Comparative study of chemical absorbents in postcombustion CO2 capture

In order to reduce CO₂ emissions from a power plant, CO₂ can be captured either from the syngas that is to be burned or from the flue gases exiting the energy conversion process. Postcombustion capture has the advantage that it can be applied to retrofit existing power plants. In this paper the authors compare two primary amines (MEA and DGA) to ammonia with respect to their capability to capture CO₂ from a flue gas stream. The ammonia process captures CO₂ by formation of stable salts, which are separated from the solvent stream by filtration or sedimentation. These salts can be used commercially as fertilizers. Energy requirements are greatly reduced, since no heat is required for solvent regeneration, and no compression of the separated CO₂ is necessary. Energy, however, is required for the reduction of ammonia emissions. In order to obtain the solid ammonia salts, their solubility has to be reduced by modification of the solvent and by lowering absorption temperature. With and without separation of the salt products, ammonia proved to be an alternative solvent with high CO₂ removal efficiency. Simulation of all processes was carried out with Aspen Plus^® and compared to experimental results for CO₂ scrubbing with ammonia.     

Comparison of MEA and DGA performance for CO2 capture under different operational conditions

Carbon capture and storage from flue gases is the most common method to reduce greenhouse gas emissions. Using a primary amine as the solvent of CO₂ capture unit is popular because of its high activity and ability to be used for streams with low concentration and low partial pressure of CO₂. Monoethanolamine(MEA) and Diglycolamine(DGA) are the most common kinds of primary amines which have been traditionally used in many natural gas sweetening plants. In this research, the capture plant has been designed for these two solvents at various CO₂ concentrations in the feed flue gas. This paper proposes different possible alters to overcome the high energy requirements of capture plant. It also presents the results of technical evaluation of different parameters, in order to design an actual plant with minimum energy requirement. The results of different parameters show that for DGA solvent, there will be an improvement in overall energy usage in the capture plant rather than MEA for some special cases. To gain the practical results, actual stages have been used for absorber and stripper instead of equilibrium stages. Copyright © 2011 John Wiley & Sons, Ltd.     

Cycle analysis of low and high H2 utilization SOFC/gas turbine combined cycle for CO2 recovery

A major factor in global warming is CO₂ emission from thermal power plants, which burn fossil fuels. One technology proposed to prevent global warming is CO₂ recovery from combustion flue gas and the sequestration of CO₂ underground or near the ocean bed. Solid oxide fuel cell (SOFC) can produce highly concentrated CO₂, because the reformed fuel gas reacts with oxygen electrochemically without being mixed with air in the SOFC. We therefore propose to operate multi-staged SOFCs with high utilization of reformed fuel to obtain highly concentrated CO₂. In this study, we estimated the performance of multi-staged SOFCs considering H₂ diffusion and the combined cycle efficiency of a multi-staged SOFC/gas turbine/CO₂ recovery power plant. The power generation efficiency of our CO₂ recovery combined cycle is 68.5%, whereas the efficiency of a conventional SOFC/GT cycle with the CO₂ recovery amine process is 57.8%.     

Reduction of energy cost and CO2 emission for the furnace using energy recovered from waste tail-gas

In this research, the waste tail gas emitted from petrochemical processes, e.g. catalytic reforming unit, catalytic cracking unit and residue desulfurization unit, was recovered and reused as a replacement of natural gas (NG). On-site experimental results show that both the flame length and orange-yellowish brightness decrease with more proportion of waste gas fuel added to the natural gas, and that the adiabatic temperature of the mixed fuel is greater than 1800 °C. A complete replacement of natural gas by the recovered waste gas fuel will save 5.8 × 10⁶ m³ of natural gas consumption, and 3.5 × 10⁴ tons of CO₂ emission annually. In addition, the reduction of residual O₂ concentration in flue gases from 4% to 3% will save 1.1 × 10⁶ m³ of natural gas consumption, reduce 43.0% of NO_x emission, and 1.3 × 10³ tons of CO₂ emission annually. Thus, from the viewpoint of the overall economics and sustainable energy policy, recovering the waste tail gas energy as an independent fuel source to replace natural gas is of great importance for saving energy, reducing CO₂ emission reduction, and lowering environmental impact.     

