Study on different zero CO2 emission IGCC systems with CO2 capture by integrating OTM

In this paper, different zero CO₂ emission integrated gasification combined cycle (IGCC) systems based on the oxy‐fuel combustion method by integrating with oxygen ion transfer membrane (OTM) with and without sweep gas are proposed in order to reduce the energy consumption of CO₂ capture. By utilizing the Aspen Plus software, the overall system models are established. The performances of the proposed systems are compared with the traditional IGCC system without CO₂ capture and the zero CO₂ emission IGCC system based on the oxy‐fuel combustion method using the cryogenic air separation unit. In addition, the effects of OTM key parameters on the proposed system performance, such as the feed side pressure, permeate side pressure, and operating temperature, are investigated and analyzed. The results show that the efficiency of the zero CO₂ emission IGCC system based on the oxy‐fuel combustion method integrated with OTM without sweep gas is 6.67% lower than that of the traditional IGCC system without CO₂ capture, but 1.88% higher than that of the zero CO₂ emission IGCC system using the cryogenic air separation unit, and 0.64% lower than that of the proposed system with sweep gas. The research achievements will provide valuable references for further study on CO₂ capture based on IGCC with lower energy penalty. Copyright © 2016 John Wiley & Sons, Ltd.     

Comparison of absorption and regeneration performance for post-combustion CO2 capture by mixed MEA solvents

In this work, the absorption performance, regeneration performance, and cyclic absorption capacity of three kinds of mixed monoethanolamine (MEA) solvents were studied compared to those of using MEA solvents alone in self-made apparatuses, including MEA-piperazine (PZ), MEA-potassium carbonate (K₂CO₃), and MEA-ammonia (NH₃). The mixed solvent of 10 wt% MEA/5 wt% PZ has a similar absorption performance and a higher regeneration temperature compared with the 20 wt% MEA solvent. And the mixed solvent of 10 wt% MEA/5 wt% K₂CO₃ has the lowest initial absorption rate, but it has a better cyclic absorption performance and a longer effective reaction time. The mixed solvent of 10 wt% MEA/5 wt% NH₃ has both a faster absorption rate and a lower regeneration temperature. These results prove that the mixed MEA solvent mixed with K₂CO₃ or NH₃ has good potential to replace the MEA solvent alone with a lower energy consumption.     

Energy minimization in monoethanolamine‐based CO2 capture using capacitive deionization

Post‐combustion CO₂ capture using monoethanolamine (MEA) is a mature technology; however, the high energy input requirements for solvent regeneration are still a challenge for MEA‐based CO₂ capture. In this paper, a novel approach is presented in which a conventional CO₂ absorption–desorption system is integrated with capacitive deionization (CDI) in such a way to minimize the heat duty requirement of the stripper. The CO₂‐rich solution drawn from the absorber column is first sent to CDI where ionic species are adsorbed at oppositely charged electrodes during the charging cycle, and an ion‐free solution is sent back to the absorber. The adsorbed ions released during the regeneration cycle are sent to the stripper column. The concentrated solution from the CDI process that was sent to the stripper required low heat duty to regenerate the solvent because of the high CO₂ loading of the solution. The feasibility of the suggested modelling technique is verified at various stripper inlet temperatures and lean CO₂ loadings. The results indicate that 10–45% of the total energy supplied to the stripper can be conserved at a lean CO₂ loading of 0.0000–0.0323 using the suggested process model. Moreover, the required size of the stripper column will be small due to the small volume of the concentrated ionic solutions from the CDI cell, eliminating the initial cost of the CO₂ capture system. Copyright © 2014 John Wiley & Sons, Ltd.     

Effect of supplementary firing options on cycle performance and CO2 emissions of an IGCC power generation system

Supplementary firing is adopted in combined‐cycle power plants to reheat low‐temperature gas turbine exhaust before entering into the heat recovery steam generator. In an effort to identify suitable supplementary firing options in an integrated gasification combined‐cycle (IGCC) power plant configuration, so as to use coal effectively, the performance is compared for three different supplementary firing options. The comparison identifies the better of the supplementary firing options based on higher efficiency and work output per unit mass of coal and lower CO₂ emissions. The three supplementary firing options with the corresponding fuel used for the supplementary firing are: (i) partial gasification with char, (ii) full gasification with coal and (iii) full gasification with syngas. The performance of the IGCC system with these three options is compared with an option of the IGCC system without supplementary firing. Each supplementary firing option also involves pre‐heating of the air entering the gas turbine combustion chamber in the gas cycle and reheating of the low‐pressure steam in the steam cycle. The effects on coal consumption and CO₂ emissions are analysed by varying the operating conditions such as pressure ratio, gas turbine inlet temperature, air pre‐heat and supplementary firing temperature. The results indicate that more work output is produced per unit mass of coal when there is no supplementary firing. Among the supplementary firing options, the full gasification with syngas option produces the highest work output per unit mass of coal, and the partial gasification with char option emits the lowest amount of CO₂ per unit mass of coal. Based on the analysis, the most advantageous option for low specific coal consumption and CO₂ emissions is the supplementary firing case having full gasification with syngas as the fuel. Copyright © 2008 John Wiley & Sons, Ltd.     

