Electric Swing Adsorption for CO2 removal from flue gases

One of the most important sources of CO₂ emissions are the fossil-fuel fired plants for production of electricity. Removal of CO₂ from flue gas streams for further sequestration has been proposed by the International Panel on Climate Change experts as one of the most reliable solutions to mitigate anthropogenic greenhouse emissions. When natural gas is employed as fuel, the molar fraction of CO₂ in the flue gas is lower than 5% causing serious problems for capture. The purpose of this work is to present experimental validation of an Electric Swing Adsorption (ESA) technology that may be employed for carbon capture for low molar fractions of CO₂ in the flue gas streams. To improve energy utilization, an activated carbon honeycomb monolith with low electrical resistivity was employed as selective adsorbent. A mathematical model for this honeycomb is proposed as well as different ESA cycles for CO₂ capture.     

Integration of CO2 capture unit using single- and blended-amines into supercritical coal-fired power plants: Implications for emission and energy management

This work provides the essential information and approaches for integration of carbon dioxide (CO₂) capture units into power plants, particularly the supercritical type, so that energy utilization and CO₂ emissions can be well managed in the subject power plants. An in-house model, developed at the University of Regina, Canada, was successfully used for simulating a 500 MW supercritical coal-fired power plant with a post-combustion CO₂ capture unit. The simulations enabled sensitivity and parametric study of the net efficiency of the power plant, the coal consumption rate, and the amounts of CO₂ captured and avoided. The parameters of interest include CO₂ capture efficiency, type of coal, flue gas delivery scheme, type of amine used in the capture unit, and steam pressure supplied to the capture unit for solvent regeneration. The results show that the advancement of MEA-based CO₂ capture units through uses of blended monoethanolamine–methyldiethanolamine (MEA–MDEA) and split flow configuration can potentially make the integration of power plant and CO₂ capture unit less energy intensive. Despite the increase in energy penalty, it may be worth capturing CO₂ at a higher efficiency to achieve greater CO₂ emissions avoided. The flue gas delivery scheme and the steam pressure drawn from the power plant to the CO₂ capture unit should be considered for process integration.     

The thief process for mercury removal from flue gas

The Thief Process is a cost-effective variation to activated carbon injection (ACI) for removal of mercury from flue gas. In this scheme, partially combusted coal from the furnace of a pulverized coal power generation plant is extracted by a lance and then re-injected into the ductwork downstream of the air preheater. Recent results on a 500-lb/h pilot-scale combustion facility show similar removals of mercury for both the Thief Process and ACI. The tests conducted to date at laboratory, bench, and pilot-scales demonstrate that the Thief sorbents exhibit capacities for mercury from flue gas streams that are comparable to those exhibited by commercially available activated carbons. A patent for the process was issued in February 2003. The Thief sorbents are cheaper than commercially-available activated carbons; exhibit excellent capacities for mercury; and the overall process holds great potential for reducing the cost of mercury removal from flue gas. The Thief Process was licensed to Mobotec USA, Inc. in May of 2005.     

Assessment of the different parameters affecting the CO2 purity from coal fired oxyfuel process

The oxyfuel process is one of the most promising options to capture CO₂ from coal fired power plants. The combustion takes place in an atmosphere of almost pure oxygen, delivered from an air separation unit (ASU), and recirculated flue gas. This provides a flue gas containing 80–90 vol% CO₂ on a dry basis. Impurities are caused by the purity of the oxygen from the ASU, the combustion process and air ingress. Via liquefaction a CO₂ stream with purity in the range from 85 to 99.5 vol% can be separated and stored geologically. Impurities like O₂, NO_X, SO_X, and CO may negatively influence the transport infrastructure or the geological storage site by causing geochemical reactions. Therefore the maximum acceptable concentrations of the impurities in the separated CO₂ stream must be defined regarding the requirements from transportation and storage. The main objective of the research project COORAL therefore is to define the required CO₂ purity for capture and storage.     