Experimental determination and analysis of CO2, SO2 and NOx emission factors in Iran’s thermal power plants

Emission factors of CO₂, SO₂ and NO_x emitted from Iran’s thermal power plants are fully covered in this paper. To start with, emission factors of flue gases were calculated for fifty thermal power plants with the total installed capacity of 34,863 MW over the period 2007–2008 with regard to the power plants’ operation characteristics including generation capacity, fuel type and amount and the corresponding alterations, stack specifications, analysis of flue gases and physical details of combustion gases in terms of g kWh⁻¹. This factor was calculated as 620, 2.57 and 2.31 g kWh⁻¹ for CO₂, SO₂ and NO_x respectively. Regarding these results, total emissions of CO₂, SO₂ and NO_x were found to be 125.34, 0.552 and 0.465 Tg in turn. To achieve an accurate comparison, these values were compared with their alternatives in North American countries. According to this comparison, emission factor of flue gases emitted from Iran’s thermal power plants will experience an intensive decline if renewable, hydroelectric and nuclear types of energy are more used, power plants’ efficiency is increased and continuous emission monitoring systems and power plant pollution reduction systems are utilized.     

High performance composite hollow fiber membranes for CO2/H2 and CO2/N2 separation

The search for a clean energy source as well as the reduction of CO₂ emissions to the atmosphere are important strategies to resolve the current energy shortage and global warming issues. We have demonstrated, for the first time, a Pebax/poly(dimethylsiloxane)/polyacrylonitrile (Pebax/PDMS/PAN) composite hollow fiber membrane not only can be used for flue gas treatment but also for hydrogen purification. The composite membranes display attractive gas separation performance with a CO₂ permeance of 481.5 GPU, CO₂/H₂ and CO₂/N₂ selectivity of 8.1 and 42.0, respectively. Minimizing the solution intrusion using the PDMS gutter layer is the key to achieving the high gas permeance while the interaction between poly(ethylene oxide) (PEO) and CO₂ accounts for the high selectivity. Effects of coating solution concentration and coating time on gas separation performance have been investigated and the results have been optimized. To the best of our knowledge, this is the first polymeric composite hollow fiber membrane for hydrogen purification. The attractive gas separation performance of the newly developed membranes may indicate good potential for industrial applications.     

Reduction of CO2 capture plant energy requirement by selecting a suitable solvent and analyzing the operating parameters

Among various developed methods for CO₂ capturing from industrial flue gases, chemical absorption system is still considered as the most efficient technique, because of its lower energy requirement and also its applicability for low concentration of CO₂ in the inlet gas stream. Also, it can be used to retrofit the existed power plants, which are the major industrial CO₂ emission sources, without changing their design condition. Selection of a suitable solvent is the first parameter that should be considered in the design of capture plants that use absorption technology. The most important challenge for using chemical solvents is finding the optimum operating conditions to minimize the energy requirement. Study of technical parameters can be helpful to improve the overall capture plant efficiency. In this paper, CO₂ capture plant has been simulated for different solvents to compare their performance and energy requirement. To improve the plant overall efficiency, effect of the main operating factors such as amine flow rate, temperature, inlet gas temperature, and pressure has been studied in this paper. This analysis indicates the best chemical solvent for various cases of inlet flue gas. This parametric study reduces the overall energy requirement and helps design a cost‐effective plant. Copyright © 2012 John Wiley & Sons, Ltd.     

Comparative analysis of energy requirements of CO2 removal from metallurgical fuel gases

The paper presents preliminary results of the analysis concerning a CO₂ removal process, applied to metallurgical fuel gases: blast-furnace gas and Corex gas. The CO₂ removal is realised by the physical absorption process with the Selexol solvent as the absorbing liquid. The analysis is focused on the energy consumption in the case of such installations, when blast-furnace gas or Corex gas are supposed to be treated. The CO₂ removal from metallurgical gases can be attractive from both technological and environmental points of view. Decreased CO₂ content in the gases and increased lower heating value (LHV) results in better conditions for its utilisation e.g. in a gas turbine-based combined heat and power (CHP) plant or direct utilisation within the process, e.g. as an auxiliary fuel or reducing gas in a blast furnace. As the composition, flow rate and LHV of the raw blast furnace and Corex gases differ strongly, the physical absorption installation has different requirements and operation parameters in the two cases. The optimisation leads to minimal energy consumption with the assumed CO₂ removal efficiency. The results indicate which technology of pig-iron production has greater potential in the field of mitigation of greenhouse gas emissions, with respect to the technological possibilities of utilisation of the treated fuel gases.     