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.     

Implication of CO2 capture technologies options in electricity generation in Korea

This paper estimates the future mitigation potential and costs of CO₂ reduction technology options to the electricity generation facility in Korea. The monoethanolamine (MEA) absorption, membrane separation, pressure swing adsorption, and O₂/CO₂ input system were selected as the representative CO₂ reduction technology options. In order to analyze the mitigation potential and cost of these options, it uses the long-range energy alternative planning (LEAP) framework for setting future scenarios and assessing the technology options implication. The baseline case of energy planning scenario in Korea is determined in a business-as-usual (BAU) scenario. A BAU scenario is composed of the current account (2003) and future projections for 20 years. Alternative scenarios mainly deal with the installation planning options of CO₂ reduction technology (exogenous capacity, planning time, and existing electric plants). In each alternative scenario analysis, an alternation trend of existing electricity generation facilities was analyzed and the cost of installed CO₂ reduction plants and CO₂ reduction potential was assessed quantitatively.     

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.     

CO2 capture study in advanced integrated gasification combined cycle

This paper presents the results of technical and economic studies in order to evaluate, in the French context, the future production cost of electricity from IGCC coal power plants with CO₂ capture and the resulting cost per tonne of CO₂ avoided. The economic evaluation shows that the total cost of base load electricity produced in France by coal IGCC power plants with CO₂ capture could be increased by 39% for ‘classical’ IGCC and 28% for ‘advanced’ IGCC. The cost per tonne of avoided CO₂ is lower by 18% in ‘advanced’ IGCC relatively to ‘classical’ IGCC. The approach aimed to be as realistic as possible for the evaluation of the energy penalty due to the integration of CO₂ capture in IGCC power plants. Concerning the CO₂ capture, six physical and chemical absorption processes were modeled with the Aspen Plus™ software. After a selection based on energy performance three processes were selected and studied in detail: two physical processes based on methanol and Selexol™ solvents, and a chemical process using activated MDEA. For ‘advanced’ IGCC operating at high-pressure, only one physical process is assessed: methanol.     

A comprehensive techno‐economic analysis method for power generation systems with CO2 capture

A new comprehensive techno‐economic analysis method for power generation systems with CO₂ capture is proposed in this paper. The correlative relationship between the efficiency penalty, investment increment, and CO₂ avoidance cost is established. Through theoretical derivation, typical system analysis, and variation trends investigation, the mutual influence between technical and economic factors and their impacts on the CO₂ avoidance cost are studied. At the same time, the important role that system integration plays in CO₂ avoidance is investigated based on the analysis of a novel partial gasification CO₂ recovery system. The results reveal that for the power generation systems with CO₂ capture, the efficiency penalty not only affects the costs on fuel, but the incremental investment cost for CO₂ capture (U.S.$ kW⁻¹) as well. Consequently, it will have a decisive impact on the CO₂ avoidance cost. Therefore, the added attention should be paid to improve the technical performance in order to reduce the efficiency penalty in energy system with CO₂ capture and storage. Additionally, the system integration may not only decrease the efficiency penalty, but also simplify the system structure and keep the investment increment at a low level, and thereby it reduces the CO₂ avoidance cost significantly. For example, for the novel partial gasification CO₂ recovery system, owing to system integration, its efficiency can reach 42.2%, with 70% of CO₂ capture, and its investment cost is only 87$ kW⁻¹ higher than that of the reference IGCC system, thereby the CO₂ avoidance cost is only 6.23$ t⁻¹ CO₂. The obtained results provide a comprehensive technical–economical analysis method for energy systems with CO₂ capture useful for reducing the avoidance costs. Copyright © 2009 John Wiley & Sons, Ltd.     

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.     