Corrosion and polarization behavior of carbon steel in MEA-based CO2 capture process

This work reveals levels of corrosion rate and polarization behavior of carbon steel immersed in aqueous solutions of monoethanolamine (MEA) used in the absorption-based carbon dioxide (CO₂) capture process for greenhouse gas reduction from industrial flue gas streams. Such information was obtained from electrochemical-based corrosion experiments under a wide range of the CO₂ capture process conditions. The corrosion of carbon steel was evaluated in respect to process parameters including partial pressure of oxygen (O₂), CO₂ loading in solution, solution velocity, solution temperature, MEA concentration and metal surface condition. Results show that the aqueous MEA solution containing CO₂ provides a favorable condition for the corrosion of carbon steel to proceed. Corrosion rate is increased by all tested process parameters. These parametric effects were explained by the electrochemical kinetic data obtained from polarization curves and by the thermodynamic data obtained from Pourbaix diagram.     

A novel process integration,optimization and design approach for large-scale implementation of oxy-fired coal power plants with CO2 capture

The widespread use of fossil fuels within the current energy infrastructure is considered as the largest source of anthropogenic emissions of carbon dioxide, which is largely blamed for global warming and climate change. At the current state of development, the risks and costs of non-fossil energy alternatives, such as nuclear, biomass, solar, and wind energy, are so high that they cannot replace the entire share of fossil fuels in the near future timeframe. Additionally, any rapid change towards non-fossil energy sources, even if possible, would result in large disruptions to the existing energy supply infrastructure. As an alternative, the existing and new fossil fuel-based plants can be modified or designed to be either “capture” or “capture-ready” plants in order to reduce their emission intensity through the capture and permanent storage of carbon dioxide in geological formations. This would give the coal-fired power generation units the option to sustain their operations for longer time, while meeting the stringent environmental regulations on air pollutants and carbon emissions in years to come.Currently, there are three main approaches to capturing CO₂ from the combustion of fossil fuels, namely, pre-combustion capture, post-combustion capture, and oxy-fuel combustion. Among these technology options, oxy-fuel combustion provides an elegant approach to CO₂ capture. In this approach, by replacing air with oxygen in the combustion process, a CO₂-rich flue gas stream is produced that can be readily compressed for pipeline transport and storage. In this paper, we propose a new approach that allows air to be partially used in the oxy-fired coal power plants. In this novel approach, the air can be used to carry the coal from the mills to the boiler (similar to the conventional air-fired coal power plants), while O₂ is added to the secondary recycle flow as well as directly to the combustion zone (if needed). From a practical point of view, this approach eliminates problems with the primary recycle and also lessens concerns about the air leakage into the system. At the same time, it allows the boiler and its back-end piping to operate under slight suction; this avoids the potential danger to the plant operators and equipment due to possible exposure to hot combustion gases, CO₂ and particulates. As well, by integrating oxy-fuel system components and optimizing the overall process over a wide range of operating conditions, an optimum or near-optimum design can be achieved that is both cost-effective and practical for large-scale implementation of oxy-fired coal power plants.     

The modelling of a hybrid combined cycle with pressurised fluidised bed combustion and CO2 capture

This study investigates the possibility of capturing CO₂ from flue gas under pressurised conditions, which could prove to be beneficial in comparison to working under atmospheric conditions. Simulations of two hybrid combined cycles with pressurised fluidised bed combustion and CO₂ capture are presented. CO₂ is captured from pressurised flue gas by means of chemical absorption after the boiler but before expansion. The results show a CO₂ capture penalty of approximately 8 percentage points (including 90% CO₂ capture rate and compression to 110 bar), which makes the efficiency for the best performing cycle 43.9%. It is 5.2 percentage points higher than the most probable alternative, i.e. using a natural gas fired combined cycle and a pulverised coal fired condensing plant separately with the same fuel split ratio. The largest part of the penalty is associated with the lower mass flow of flue gas after CO₂ capture, which leads to a decrease in work output in the expander and potential for feed water heating. The penalty caused by the regeneration of absorbent is quite low, since the high pressure permits the use of potassium carbonate, which requires less regeneration heat than for example the more commonly proposed monoethanolamine. Although the efficiencies of the cycles look promising it will be important to perform a cost estimate to be able to make a fair comparison with other systems. Such a cost estimate has not been done in this study. A significant drawback of these hybrid cycles in that respect is the complex nature of the systems that will have a negative effect on the economy.     