An innovative process for simultaneous removal of CO2 and SO2 from flue gas of a power plant by energy integration

With the fast development of the society, the amount of carbon dioxide has been increased enormously in the atmosphere all over the world, which has already endangered the survival of human being. More and more people or organizations are studying new technologies to reduce the cost of capturing CO₂. The recovery and sequestration of CO₂ from flue gas of the power plant is regarded as a feasible way to mitigate the greenhouse gas emissions. Therefore, the process of recovering carbon dioxide by chemical absorption with monoethanolamine (MEA) in industry was emphatically described in this paper. Based on energy integration, a coupled process was proposed which included MEA absorption of CO₂ and SO₂, and the heat recovery from the flue gas’s waste heat recovery unit and compressor inter-stage cooling unit. Compared the innovative process with an original process, 9% of thermal energy could be reduced in the new flowsheet. Meanwhile decarbonization and desulphurization could be carried on in the absorber simultaneously without the usual wet flue gas desulphurization (FGD) system. An exergy analysis model was established and validated by the literature data with a deviation less than 5.40%. The exergy results indicated that the exergy loss of the improved process was 15.48–20.75% less than that of the original one, which proved that the innovative process was reasonable and effective from the perspective of energy utilization.     

Comparison of two CO2 removal options in combined cycle power plants

In this paper, two concepts of CO₂ removal in CC are compared from the performance point of view. The first concept has been proposed in the framework of the European Joule II programme and is based on a semi-closed gas turbine cycle using CO₂ as the working fluid and a combustion with pure oxygen generated in an air separation unit. This is a zero emission system as the excess CO₂ produced in the combustion process is totally captured without the need of costly and energy consuming devices. The second concept calls for a partial recirculation of the flue gas at the exit of the heat recovery boiler of a CC. The remaining flow is sent to a CO₂ scrubber. Ninety percent of the CO₂ is removed in an absorber/stripper device. The two systems are compared to a state-of-the-art CC when the most advanced technology is used, namely a 9FA type gas turbine and a three pressure level and heat recovery boiler. Our results show also that the CO₂ semi-closed CC cycle performances are not very dependent on the configuration of the heat recovery boiler and that the recirculated gas CC performances are only slightly sensitive to the recirculation ratio. A high value of this latter mainly gives a significant reduction of the size and hence of the cost of the CO₂ scrubber. From the performance point of view, the results show that the system efficiency with partial recirculation and a CO₂ scrubber is always higher by 2–3% points than the CO₂-based CC efficiency in comparable conditions.     

Liquid CO2 droplet extraction from gases

Efficient mechanical separation of CO₂ from combustion effluent affects the utilization potential of high CO₂ producers such as coal. Novel mechanical separations of condensing CO₂ from gas flows need to be able to capture the small condensed droplets below the cyclone cut-off limit of 20 μm. We describe the thermodynamics, the energy costs and droplet formation of CO₂ phase separation from combustion effluent and natural gas. We report the first measurements of condensing CO₂ droplet sizes from gas. This shows that application of homogeneous condensation of CO₂ yields much smaller droplets in flue gas (N₂/CO₂) than from contaminated natural gas (CH₄/CO₂). These small droplets can only be efficiently removed at high throughputs using the novel centrifugal method we describe. Such mechanical separations are preferable to the current standard chemical methods because of the much lower environmental footprint.     

Hydrogen permeation through a Pd-based membrane and RWGS conversion in H2/CO2, H2/N2/CO2 and H2/H2O/CO2 mixtures

This study investigated the effect of gases such as CO₂, N₂, H₂O on hydrogen permeation through a Pd-based membrane −0.012 m² – in a bench-scale reactor. Different mixtures were chosen of H₂/CO₂, H₂/N₂/CO₂ and H₂/H₂O/CO₂ at temperatures of 593–723 K and a hydrogen partial pressure of 150 kPa. Operating conditions were determined to minimize H₂ loss due to the reverse water gas shift (RWGS) reaction. It was found that the feed flow rate had an important effect on hydrogen recovery (HR). Furthermore, an identification of the inhibition factors to permeability was determined. Additionally, under the selected conditions, the maximum hydrogen permeation was determined in pure H₂ and the H₂/CO₂ mixtures. The best operating conditions to separate hydrogen from the mixtures were identified.     

