstrated the feasibility and the advantages of EGR at full load, but operation at part load is also important because it is a common condition when NGCC power plants are being used as backup for renewables. The results of this study show that the number of absorber trains is reduced from 4 to 3 with EGR. The efficiency of the NGCC plant with EGR was 0.5% points higher than a conventional NGCC at full load as a result of a higher CO₂ concentration in the flue gas. However, this efficiency advantage decreased as the load was reduced from 100% to 50%, with both cases presenting the same efficiency at 50% load. This means that there was no benefit from the effect of EGR at lower loads. The efficiency of a NGCC plant with EGR and CO₂ capture configuration decreased from 52.6% to 45.9% when the load was reduced from 100% to 50% compared with a conventional NGCC where the efficiency changed from 52.1% to 45.9%. It was concluded that a NGCC plant with EGR and CO₂ capture is viable, results in lower capital costs due to the smaller number of absorber trains and yields slightly higher efficiencies, for operation at part-load down to 50%.     

Production of hydrogen-rich fuels for pre-combustion carbon capture in power plants: A thermodynamic assessment

Hydrogen-fueled plants can play an important role in the field of carbon capture and storage, because they facilitate the mitigation of harmful emissions. In this paper, two combined-cycle power plants with pre-combustion CO₂ capture are examined, in which natural gas is converted into a hydrogen-rich fuel through reforming. The first plant considered operates with a hydrogen-separating membrane and the second with an autothermal reformer. The two plants are compared to a reference plant without CO₂ capture and briefly to alternative oxy-fuel and post-combustion capture technologies. It is found that both plants suffer high penalties caused by the high energy requirements of the reforming components and the CO₂ compression units. Additionally, both plants appear inferior to alternative capture technologies. When comparing the two reforming plants, the plant with the hydrogen-separating membrane operates somewhat more efficiently. However, in order to make these technologies more attractive, their thermodynamic efficiency must be enhanced. The potential for improving the efficiencies of these plants is revealed by an exergetic analysis.