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A precipitating potassium carbonate (K 2 CO 3 ) based solvent absorption process has been developed for capturing carbon dioxide (CO 2 ) from industrial sources. Demonstration of this process has been completed using real flue gas in a pilot plant located at Hazelwood power station in Victoria, Australia. The pilot plant was designed to capture up to 1 tonne per day of CO 2 and was operated over a number of campaigns to test the absorption performance of a liquid solvent (30 wt% K 2 CO 3 ), a precipitating solvent (45 wt% K 2 CO 3 ) and a promoted precipitating solvent (promoter with 45 wt% K 2 CO 3 ). The main aim of this study was to collect operational data from the industry based pilot plant absorber in order to validate thermodynamic experiments and further improve simulation models developed from lab-scale precipitating column trials using synthetic feed gas. The performance of the industry based absorber including CO 2 capture rate, pressure drop, solvent loadings and temperature profile, has been measured over a range of operating conditions. The CO 2 capture rate improved when operating with a lower gas flow rate, higher solvent temperature and when a rate promoter was added to the solvent. The highly concentrated solvent trials created some difficulties with absorber flooding and intermittent operation due to blockages at start-up but minimal issues were encountered once the system was stabilized. Process simulations have been developed to successfully predict the pilot plant performance over a range of operating conditions. Completion of these pilot plant trials has provided confidence in plant operation and will enable an improved full-scale design and costing of this slurry based solvent process to be completed for commercial scale. [ABSTRACT FROM AUTHOR]

There has been a rapid increase in the use of natural gas for power generation based on gas turbine technology which elevates the importance of carbon dioxide (CO2) capture technology to reduce CO2 emissions from gas turbine based power stations. The low content of CO2 in the gas turbine exhaust results in low rates of CO2 absorption and larger absorption equipment when compared to studies done on coal fired power stations. Furthermore the high oxygen (O2) content in the exhaust gas adversely affects the solvent stability, particularly for the traditional amine based solvents. This paper describes how exhaust gas recirculation (EGR) along with CO2CRC's low cost "UNO MK 3" precipitating potassium carbonate (K2CO3) process can overcome the challenges of CO2 capture from gas turbine power stations. To further bring down the energy requirements of the capture process, heat integration of the UNO MK 3 process with power generation process is carried out. An economic analysis of the various retrofit options is performed. The current study shows that in the case of retrofitting the UNO MK 3 process to a natural gas combined cycle (NGCC), the use of EGR can reduce the energy penalty of CO2 capture by 15%, whilst a reduction of up to 25% can be achieved with the heat integration strategies described. Significantly the study shows that converting an existing open cycle gas turbine (OCGT) to a combined cycle with steam generation along with retrofitting CO2 capture presents a different steam cycle design for the maximum power output from the combined cycle with CO2 capture. Such a conversion actually produces more power and offers an alternative low emission retrofit pathway for gas fired power. Cost analysis shows that inclusion of the UNO MK 3 CO2 capture process with EGR to an existing NGCC is expected to increase the cost of electricity (COE) by 20%. However, retrofit/repowering of an underutilised or peaking OCGT station with the inclusion of CO2 capture can reduce the COE as well as produce low emission power. This is achieved by increasing the load factor and incorporating a purpose built steam generation cycle. [ABSTRACT FROM AUTHOR]

Potassium carbonate (K2CO3) solvents offer a lower cost and environmentally benign alternative to the traditional amine-based solvents for post-combustion capture of carbon dioxide (CO2) from power station flue gases. The CO2CRC is developing a precipitating K2CO3 process, termed UNO MK 3, which has the potential for significant cost reductions. The costs have been calculated based on capturing 90% of the CO2 emissions from a new build black coal (Illinois No. 6) power station with a net output of 550 MW. With the UNO MK 3 process for CO2 capture, the cost of electricity is predicted to be as low as $73/MWh and the cost of capture as low as $21/tonne of CO2 avoided. The cost of electricity with the UNO MK 3 process represents as low as a 24% increase in the cost of electricity, which meets the target set by the US Department of Energy for capture technologies of adding less than 35% to the cost of electricity. [ABSTRACT FROM AUTHOR]

Abstract: The CO2CRC's UNO MK 3 process is a precipitating potassium carbonate process engineered to capture 90% of carbon dioxide emissions from large scale emission sources such as power stations and other industrial sources. The UNO MK 3 is expected to have benefits in the following areas; [•] Low energy of regeneration (2 - 2.5 GJ/tonne of CO2). [•] Low overall cost, which is expected to be greater than $20/tonne of CO2 avoided less than competing amines. [•] Low volatility and environmental impact with low emissions, low toxicity and smaller carbon footprint. [•] Multi-impurity capture of CO2, SOx and NOx with linkage to the global potassium fertilizer chain. These key benefits of the UNO MK 3 process are being confirmed by the CO2CRC's work program, which combines fundamental research, process demonstrations and larger scale engineering applicable to capture from 500 MW power stations. Techno-economic results from this large scale engineering work program are presented and the systematic technology improvements discussed. [Copyright &y& Elsevier]