Elevated temperature pressure swing adsorption process for reactive separation of CO/CO2 in H2-rich gas

Purification of CO and CO₂ to the ppm level in H₂-rich gas without losing H₂ is one of the technical difficulties for fuel cell power systems. In this work, a two-column seven-step elevated temperature pressure swing system with high purification performance was proposed. The concept of reactive separation by adding water gas shift catalysts into the columns filled with elevated temperature CO₂ adsorbents was adopted. The H₂ recovery ratio and H₂ purity were greatly improved by the introduction of steam rinse and steam purge, which could be realized due to the increasing operating temperature (200–450 °C). An optimized operating region to both achieve high efficiency and low energy consumption was proposed. The optimized case with 0.09 purge-to-feed ratio and 0.15 rinse-to-feed ratio could achieve 99.6% H₂ recovery ratio and 99.9991% H₂ purity at a stable state for a feed gas containing 1% CO, 1% CO₂, 10% H₂O, and 88% H_2. No performance degradation was observed for at least 1000 cycles. The proposed (ET-PSA) system possessed self-purification ability while the columns were penetrated by CO₂. It is however suggested that periodical heat regeneration should be adopted to accelerate performance recovery during long-term operation.     

Review of CO2 recovery methods from the exhaust gas of biomass heating systems for safe enrichment in greenhouses

Novel approaches to practice CO₂ enrichment in greenhouses from the exhaust gas of a biomass heating system are reviewed. General CO₂ enrichment benefits for greenhouse plant production are described along with optimal management strategies to reduce fuel consumption while improving benefits. Alternative and renewable fuels for CO₂ enrichment, landfill biogas and biomass, are compared with traditional methods and fuels. Exhaust gas composition is outlined to address the challenges of CO₂ enrichment from biomass combustion and leads to a comparison between combustion and gasification to improve boiler efficiency. In terms of internal modifications to a biomass heating system, syngas combustion, following biomass gasification, presents good potential to achieve CO₂ enrichment. Regarding external modifications to clean the exhaust gas, CO₂ can be extracted from flue gases via membrane separation that has shown a lot of potential for large industries trying to reduce and isolate CO₂ emissions for sequestration. Other research has optimized wet scrubbing systems by extracting SO₂ and NO emissions from flue gases to form ammonium sulphate as a by-product valuable to fertilizer markets. The potential of these techniques are reviewed while future research directions are suggested.     

Hydrogen production from coal gasification for effective downstream CO2 capture

The coal gasification process is used in commercial production of synthetic gas as a means toward clean use of coal. The conversion of solid coal into a gaseous phase creates opportunities to produce more energy forms than electricity (which is the case in coal combustion systems) and to separate CO₂ in an effective manner for sequestration. The current work compares the energy and exergy efficiencies of an integrated coal-gasification combined-cycle power generation system with that of coal gasification-based hydrogen production system which uses water-gas shift and membrane reactors. Results suggest that the syngas-to-hydrogen (H₂) system offers 35% higher energy and 17% higher exergy efficiencies than the syngas-to-electricity (IGCC) system. The specific CO₂ emission from the hydrogen system was 5% lower than IGCC system. The Brayton cycle in the IGCC system draws much nitrogen after combustion along with CO₂. Thus CO₂ capture and compression become difficult due to the large volume of gases involved, unlike the hydrogen system which has 80% less nitrogen in its exhaust stream. The extra electrical power consumption for compressing the exhaust gases to store CO₂ is above 70% for the IGCC system but is only 4.5% for the H₂ system. Overall the syngas-to-hydrogen system appears advantageous to the IGCC system based on the current analysis.     

