The air membrane-ATR integrated gas turbine power cycle: A method for producing electricity with low CO2 emissions

The air membrane-auto thermal reforming (AM-ATR) gas turbine cycle combines features of the R-ATR power cycle, introduced at the University of Florence, with ceramic, air separation membranes to achieve a novel combined cycle process with fuel decarbonisation and near-zero CO₂ emissions. Within this process, the natural gas fuel is converted to H₂ and CO through the auto thermal reforming process (ATR), i.e. combined partial oxidation and steam methane reforming, within the air separation membrane reactor. In a subsequent process unit, the H₂ content of the reformed fuel is enriched by the well known CO–CO₂ shift reaction. This fuel is then sent to an amine based carbon dioxide removal unit and, finally, to two combustors: the first one is located upstream of the membrane reformer (in order to achieve the required working temperature) and the second one is downstream of the membrane to reach the desired turbine inlet temperature (TIT).The main advantage of the proposed concept over other decarbonisation processes is the coupling of the membrane and the ATR reactor. This coupling greatly reduces the mass flow of syngas with respect to the air blown ATR contained in the previously proposed R-ATR, thus lowering the size of the syngas treatment section. Furthermore, as the oxygen production is integrated at high temperatures in the power cycle, the efficiency penalty of producing oxygen is much smaller than for the traditional cryogenic oxygen separation. The main advantages over other integrated GT-membrane concepts are the lower membrane operating temperature, lower levels of required air separation at high partial pressure driving forces (leading to lower membrane surface areas) and the possibility to achieve a higher TIT with top firing without increasing CO₂ emissions. When compared to power plants with tail end CO₂ separation, the CO₂ removal process treats a gas at pressure and with a significantly higher CO₂ concentration than that of gas turbine exhausts, which allows a compact carbon dioxide removal unit with a lower energy penalty.Starting from the same basis, various configurations were considered and optimised, all of which targeted a 65 MW power output combined cycle. The efficiency level achieved is around 45% (including recompression of the separated CO₂), which is roughly 10% less than the reference GT-CC plant (without CO₂ removal). A significant part of the efficiency penalty (4.3–5.6% points) is due to the fuel reforming, whereas further penalties come from the recompression units, loss of working fluid through the expander and the steam extracted for the ATR reactor and CO₂ separation. The specific CO₂ emissions of the MCM-ATR are about 120 kg CO₂/kWh, representing 30% of the emissions without CO₂ removal. This may be reduced to 10–15% with a better design of the shift reactors and the CO₂ removal unit. Compared to other concepts with air membrane technology, such as the AZEP concept, the efficiency loss is much greater when used for fuel de-carbonisation than for previous integration options.     

Exergy analysis of the recuperative auto thermal reforming (R-ATR) and recuperative reforming (R-REF) power cycles with CO2 removal

Two relatively innovative gas turbine (GT) based power cycles with high CO₂ removal potential have been proposed and discussed in terms of exergy analysis. Fuel decarbonisation is applied by the means of auto thermal reforming (R-ATR) and simple reforming (R-REF), in order to convert the primary natural gas into a highly H₂ and CO₂ concentrated fuel. Thus, CO₂ is captured with amine chemical absorption into a specific unit and, finally, the decarbonised fuel is sent to the GT combustion chamber. No bottoming steam cycle is included, which should promote the size flexibility of the powerplant. The heat content of GT exhausts is employed partially to sustain the endothermic reforming reactions and partially for cycle recuperation. Moreover, the possibility of steam blade cooling has been investigated.The efficiency is optimised at low pressure ratios (7–10) in the steam cooled R-ATR, whereas higher values have been found in air cooled version (16–17). Generally, the R-ATR solution shows higher efficiency levels, mainly due to the reduced combustion chamber and CO₂ capture exergy destruction and higher cycle recuperation degree.The exergy analysis showed a relatively limited influence of combustion chamber losses on the primary fuel exergy input (20–23%). The relative loss of CO₂ removal unit is limited as well (5–7%) when compared with values of semi-closed GT configurations. The exergy destruction of R-ATR and R-REF CO₂ removal sections is greatly reduced if steam blade cooling is adopted. Generally, all the proposed cycles showed satisfactory values of efficiency (43–46% under optimised conditions) taking into account that they do not involve combined power plants.     