Oxy-fuel coal combustion—A review of the current state-of-the-art

Carbon dioxide emissions will continue being a major environmental concern due to the fact that coal will remain a major fossil-fuel energy resource for the next few decades. To meet future targets for the reduction of greenhouse gas (GHG) emissions, capture and storage of CO₂ is required. Carbon capture and storage technologies that are currently the focus of research centres and industry include: pre-combustion capture, post-combustion capture, and oxy-fuel combustion. This review deals with the oxy-fuel coal combustion process, primarily focusing on pulverised coal (PC) combustion, and its related research and development topics. In addition, research results related to oxy-fuel combustion in a circulating fluidised bed (CFB) will be briefly dealt with.During oxy-fuel combustion, a combination of oxygen, with a purity of more than 95 vol.%, and recycled flue gas (RFG) referred to as oxidant is used for combusting the fuel producing a gas consisting of mainly CO₂ and water vapour, which after purification and compression, is ready for storage. The high oxygen demand is supplied by a cryogenic air separation process, which is the only commercially available mature technology. The separation of oxygen from air as well as the purification and liquefaction of the CO₂-enriched flue gas consumes significant auxiliary power. Therefore, the overall net efficiency is expected to be decreased by 8–12% points, corresponding to a 21–35% increase in fuel consumption. Alternatively, ion transport membranes (ITMs) are proposed for oxygen separation, which might be more energy efficient. However, since ITMs are far away from becoming a mature technology, it is widely expected that cryogenic air separation will be the selected technology in the near future. Oxygen combustion is associated with higher temperatures compared with conventional air combustion. Both fuel properties as well as limitations of steam and metal temperatures of the various heat exchanger sections of the boiler require a moderation of the temperatures in the combustion zone and in the heat-transfer sections. This moderation in temperature is accomplished by means of recycled flue gas. The interdependencies between the fuel properties, the amount and temperature of the recycled flue gas, and the resulting oxygen concentration in the combustion atmosphere are reviewed.The different gas atmosphere resulting from oxy-fuel combustion gives rise to various questions related to firing, in particular, with respect to the combustion mechanism, pollutant reduction, the risk of corrosion, and the properties of the fly ash or its resulting deposits. In this review, detailed nitrogen and sulphur chemistry was investigated in a laboratory-scale facility under oxy-fuel combustion conditions. Oxidant staging succeeded in reducing NO formation with effectiveness comparable to that typically observed in conventional air combustion. With regard to sulphur, a considerable increase in the SO₂ concentration was measured, as expected. However, the H₂S concentration in the combustion atmosphere in the near-flame zone increased as well. Further results were obtained in a pilot-scale test facility, whereby acid dew points were measured and deposition probes were exposed to the combustion environment. Slagging, fouling and corrosion issues have so far been addressed via short-term exposure and require further investigation.Modelling of PC combustion processes by computational fluid dynamics (CFD) has become state-of-the-art for conventional air combustion. Nevertheless, the application of these models for oxy-fuel combustion conditions needs adaptation since the combustion chemistry and radiative heat transfer is altered due to the different combustion gas atmosphere.CFB technology can be considered mature for conventional air combustion. In addition to its inherent advantages like good environmental performance and fuel flexibility, it offers the possibility of additional heat exchanger arrangements in the solid recirculation system, i.e. the ability to control combustion temperatures despite relatively low flue gas recycle ratios even when combusting in the presence of high oxygen concentrations.     

Environmental impacts of absorption-based CO2 capture unit for post-combustion treatment of flue gas from coal-fired power plant

This study assesses potential environmental impacts of the absorption-based carbon dioxide (CO₂) capture unit that is integrated to coal-fired power plant for post-combustion treatment of flue gas. The assessment was performed by identifying potential pollutants and their sources as well as amounts of emissions from the CO₂ capture unit and also by reviewing toxicology, potential implications to human health and the environment, as well as the environmental laws and regulations associated with such pollutants. The assessment shows that, while offering a significant environmental benefit through a reduction of greenhouse gas emissions, the installation of CO₂ capture units for post-combustion treatment might induce unintentional and potential burdens to human health and the environment through four emission pathways, including treated gas, process wastes, fugitive emissions, and accidental releases. Such burdens nevertheless can be predetermined and properly mitigated through a well-established environmental management program and mitigation measures. Recommendations to minimize these impacts are provided in this paper.     