Abstract: An Aspen Plus® simulation of an existing power station with a potassium carbonate based carbon capture (CCS) plant including CO2 compression is combined with an Excel based genetic algorithm to optimise the net power output of the power station and amount of CO2 captured for a range of solvent flowrates, lean loading and stripper pressures. The net power output was compared for a CCS plant that is added to the power station without any heat integration to a system where heat integration is maximised by the use of pinch analysis and linear optimisation to calculate the amount of steam required to be extracted from the turbine to meet the additional heating requirements of the CCS plant. The multi-objective optimisation of the process identified that lean solvent loading and stripper pressure will have a large impact on the net power output and amount of CO2 captured. The curves developed in the multi-objective optimisation can provide not only the ability to determine the CO2 capture rate to maximise the profit at a given time due to fluctuating electricity prices, but will also provide the optimum solvent flowrate and lean loading to achieve that maximum capture rate for a given net power. The paper shows that the design of the optimum carbon capture plant will depend not only on the specific capture process but also on the conditions of the power station and the importance in optimising the whole process at the same time. The minimum energy penalty for the potassium carbonate system combined with the reference power station modeled in this paper is 1.02 MJe/kgCO2 with a reboiler regeneration energy of 5.3 MJth/kgCO2. In this example optimisation and heat integration was able to reduce the energy penalty by 0.4 MJe/kgCO2. [Copyright &y& Elsevier]

Abstract: This paper discusses the energy penalty of solvent based post combustion capture for three different power stations and includes a comparison of shockwave CO2 compression versus conventional turbo machinery on the energy penalty associated with carbon capture and storage. This study uses pinch analysis to determine targets for the energy penalty of three different power stations that include a brown coal power plant with no reheat stage, a more efficient brown coal power station and a black coal power station. Heat integration can be used to reduce the energy penalty of all power stations combined with CCS. It is also found that when heat integration is considered, the heat that can be recovered in shockwave compressor inter/after-coolers reduces the amount of steam that needs to be extracted from the steam turbine. Hence, the net power output from the power station will be higher when shockwave compressors are used for CO2 compression compared to conventional turbo-machinery. [Copyright &y& Elsevier]

Abstract: Integration of CO2 capture and storage (CCS) into coal-fired power stations is seen as a way of significantly reducing the carbon emissions from stationary sources. A large proportion of the estimated cost of CCS is because of the additional energy expended to capture the CO2 and compress it for transport and storage, reducing the energy efficiency of the power plant. This study uses pinch analysis and heat integration to reduce the overall energy penalty and, therefore, the cost of implementing CCS for power plants where the additional heat and power for the CCS plant will be provided by the existing power plant. A combined pinch analysis and linear programming optimisation are applied to determine targets for the energy penalty of existing power plants. Two existing pulverised brown coal power plants with new CCS plants using solvent absorption are used as the basis for the study that show the energy penalty can be reduced by up to 50% by including effective heat integration. The energy penalty can be further reduced by pre-drying the coal. [Copyright &y& Elsevier]

Abstract: Integration of CO2 capture and storage (CCS) into existing and new coal fired power stations is seen as a way of significantly reducing the carbon emissions from stationary sources. A significant proportion of the estimated cost of CCS for post-combustion capture from coal-fired power stations is due to the additional energy expended to capture the CO2 and compress it for transport and storage. The additional energy either reduces the power plant output or creates additional CO2 which will increase the CCS requirements. Therefore, reductions in the overall energy penalty of CCS by improving the efficiency of both the carbon capture processes and the integration of the capture technology with the power plant can lead to significant reductions in the cost of CCS. Pre-drying lignite using low temperature heat sources enables power stations to increase their energy efficiency by the use of low grade heat, providing energy that is less carbon intensive and potentially reducing the cost of electricity production. This work reviews the current thinking for integration of CO2 capture plants using solvent absorption for postcombustion coal fired power stations. It also reviews the integration potential of brown coal dewatering processes to a power plant with CCS. The review uses as a basis a 200MWe(nominal) train of an existing pulverised brown coal fired power plant using heat and process integration techniques such as heat pinch analysis to determine the potential for reductions in capture cost by minimising the energy penalty associated with the addition of the CCS. The study shows that the energy penalty reduces from 39% for a CCS plant with no heat integration to 24% for a plant with effective heat integration. The energy penalty can be further reduced by the addition of pre-drying of the coal. This study shows there is potential to reduce the energy penalty associated with the addition of CCS, however the heat exchanger network and the required modifications to the existing equipment have not been determined and further work identifying these issues is required and these will have a large impact into whether the reductions suggested by this study can be economically implemented. [Copyright &y& Elsevier]