Thermoeconomic evaluation of CO2 alkali absorption system applied to semi-closed gas turbine combined cycle

A new carbon dioxide separation system based on CO₂ absorption in aqueous solutions of alkaline salts (sodium and potassium carbonate) was studied with reference to semi-closed gas turbine/combined cycle (SCGT/CC), and compared to results obtained with existing technologies. Use of calcium hydroxide for the regeneration of the exhaust solution was studied in order to obtain a tail-end product, calcium carbonate in the form of precipitated calcium carbonate (PCC) with a wide spread and continuously growing market. The alkali CO₂ absorption process was compared with a conventional amine absorption process (DEA+MDEA), referring to the same SCGT/CC based on the same CO₂ removal efficiency. The comparison allows foregrounding of the possible goals of the CO₂ alkali absorption process with respect to previous amine cycle analyses. The modeling approach focuses on a thermodynamical and economical first comparison of the proposed cycle to previous studies carried out on CO₂ absorption (Energy Convers. Manage. 40 (1999) 1917; Absorption of CO₂ with amines in a semi closed GT cycle: plant performance and operating costs, ASME Paper 98-GT-395, American Society of Mechanical Engineers ASME Publishing, New York, 1998; Greenhouse Gas Control Technologies Conference, Interlaken, Switzerland, Pergamon, Oxford, 1999).     

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.     

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.     

Benchmarking of the pre/post-combustion chemical absorption for the CO2 capture

The aim of the article was to compare the pre- and post-combustion CO₂ capture process employing the chemical absorption technology. The integration of the chemical absorption process before or after the coal combustion has an impact on the power plant efficiency because, in both cases, the thermal energy consumption for solvent regeneration is provided by the steam extracted from the low pressure steam turbine. The solvent used in this study for the CO₂ capture was monoethanolamine (MEA) with a weight concentration of 30%. In the case of the pre-combustion integration, the coal gasification was analysed for different ratios air/fuel (A/F) in order to determine its influences on the syngas composition and consequently on the low heating value (LHV). The LHV maximum value (28 MJ/kg) was obtained for an A/F ratio of 0.5 kg_air/kg_fuel, for which the carbon dioxide concentration in the syngas was the highest (17.26%). But, considering the carbon dioxide capture, the useful energy (the difference between the thermal energy available with the syngas fuel and the thermal energy required for solvent regeneration) was minimal. The maximum value (61.59 MJ) for the useful energy was obtained for an A/F ratio of 4 kg_air/kg_fuel. Also, in both cases, the chemical absorption pre- and post-combustion process, the power plant efficiency decreases with the growth of the L/G ratio. In the case of the pre-combustion process, considering the CO₂ capture efficiency of 90%, the L/G ratio obtained was of 2.55 mol_solvent/mol_syngas and the heat required for the solvent regeneration was of 2.18 GJ/tCO₂. In the case of the post-combustion CO₂ capture, for the same value of the CO₂ capture efficiency, the L/G ratio obtained was of 1.13 mol_solvent/mol_{flue gas} and the heat required was of 2.80 GJ/tCO₂. However, the integration of the CO₂ capture process in the power plant leads to reducing the global efficiency to 30% in the pre-combustion case and to 38% to the post-combustion case.     

Analysis of oxy-fuel combustion power cycle utilizing a pressurized coal combustor

Growing concerns over greenhouse gas emissions have driven extensive research into new power generation cycles that enable carbon dioxide capture and sequestration. In this regard, oxy-fuel combustion is a promising new technology in which fuels are burned in an environment of oxygen and recycled combustion gases. In this paper, an oxy-fuel combustion power cycle that utilizes a pressurized coal combustor is analyzed. We show that this approach recovers more thermal energy from the flue gases because the elevated flue gas pressure raises the dew point and the available latent enthalpy in the flue gases. The high-pressure water-condensing flue gas thermal energy recovery system reduces steam bleeding which is typically used in conventional steam cycles and enables the cycle to achieve higher efficiency. The pressurized combustion process provides the purification and compression unit with a concentrated carbon dioxide stream. For the purpose of our analysis, a flue gas purification and compression process including de-SO_x, de-NO_x, and low temperature flash unit is examined. We compare a case in which the combustor operates at 1.1 bars with a base case in which the combustor operates at 10 bars. Results show nearly 3% point increase in the net efficiency for the latter case.     