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO₂ capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO₂ from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO₂ capture and compression integration into an 800 MW_e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO₂ capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh_e/tonne CO₂. The study also addresses the effect of CO₂ capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW_e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO₂ capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.     

Study of Hg and SO3 behavior in flue gas of oxy-fuel combustion system

Oxy-fuel combustion systems have been under development to reduce CO₂ emissions from coal-fired power plants. In oxy-fuel combustion system, Hg in the flue gas causes corrosion in CO₂ purification and compression units. Also, SO₃ in the flue gas corrodes the equipment and ducts of oxy-fuel combustion system. Therefore, Hg and SO₃ need to be removed.Babcock-Hitachi conducted tests using a 1.5 MWth Combustion & Air Quality Control System (AQCS) test facility which consists of oxygen supply unit, furnace, Selective Catalytic Reduction (SCR) catalyst, Clean Energy Recuperator (CER), Dry Electrostatic Precipitator (DESP), flue gas recirculation system, Wet Flue Gas Desulfurization (WFGD), and CO₂ Compression and Purification Unit (CPU). In both cases of air and oxy-fuel combustion, the Hg removal across the DESP could be improved, and SO₃ concentration at the DESP outlet could be reduced to less than 1 ppm by installing a CER upstream of the DESP and reducing the gas temperature at the DESP inlet. Hg was not dissolved in the drain recovered from CO₂ compressor, and may be adsorbed at an inner part of CO₂ compressor. This indicated that Hg needs to be removed at a location upstream of the CO₂ compressor to prevent corrosion of the compressor.     

Reduction of CaSO4 oxygen carrier with coal in chemical-looping combustion: Effects of temperature and gasification intermediate

Chemical-looping combustion (CLC) has been suggested as an energy efficient method for the capture of carbon dioxide from combustion. Thermodynamics and kinetics of CaSO₄ reduction with coal via gasification intermediate in a CLC process were discussed in the paper, with respect to the CO₂ generating efficiency, the environmental factor and the surface morphology of oxygen carrier. Tests on the combined process of coal gasification and CaSO₄ reduction with coal syngas were conducted in a batch fluidized bed reactor at different reaction temperatures and with different gasification intermediates. The products were characterized by gas chromatograph, gas analyzers and scanning electron microscope. And the results showed that an increase in the reaction temperature aggravated the SO₂ emission. The CO₂ generating efficiency also increased with the temperature, but it decreased when the temperature exceeded 950 °C due to the sintering of oxygen carrier particles. The use of CO₂ as gasification intermediate in the fuel reactor had a positive effect on the sintering-resistant of oxygen carrier particles. However, increasing the steam/CO₂ ratio in gasification intermediate evidently enhanced CO₂ generating efficiency and reduced SO₂ environmental impact.     

CO2 capture by adsorption: Materials and process development

Vacuum swing adsorptive (VSA) capture of CO₂ from flue gas and related process streams is a promising technology for greenhouse gas mitigation. Although early reports suggested that VSA was problematic and expensive, through the application of more logical process configurations that are appropriately coupled to the composition of the feed and product gas streams, we can now refute this early assertion. Improved cycle designs coupled with tighter temperature control are also helping to optimise performance for CO₂ separation. Simultaneously, new adsorbent materials are being developed. These separate CO₂ by selective (acid-base) reaction with surface bound amine groups (chemisorption), rather than on the basis of non-bonding interactions (physisorption). This report describes some of these recent developments from our own laboratories and points to synergies that are anticipated as a result of combining these improvements in adsorbent properties and VSA process cycles.     