CO2 reforming of CH4 by binode thermal plasma

A binode thermal plasma is first applied to CO₂ reforming of CH₄ to investigate how to enlarge the process and lower energy consumption. Experimental study is conducted in two modes. One is to introduce feed gases (CH₄ and CO₂) only into discharge region between the first anode and the second anode as plasma-forming gas; the other is to introduce them not only into discharge region but also into the plasma jet from the exit of plasma generator. The experimental results show that, the former brings about higher conversion and selectivity but appreciably lower energy conversion efficiency due to its higher energy utilization, while the latter brings about higher energy conversion efficiency but somewhat lower conversion and selectivity due to its larger feeding of CH₄ and CO₂. Furthermore, during discharge in both modes, the oxidation on cathode and anode, or carbon deposition in plasma generator is not observed.     

Co-benefits of CO2 emission reduction in a developing country

In this paper, we examine the co-benefits of reducing CO₂ emissions in Thailand during 2005–2050 in terms of local pollutant emissions as well as the role of renewable-, biomass- and nuclear-energy. It also examines the implications of CO₂ emission reduction policy on energy security of the country. The analyses are based on a long term energy system model of Thailand using the MARKAL framework. The study shows that the power sector would account for the largest share (over 60%) in total CO₂ emission reduction followed by the industrial and transport sectors. Under the CO₂ emission reduction target of 30%, there would be a reduction in SO₂ emission by 43% from the base case level. With the CO₂ emission reduction target of 10–30%, the cumulative net energy imports in the country during 2005–2050 would be reduced in the range of over 16 thousand PJ to 26 thousand PJ from the base case emission level. Under the CO₂ emission reduction targets, the primary energy supply system would be diversified towards lower use of coal and higher use of natural gas, biomass and nuclear fuels.     

On the off-design of a natural gas-fired combined cycle with CO2 capture

During the last 15 years cycles with CO₂ capture have been in focus, due to the growing concern over our climate. Often, a natural gas fired combined cycle with a chemical absorption plant for CO₂ capture from the flue gases have been used as a reference in comparisons between cycles. Neither the integration of the steam production for regeneration of amines in the combined cycle nor the off-design behaviour of such a plant has been extensively studied before.     

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.     

MCFC-based CO2 capture system for small scale CHP plants

Carbon dioxide emissions into the atmosphere are considered among the main reasons of the greenhouse effect. The largest share of CO₂ is emitted by power plants using fossil fuels. Nowadays there are several technologies to capture CO₂ from power plants' exhaust gas but each of them consumes a significant part of the electric power generated by the plant. The Molten Carbonate Fuel Cell (MCFC) can be used as concentrator of CO₂, due to the chemical reactions that occurs in the cell stack: carbon dioxide entering into the cathode side is transported to the anode side via CO₃⁼ ions and is finally concentrated in the anodic exhaust. MCFC systems can be integrated in existing power plants (retro fitting) to separate CO₂ in the exhaust gas and, at the same time, produce additional energy. The aim of this study is to find a feasible system design for medium scale cogeneration plants which are not considered economically and technically interesting for existing technologies for carbon capture, but are increasing in numbers with respect to large size power plants. This trend, if confirmed, will increase number of medium cogeneration plants with consequent benefit for both MCFC market for this application and effect on global CO₂ emissions. System concept has been developed in a numerical model, using AspenTech engineering software. The model simulates a plant, which separates CO₂ from a cogeneration plant exhaust gases and produces electric power. Data showing the effect of CO₂ on cell voltage and cogenerator exhaust gas composition were taken from experimental activities in the fuel cell laboratory of the University of Perugia, FCLab, and from existing CHP plants. The innovative aspect of this model is the introduction of recirculation to optimize the performance of the MCFC. Cathode recirculation allows to decrease the carbon dioxide utilization factor of the cell keeping at the same time system CO₂ removal efficiency at high level. At anode side, recirculation is used to reduce the fuel consumption (due to the unreacted hydrogen) and to increase the CO₂ purity in the stored gas. The system design was completely introduced in the model and several analyses were performed. CO₂ removal efficiency of 63% was reached with correspondent total efficiency of about 35%. System outlet is also thermal power, due to the high temperature of cathode exhaust off gases, and it is possible to consider integration of this outlet with the cogeneration system. This system, compared to other post-combustion CO₂ removal technologies, does not consume energy, but produces additional electrical and thermal power with a global efficiency of about 70%.