Modeling and analysis of ceramic-carbonate dual-phase membrane reactor for carbon dioxide reforming with methane

A new high temperature tube-shell membrane reactor (MR) design for separation and utilization of CO₂ from the flue gas and for simultaneous production of syngas through carbon dioxide reforming of methane (CRM) is reported. The MR is based on a dual-phase CO₂ permeation membrane consisting of mixed-conducting oxide and molten carbonate phases. High temperature CO₂-containing flue gas and CH₄ are respectively fed into the shell and tube sides of the reactor packed with a reforming catalyst. Under performance conditions, CO₂ permeates selectively through the membrane from the shell side to the tube side and reacts with CH₄ to produce syngas. Additionally, the heat from the flue gas can transfer directly through the membrane to provide energy for the endothermic CRM reaction. An isothermal steady-state model was developed to simulate and analyze CRM in the MR in this work. The effect of the design and operational parameters, such as inlet CH₄ flow rate, shell side CO₂ partial pressure and the flue gas composition, i.e., containing O₂ or not, as well as the membrane thickness on the reactor performance with respect to the CH₄ conversion and the CO₂ permeation flux were investigated and discussed. The results show that the MR has a high efficiency in separating and utilizing CO₂ from the flue gas. For a CH₄ space velocity of 3265.31 h⁻¹, with a membrane thickness of 0.075 mm and the shell side CO₂ partial pressure of 1 atm, a CH₄ conversion of 48.06% and an average CO₂ permeation flux of 1.52 mL(STP) cm⁻² min⁻¹ through the membrane tube at 800 °C are obtained. Further improvement of the MR performance can be achieved by involving O₂ in the permeation process.     

Recovery of CO2 with MEA and K2CO3 absorption in the IGCC system

Recovery of CO₂ with monoethanolamine (MEA) and hot potassium carbonate (K₂CO₃) absorption processes in an integrated gasification combined cycle (IGCC) power plant was studied for the purpose of development of greenhouse gas control technology. Based on energy and exergy analysis of the two systems, improvement options were provided to further reduce energy penalty for the CO₂ separation in the IGCC system. In the improvement options, the energy consumption for CO₂ separation is reduced by about 32%. As a result, the thermal efficiency of IGCC system is increased by 2.15 percentage‐point for the IGCC system with MEA absorption, and by 1.56 percentage‐point for the IGCC system with K₂CO₃ absorption. Copyright © 2004 John Wiley & Sons, Ltd.     

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.     

Poisoning-tolerant metal hydride materials and their application for hydrogen separation from CO2/CO containing gas mixtures

Metal hydride materials offer attractive solutions in addressing problems associated with hydrogen separation and purification from waste flue gases. However, a challenging problem is the deterioration of hydrogen charging performances resulting from the surface chemical action of electrophilic gases. In this work, the feasibility study of poisoning tolerance of surface modified AB₅-type hydride forming materials and their application for hydrogen separation from process gases containing carbon dioxide and monoxide was carried out. Target composition of La(Ni,Co,Mn,Al)₅ substrate was chosen to provide maximum reversible hydrogen capacity at the process conditions. The selected substrate alloy has been shown to be effectively surface-modified by fluorination followed by electroless deposition of palladium. The surface-modified material exhibited good coating quality, high cycle stability and minimal deterioration of kinetics of selective hydrogen absorption at room temperature, from gas mixtures containing 10% CO₂ and up to 100 ppm CO. The experimental prototype of a hydrogen separation unit, based on the surface-modified metal hydride material, was tested and exhibited stable hydrogen separation and purification performances when exposed to feedstocks containing concentrations of CO₂ and CO of up to 30% and 100 ppm, respectively.     