Study on a zero CO2 emission SOFC hybrid power system integrated with OTM using CO2 as sweep gas

A new zero CO₂ emission solid oxide fuel cell (SOFC) hybrid power system integrated with the oxygen ion transport membrane using CO₂ as sweep gas is proposed in this paper. The pure oxygen is picked up from the cathode outlet gas by the oxygen ion transport membrane with CO₂ as sweep gas; the oxy‐fuel combustion mode in the afterburner of SOFC is employed. Because the combustion product gas only consists of CO₂ and steam, CO₂ is easily captured with lower energy consumption by the condensation of steam. With the aspen plus soft, this paper builds the simulation model of the overall SOFC hybrids system with CO₂ capture. The exergy loss distributions of the overall system are analyzed, and the effects of the key operation parameters on the overall system performance are also investigated. The research results show that the new system still has a high efficiency after CO₂ recovery. The efficiency of the new system is around 65.03%, only 1.25 percentage points lower than that of the traditional SOFC hybrid power system(66.28%)without CO₂ capture. The research achievements from this paper will provide the valuable reference for further study on zero CO₂ emission SOFC hybrid power system with higher efficiency. Copyright © 2013 John Wiley & Sons, Ltd.     

CO2 chemical conversion to useful products: An engineering insight to the latest advances toward sustainability

In the fossil‐fuel‐based economies, current remedies for the CO₂ reduction from large‐scale energy consumers (e.g. power stations and cement works) mainly rely on carbon capture and storage, having three proposed generic solutions: post‐combustion capture, pre‐combustion capture, and oxy fuel combustion. All the aforementioned approaches are based on various physical and chemical phenomena including absorption, adsorption, and cryogenic capture of CO₂. The purified carbon dioxide is sent for the physical storage options afterwards, using the earth as a gigantic reservoir with unknown long‐term environmental impacts as well as possible hazards associated with that. Consequently, the ultimate solution for the CO₂ sequestration is the chemical transformation of this stable molecule to useful products such as fuels (through, for example, Fischer–Tropsch chemistry) or polymers (through successive copolymerization and chain growth). This sustainably reduces carbon emissions, taking full advantage of CO₂‐derived chemical commodities, so‐called carbon capture and conversion. Nevertheless, the surface chemistry of CO₂ reduction is a challenge due to the presence of large energy barriers, requiring noticeable catalysis. This work aims to review the most recent advances in this concept selectively (CO₂ conversion to fuels and CO₂ copolymerization) with chemical engineering approach in terms of both materials and process design. Some of the most promising studies are expanded in detail, concluding with the necessity of subsidizing more research on CO₂ conversion technologies considering the growing global concerns on carbon management. Copyright © 2013 John Wiley & Sons, Ltd.     

Study on zero CO2 emission atmospheric pressure SOFC hybrid power system integrated with OTM

In order to further reduce the energy consumption of CO₂ capture from the traditional SOFC hybrid power system, based on the principle of energy cascade utilization and system integration, a zero CO₂ emission atmospheric pressure solid oxide fuel cell (SOFC) hybrid power system integrated with oxygen ion transport membrane (OTM) is proposed. The oxygen is produced by the OTM for the oxy‐fuel combustion afterburner of SOFC. With the Aspen‐plus software, the models of the overall SOFC hybrid power systems with or without CO₂ capture are developed. The thermal performance of new system is investigated and compared with other systems. The effects of the fuel utilization factor of SOFC and the pressure ratio between two sides of OTM membrane on the overall system performance are analyzed and optimized. The research results show that the efficiency of the zero CO₂ emission atmospheric pressure SOFC hybrid power system integrated with OTM is around 58.36%, only 2.48% lower than that of the system without CO₂ capture (60.84%) but 0.96% higher than that of the zero CO₂ emission atmospheric pressure SOFC hybrid system integrated with the cryogenic air separation unit. Copyright © 2014 John Wiley & Sons, Ltd.     

Performance analysis of a CO2 recycling system which utilizes solar energy

In this report, a CO₂ recycling system is proposed and designed for the purpose of CO₂ mitigation through utilization of solar energy (photovoltaic power generation). A performance analysis of the potential of this system for CO₂ reduction is performed as one of the life cycle analyses (LCA) of this system. The CO₂ emission from building the photovoltaic (PV) power generation facilities represents the largest fraction of CO₂ emission and accounts for 81 per cent of the CO₂ emission from building of plants. The CO₂ balance ratio of the system is approximately 1.4. It clearly reveals that this system would be an effective way to reduce CO₂ emissions and to utilize PV power generation as a natural energy source. Copyright © 2001 John Wiley & Sons, Ltd.     