Drying of granulated wood ash by flue gas from saw dust and natural gas combustion

At the district heating plant of Kalmar, Sweden an on-line unit for production of granulated wood ash for nutrient recycling on forest soils is being applied. Currently, the granules are dried by hot air from an oil-fired burner. The objective of this work was to investigate how drying by flue gas affects the hardening of granules, or impacts their chemical composition and properties. Ninety-six granule samples were treated by flue gas from natural gas combustion in a laboratory pilot scale flue gas generator. CO₂, CO, O₂, C₃H₈ and NO concentrations were varied during the experiment. Additionally, some samples were treated by flue gas from combustion of sawdust at the heating plant in Kalmar. Drying by flue gases did not affect the chemical composition of granules, but minor effects were seen in their mineralogy. The carbonate content was slightly higher in granules treated with flue gas from natural gas combustion compared to the granules dried by hot air only, when measured by wet chemical methods. Results from XRD analysis imply that the calcite content is higher and the portlandite and arcanite content slightly less in granules treated with flue gas from sawdust combustion compared to the granules dried by hot air only. The results from this investigation showed no negative effects on ash granule composition or physical structure by the use of a flue as a drying medium.     

Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture,transport and storage

Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO₂) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer.Results show that the sequestration of 90% CO₂ from the flue gas results in avoiding 70% of CO₂ emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NO_x from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs.The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories.     

Chemical-looping with oxygen uncoupling for combustion of solid fuels

Chemical-looping with oxygen uncoupling (CLOU) is a novel method to burn solid fuels in gas-phase oxygen without the need for an energy intensive air separation unit. The carbon dioxide from the combustion is inherently separated from the rest of the flue gases. CLOU is based on chemical-looping combustion (CLC) and involves three steps in two reactors, one air reactor where a metal oxide captures oxygen from the combustion air (step 1), and a fuel reactor where the metal oxide releases oxygen in the gas-phase (step 2) and where this gas-phase oxygen reacts with a fuel (step 3). In other proposed schemes for using chemical-looping combustion of solid fuels there is a need for an intermediate gasification step of the char with steam or carbon dioxide to form reactive gaseous compounds which then react with the oxygen carrier particles. The gasification of char with H₂O and CO₂ is inherently slow, resulting in slow overall rates of reaction. This slow gasification is avoided in the proposed process, since there is no intermediate gasification step needed and the char reacts directly with gas-phase oxygen. The process demands an oxygen carrier which has the ability to react with the oxygen in the combustion air in the air reactor but which decomposes to a reduced metal oxide and gas-phase oxygen in the fuel reactor. Three metal oxide systems with suitable thermodynamic properties have been identified, and a thermal analysis has shown that Mn₂O₃/Mn₃O₄ and CuO/Cu₂O have suitable thermodynamic properties, although Co₃O₄/CoO may also be a possibility. However, the latter system has the disadvantage of an overall endothermic reaction in the fuel reactor. Results from batch laboratory fluidized bed tests with CuO and a gaseous and solid fuel are presented. The reaction rate of petroleum coke is approximately a factor 50 higher using CLOU in comparison to the reaction rate of the same fuel with an iron-based oxygen carrier in normal CLC.     

Flue gas desulphurization for hot recycle Oxyfuel combustion: Experiences from the 30 MWth Oxyfuel pilot plant in Schwarze Pumpe

Significant differences exist in the flue gas composition in hot recycle Oxyfuel conditions as e.g. the high CO₂ partial pressure (>90 vol%, dry), the very high SO₂ concentration and the high water content (approx. 30 vol%). Therefore certain design and operation criteria have to be observed for the flue gas desulphurization with forced oxidation under Oxyfuel combustion conditions. Several performance tests have been executed at the 30 MW_th Oxyfuel pilot plant in Schwarze Pumpe to evaluate the main performance parameters and to assess the influence of the major operation parameters. The results show that there are no fundamental problems for the operation of the flue gas desulphurization unit under Oxyfuel combustion conditions. High removal rates could be reached and no negative impact of the high CO₂ partial pressure was observed under the tested operating conditions. No major differences in the gypsum quality have been observed between air firing and Oxyfuel conditions.     