A novel approach for treatment of CO2 from fossil fired power plants,Part A: The integrated systems ITRPP

The environmental issues, due to the global warming caused by the rising concentration of greenhouse gases in the atmosphere, require new strategies aimed to increase power plants efficiencies and to reduce CO₂ emissions.This two-paper work focuses on a different approach for capture and reduction of CO₂ from flue gases of fossil fired power plant, with respect to conventional post-combustion technologies. 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 and energy industries (methanol, DME, etc.). In fact, 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 this Part A, integrated systems for co-generation of electrical power and synthesis gas useful for methanol production have been defined and their performance has been investigated considering different flue gases compositions. In Part B, in order to verify the environmental advantages and energy suitability of these systems, their comparison with conventional technology for methanol production is carried out.The integrated systems (ITRPP, Integrated Tri-Reforming Power Plant) consist of a power island, based on a thermal power plant, and a methane tri-reforming island in which the power plants' exhausts react with methane to produce a synthesis gas used for methanol synthesis. As power island, a steam turbine power plant fuelled with coal and a gas turbine combined cycle fuelled with natural gas have been considered.The energy and environmental analysis of ITRPP systems (ITRPP-SC and ITRPP-CC) has been carried out by using thermochemical and thermodynamic models which have allowed to calculate the syngas composition, to define the energy and mass balances and to estimate the CO₂ emissions for each ITRPP configuration.The repowering of the base power plants (steam turbine power plant and gas turbine combine cycle) is very high because of the large amount of steam produced in the tri-reforming island (in the ITRPP-SC is about of 64%, while in the ITRPP-CC is about of 105%).The reduction in the CO₂ emissions has been estimated in 83% (15.4 vs. 93.4 kg/GJ_Fuelinput) and 84% (8.9 vs. 56.2 kg/GJ_Fuelinput) for the ITRPP-SC and ITRPP-CC respectively.     

Study on a novel solid oxide fuel cell/gas turbine hybrid cycle system with CO2 capture

A novel solid oxide fuel cell (SOFC)/gas turbine (GT) hybrid cycle system with CO₂ capture is proposed based on a typical topping cycle SOFC/GT hybrid system. The H₂ gas is separated from the outlet mixture gas of SOFC1 anode by employing the advanced ceramic proton membrane technology, and then, it is injected into SOFC2 to continue a new electrochemical reaction. The outlet gas of SOFC1 cathode and the exhaust gas from SOFC2 burn in the afterburner 1. The combustion gas production of the afterburner1 expands in the turbine 1. The outlet gas of SOFC1 anode employs the oxy‐fuel combustion mode in the afterburner 2 after H₂ gas is separated. Then, the combustion gas production expands in the turbine 2. To ensure that the flue gas temperature does not exceed the maximum allowed turbine inlet temperature, steam is injected into the afterburner 2. The outlet gas of the afterburner 2 contains all the CO₂ gas of the system. When the steam is removed by condensation, the CO₂ gas can be captured. The steam generated by the waste heat boiler is used to drive a refrigerator and make CO₂ gas liquefied at a lower temperature. The performance of the novel quasi‐zero CO₂ emission SOFC/GT hybrid cycle system is analyzed with a case study. The effects of key parameters, such as CO₂ liquefaction temperature, hydrogen separation rate, and the unit oxygen production energy consumption on the new system performance, are investigated. Compared with the other quasi‐zero CO₂ emission power systems, the new system has the highest efficiency of around 64.13%. The research achievements will provide the valuable reference for further study of quasi‐zero CO₂ emission power system with high efficiency. Copyright © 2011 John Wiley & Sons, Ltd.     

A CO2 cryogenic capture system for flue gas of an LNG-fired power plant

In the present paper, a CO₂ cryogenic capture for flue gas of an LNG-fired power generation system is proposed, in which LNG cold energy can be fully utilized during the gasification process. First of all, the flue gas is compressed to facilitate the CO₂ solid formation and separation. Sequentially, the CO₂-removed flue gas expands to supply most of the cold energy needed for the cryogenic process. In comparison with traditional CO₂-capture systems in LNG-fired power generation cycle, the new system does not require gasifying excessive amount of LNG. Based on the HYSYS simulation, the CO₂ capture pressure and temperature are investigated as the key parameters to find the appropriate working conditions of the CO₂-capture system. The results show that the system can achieve a 90% CO₂ recovery rate or higher if the flue gas temperature can be lowered to less than ?140 °C.     