Study on a novel process for CO2 compression and liquefaction integrated with the refrigeration process

In order to transport and store the captured CO₂ from coal‐fired power plants, it is necessary to compress and liquefy CO₂ first. However, the power consumption of conventional process is enormous. In this paper, a novel process for CO₂ compression and liquefaction based on the analysis of the power consumption of traditional method is proposed. The new process integrates the refrigeration process driven by the lower level heat from the coal‐fired power plant. This paper analyzes and compares the energy consumptions of conventional process and new process for CO₂ compression and liquefaction. The research result indicates that, when CO₂ needs to be compressed and liquefied and an abundant low quality heat is available, the new process has obvious superiority in lowering the energy consumption. The new process for CO₂ compression and liquation integrated with the exhaust heat powered refrigeration can greatly reduce the work consumption of CO₂ compression and liquefaction. The refrigeration temperature has great effects both on the coefficient of performance of refrigeration process and work consumption of compressors. The refrigeration temperature can be selected by optimization. Using refrigerator with double stages of evaporation can further reduce the amount of the extracted steam and lower the total energy consumption for CO₂ compression and liquation. Recovering the cool energy of CO₂ is beneficial to the reduction of the total work consumption. The achievements obtained from this paper will provide a useful reference for CO₂ compression and liquefaction with the lower energy consumption. Copyright © 2012 John Wiley & Sons, Ltd.     

Evaluation of power generation schemes based on hydrogen-fuelled combined cycle with carbon capture and storage (CCS)

IGCC is a power generation technology in which the solid feedstock is partially oxidized to produce syngas. In a modified IGCC design for carbon capture, there are several technological options which are evaluated in this paper. The first two options involve pre-combustion arrangements in which syngas is processed, either by shift conversion or chemical looping, to maximise the hydrogen level and to concentrate the carbon species as CO₂. After CO₂ capture by gas-liquid absorption or chemical looping, the hydrogen-rich gas is used for power generation. The third capture option is based on post-combustion arrangement using chemical absorption.Investigated coal-based IGCC case studies produce 400-500 MW net power with more than 90% carbon capture rate. Principal focus of the paper is concentrated on evaluation of key performance indicators for investigated carbon capture options, the influence of various gasifiers on carbon capture process, optimisation of energy efficiency by heat and power integration, quality specification of captured CO₂. The capture option with minimal energy penalty is based on chemical looping, followed by pre-combustion and post-combustion.     

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.     

Absorption and regeneration characteristics of alkanolamines after CO2 removal from flue gas

The investigations of CO₂ absorption rate, absorption capacity, and removal efficiency in monoethanolamine (MEA), diethanolamine (DEA), triethanolamine (TEA), and nonaqueous MEA solutions were carried out to improve the absorption characteristics of the absorbents. The experiments were performed using a synthetic flue gas consisting of 15% CO₂ with a flow rate of approximately 0.8 L/min. It was observed that 10 wt% MEA methanol solution had the fastest CO₂ absorption rate of 8.03 × 10^?5 mol/s. Furthermore, 10 wt% MEA methanol solution had the lowest regeneration temperature of 320 K.     

Efficiency of an Integrated Gasification Combined Cycle (IGCC) power plant including CO2 removal

This study is devoted to technical evaluation of a carbon dioxide removal in an existing Integrated Gasification Combined Cycle (IGCC) plant. This IGCC case is based on an oxygen blown entrained flow gasifier operating at 27 bar, the removal of acid gas (H₂S) is performed with MDEA unit, the efficiency of this IGCC is 43% based on the low heating value (LHV) of coal. A carbon dioxide separation unit conveniently integrated in a pre-combustion separation process is chosen, in order to take advantage of the high pressure of the gas. The methanol process for carbon dioxide removal is integrated downstream the existing desulfuration unit, and after a CO shift conversion unit. In this study, the integration of the CO₂ capture process to the IGCC is simulated as realistically as possible. The design parameters of both the gas turbine (the turbine inlet temperature, compressor pressure ratio, reduced flow rate) and the steam turbine (Stodola parameter) are taken into account. Maintenance of low _NOx${\mathrm{NO}}_x$ production in the combustion chamber is also considered. The production of _NOx${\mathrm{NO}}_x$ is supposed to be influenced by the low heating value of the gas which is maintained as low as for case of the synthesis gas without CO₂ capture. Thus the choice is made to feed the gas turbine of the combined cycle with a diluted synthesis gas, having similar low heating value than the one produced without the CO₂ capture. Plant performances for different conversion and capture rates are compared. A final optimized integration is given for 92 mol% CO conversion rate and 95 mol% CO₂ absorption rates, a comparison with former studies is proposed.     

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.