Ash and deposit formation from oxy-coal combustion in a 100 kW test furnace

Ash deposition is still an unresolved problem when retrofitting existing air-fired coal power plants to oxy-fuel combustion. Experimental data are quite necessary for mechanism validation and model development. This work was designed to obtain laboratory combustor data on ash and deposits from oxy-coal combustion, and to explore the effects of oxy-firing on their formation. Two bituminous coals (Utah coal and Illinois coal) and one sub-bituminous coal (PRB coal) were burned on a down-fired combustor under both oxy- and air-firing. Two oxy-fired cases, i.e., 27 vol% O₂/73 vol% CO₂ and 32 vol% O₂/68 vol% CO₂, were selected to match the radiation flux and the adiabatic flame temperature of air combustion, respectively. Once-through CO₂ was used to simulate fully cleaned recycled flue gas. The flue gas excess oxygen was fixed at 3 vol%. For each case, both size-segregated fly ash and bulk fly ash samples were obtained. Simultaneously, ash deposits were collected on an especially designed un-cooled deposition probe. Ash particle size distributions and chemical composition of all samples were characterized. Data showed that oxy-firing had insignificant impacts on the tri-modal ash particle size distributions and composition size distributions in the size range studied. Bulk ash compositions also showed no significant differences between oxy- and air-firing, except for slightly higher sulfur contents in some oxy-fired ashes. The oxy-fired deposits were thicker than those from air-firing, suggesting enhanced ash deposition rates in oxy-firing. Oxy-firing also had apparent impacts on the deposit composition, especially for those components (e.g., CaO, Fe₂O₃, SO₃, etc.) that could contribute significantly to ash deposition. Based on these results, aerodynamic changes in gas flow and changes in combustion temperature seemed more important than chemical changes of ash particles in determining deposit behavior during oxy-coal combustion.     

Biogas combustion in a chemical looping fluidized bed reactor

Chemical looping combustion (CLC) is a process in which oxygen required for combustion of a fuel is supplied by the metal oxide. Metal oxide plays the role of an oxygen carrier by providing oxygen for combustion when being reduced and is then re-oxidized by air in a separate reactor. Combustion is thus without any direct contact between air and fuel: as a consequence flue gas does not contain nitrogen of air which simplifies flue gas treatment prior to sequestration. In the present study, biogas combustion was analyzed in a chemical looping combustion fluidized bed reactor. NiAl_0.44O_1.67 and Cu_0.95Fe_1.05AlO₄ metal oxide particles were used as oxygen carriers. The experiments have shown the feasibility of biogas combustion in chemical looping combustion: CH₄ of the biogas was completely converted to CO₂ and H₂O with a small fraction of CO and H₂. The outlet flue gas distribution profile was not affected by ageing during the cycles of reduction and oxidation, indicating the chemical stability of the oxygen carriers. There was limited formation of carbon on the oxygen carriers during reduction.     

Life cycle modelling of fossil fuel power generation with post-combustion CO2 capture

Due to its compatibility with the current energy infrastructures and the potential to reduce CO₂ emissions significantly, CO₂ capture and geological storage is recognised as one of the main options in the portfolio of greenhouse gas mitigation technologies being developed worldwide. The CO₂ capture technologies offer a number of alternatives, which involve different energy consumption rates and subsequent environmental impacts. While the main objective of this technology is to minimise the atmospheric greenhouse gas emissions, it is also important to ensure that CO₂ capture and storage does not aggravate other environmental concerns. This requires a holistic and system-wide environmental assessment rather than focusing on the greenhouse gases only. Life Cycle Assessment meets this criteria as it not only tracks energy and non-energy-related greenhouse gas releases but also tracks various other environmental releases, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of other resources, such as water, minerals and land use. This paper presents the principles of the CO₂ capture and storage LCA model developed at Imperial College and uses the pulverised coal post-combustion capture example to demonstrate the methodology in detail. At first, the LCA models developed for the coal combustion system and the chemical absorption CO₂ capture system are presented together with examples of relevant model applications. Next, the two models are applied to a plant with post-combustion CO₂ capture, in order to compare the life cycle environmental performance of systems with and without CO₂ capture. The LCA results for the alternative post-combustion CO₂ capture methods (including MEA, K⁺/PZ, and KS-1) have shown that, compared to plants without capture, the alternative CO₂ capture methods can achieve approximately 80% reduction in global warming potential without a significant increase in other life cycle impact categories. The results have also shown that, of all the solvent options modelled, KS-1 performed the best in most impact categories.