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.     

New process concepts for CO2 post-combustion capture process integrated with co-production of hydrogen

This work describes a study in advanced post-combustion based on CO₂-capture technologies to be integrated within the Hypogyny concept (electricity generation with co-hydrogen production). Two different Hypogen concepts based on integrating IGCC (Integrated Gasification Combined Cycle) and post-combusting CO₂ capture are proposed and investigated: the first concept, hydrogen production based on syngas shifting with high-pressure CO₂ capture, while the second concept, hydrogen is produced based on membrane separation from syngas.In the first concept, combining a high-pressure and an ambient-pressure CO₂ absorber in one flow sheet and one regeneration column is found to be feasible. However, the advantage of the high CO₂ partial pressure in the high-pressure absorber is more obvious if an advanced solvent like 2-amino-2-methyl-1-propanol (AMP) is used instead of monoethanolamine (MEA) solvent kind.The second concept of using polymeric membrane for hydrogen production is considered feasible and comparing to the first concept, cost competitive with around 10% higher overall capital cost. However, the membrane unit does not achieve high hydrogen purity because the investigated concept is limited to a maximum purity of around 95%. Therefore, hydrogen selective membrane technically requires an extra hydrogen purification step e.g. further membrane separations or a pressure swing adsorption (PSA).In addition to these two concepts, the influence of flue gas circulation, gasifier selection and an advanced solvent based on the sterically hindered amine AMP was investigated. Flue gas circulation (higher CO₂-concentrations) has no influence on the regeneration energy requirements when a high binding-energy solvent like MEA is used. The main benefit is that flue gas circulation results with more compact absorption equipment. For AMP type of solvents flue gas circulation results in a substantial reduction in regeneration energy and the overall cost of CO₂ avoided. 37% reduction in the avoided cost with a flue gas recycle ratio of 45% is achieved using AMP as a solvent comparing to 10% using MEA solvent.These Hypogen strategies appear to be feasible and the overall cost of these concepts is comparable with the conventional post-combustion capture process. However, there is a significant potential for further improvement by applying more developed solvents, processes, and membranes.     

Impact of choice of CO2 separation technology on thermo‐economic performance of Bio‐SNG production processes

Three different CO₂ separation technologies for production of synthetic natural gas (SNG) from biomass gasification – amine‐based absorption, membrane‐based separation and pressure swing adsorption – are investigated for their thermo‐economic performance against the background of different possible future energy market scenarios. The studied scale of the SNG plant is a thermal input of 100 MW_th,LHV to the gasifier at a moisture content of 20 wt‐% with a preceding drying step reducing the biomass' natural moisture content of 50 wt‐%. Preparation of the CO₂‐rich stream for carbon capture and storage is investigated for the amine‐based absorption and the membrane‐based separation technology alternatives. The resulting cold gas efficiency η_cg for the investigated process alternatives ranges between 0.65 and 0.695. The overall system efficiency η_sys ranges from 0.744 to 0.793, depending on both the separation technology and the background energy system. Amine‐based absorption gives the highest cold gas efficiency whereas the potential for cogeneration of electricity from the process' excess heat is higher for membrane‐based separation and pressure swing adsorption. The estimated specific production costs for SNG c_SNG for a process input of 90.3 MW_th,LHV at 50 wt‐% moisture vary between 103–127 €₂₀₁₀/MWh_SNG. The corresponding production subsidy level c_subsidy needed to achieve end‐user purchase price‐parity with fossil natural gas is in the range of 56–78 €₂₀₁₀/MWh_SNG depending on both the energy market scenario and the CO₂ separation technology. Sensitivity analysis on the influence of changes in the total capital cost for the SNG plant on the production cost indicates a decrease of about 12% assuming a 30% reduction in total capital investment. Capture and storage of biogenic CO₂ – if included in the emission trading system – only becomes an option at higher CO₂ charges. This is due to increased investment costs but, in particular, due to the rather high costs for CO₂ transport and storage that have been assumed in this study. Copyright © 2013 John Wiley & Sons, Ltd.     

Design of CO2 absorption plant for recovery of CO2 from flue gases of gas turbine

The ongoing human-induced emission of carbon dioxide (CO₂) threatens to change the earth's climate. A major factor in global warming is CO₂ emission from thermal power plants, which burn fossil fuels. One possible way of decreasing CO₂ emissions is to apply CO₂ removal, which involves recovering of CO₂ from energy conversion processes. This study is focused on recovery of CO₂ from gas turbine exhaust of Sarkhun gas refinery power station. The purpose of this study is to recover the CO₂ with minimum energy requirement. Many of CO₂ recovery processes from flue gases have been studied. Among all CO₂ recovery processes which were studied, absorption process was selected as the optimum one, due to low CO₂ concentration in flue gas. The design parameters considered in this regard, are: selection of suitable solvent, solvent concentration, solvent circulation rate, reboiler and condenser duty and number of stages in absorber and stripper columns. In the design of this unit, amine solvent such as, diethanolamine (DEA), diglycolamine (DGA), methyldiethanolamine (MDEA), and monoethanolamine (MEA) were considered and the effect of main parameters on the absorption and stripping columns is presented. Some results with simultaneous changing of the design variables have been obtained. The results show that DGA is the best solvent with minimum energy requirement for recovery of CO₂ from flue gases at atmospheric pressure.     

A chemical intercooling gas turbine cycle with chemical-looping combustion

A novel methanol-based power system with Chemical-Looping Combustion (CLC) is proposed in this paper. CLC system is a promising approach to greatly decrease the energy penalty for CO₂ removal, where iron oxides circulate between two reactors and an inherent CO₂ separation occurs. The combustion process of CLC systems mainly include two steps: a reduction reaction of iron oxides, where the fuel is not mixed with air and the thermal energy for the endothermic reaction is supplied by the intercooling heat of the compressor of the gas turbine, and an oxidation reaction of iron oxides, where the compressed air is heated by the iron oxides. On the basis of the system's integration of cascade utilization of chemical energy of methanol and thermal energy, the thermal efficiency of this novel cycle is expected to be 56.8% with 90% of CO₂ recovery, 10.2 percentage points higher than a combined cycle (CC) with the same CO₂ capture. The promising results obtained here indicate that this novel thermal cycle is a promising approach to accomplish the efficient utilization of chemical energy of methanol without a decrease in thermal efficiency for CO₂ removal.     

A review of recent developments in carbon capture utilizing oxy‐fuel combustion in conventional and ion transport membrane systems

Fossil fuels provide a significant fraction of the global energy resources, and this is likely to remain so for several decades. Carbon dioxide (CO₂) emissions have been correlated with climate change, and carbon capture is essential to enable the continuing use of fossil fuels while reducing the emissions of CO₂ into the atmosphere thereby mitigating global climate changes. Among the proposed methods of CO₂ capture, oxyfuel combustion technology provides a promising option, which is applicable to power generation systems. This technology is based on combustion with pure oxygen (O₂) instead of air, resulting in flue gas that consists mainly of CO₂ and water (H₂O), that latter can be separated easily via condensation, while removing other contaminants leaving pure CO₂ for storage. However, fuel combustion in pure O₂ results in intolerably high combustion temperatures. In order to provide the dilution effect of the absent nitrogen (N₂) and to moderate the furnace/combustor temperatures, part of the flue gas is recycled back into the combustion chamber. An efficient source of O₂ is required to make oxy‐combustion a competitive CO₂ capture technology. Conventional O₂ production utilizing the cryogenic distillation process is energetically expensive. Ceramic membranes made from mixed ion‐electronic conducting oxides have received increasing attention because of their potential to mitigate the cost of O₂ production, thus helping to promote these clean energy technologies. Some effort has also been expended in using these membranes to improve the performance of the O₂ separation processes by combining air separation and high‐temperature oxidation into a single chamber. This paper provides a review of the performance of combustors utilizing oxy‐fuel combustion process, materials utilized in ion‐transport membranes and the integration of such reactors in power cycles. The review is focused on carbon capture potential, developments of oxyfuel applications and O₂ separation and combustion in membrane reactors. The recent developments in oxyfuel power cycles are discussed focusing on the main concepts of manipulating exergy flows within each cycle and the reported thermal efficiencies. Copyright © 2010 John Wiley & Sons, Ltd.