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Oxy-fuel combustion is an effective technology for carbon capture and storage (CCS). Oxy-combustion for coal-fired power stations is a promising technology by which to diminish CO2 emissions. Unfortunately, little attention has been paid to the oxy-combustion characteristics affected by the combustion atmosphere. This paper is aimed at investigating the oxy-fuel combustion characteristics of Australian coal in a 0.3 MWth furnace. In particular, the influences of various oxygen flow rates and recirculated flue gas (RFG) on heating performance and pollutant emissions are examined in O2/RFG environments. The results show that with increases in the secondary RFG flow rate, the temperatures in the radiative and convective sections decrease and increase, respectively. At a lower oxygen flow rate, burning Australian coal emits lower residual oxygen and NO concentrations. In the flue gas, a high CO2 concentration of up to 94.8% can be achieved. Compared to air combustion, NO emissions are dramatically reduced up to 74% for Australian coal under oxy-combustion. Note that the high CO2 concentrations in the flue gas under oxy-coal combustions suggest great potential for reducing CO2 emissions through carbon capture and storage. [ABSTRACT FROM AUTHOR]

As a part of the strategic research program 'Advanced technologies for energy generation: Development of a technology for highly efficient zero-emission coal-fired power units integrated with CO capture', a mobile CO absorption pilot plant was erected. The main purpose of the pilot plant was to demonstrate the post-combustion technology in conjunction with a coal-fired power plant. The pilot plant captured CO by chemical absorption in amine-based solvents, which was considered to be the best adapted technology to the requirements of coal-fired power plants and suitable for retrofitting to existing units. The pilot plant captured up to 1000 kg/day of CO from the power plant's flue gases with CO recovery exceeding 90 %. The flexible process flowsheet of the pilot plant offered high potential for the validation of various improvements, which were designed to reduce the process energy demand and to increase the CO recovery. This paper summarizes the initial operation experience at the TAURON Łaziska Power Plant in Poland. Selected first results obtained are presented and discussed. The initial campaigns utilized 20 and 30 wt% monoethanolamine (MEA) solutions recognized as baseline solvents that were suitable for comparative purposes. The initial campaigns at the pilot plant successfully demonstrated reliable operation and promising results. [ABSTRACT FROM AUTHOR]

The use of natural gas for power generation is becoming increasingly important in many regions in the world. Given that the combined cycle gas turbine (CCGT) power stations are lower in capital cost and carbon intensity than their coal-fired counterparts, natural gas fired power stations are considered a vital part of the transition to a low carbon economy. However, CCGTs are not themselves “low carbon” and in order to reach a carbon intensity of less than 50 kg CO 2 /MWh, it will be necessary to decarbonise them via CCS, with post-combustion CCS currently regarded as being a promising technology for this application. In this study, we present a detailed model of a 420 MW triple-pressure reheat CCGT and evaluate its technical and economic performance under full and part load conditions. We evaluate the technical performance of our CCGT model by comparison to an equivalent model implemented in Thermoflow THERMOFLEX and observe agreement of power output and efficiency to within 4.1% and the temperature profile within the HRSG within 2.9%. We further integrate the CCGT with a dynamic model of an amine based CCS process, and observe a reduction in the base plant efficiency from 51.84% at full-load and 50.23% at 60% load by 8.64% points at full-load and 7.93% points at 60% load. A core conclusion of this paper is that CCGT power plants equipped with post-combustion CCS technologies are well suited to dynamic operation, as might be required in an energy system characterised by high penetrations of intermittent renewable power generation. [ABSTRACT FROM AUTHOR]

Abstract: Adding post-combustion capture technology to existing coal-fired power plants is being considered as a near-term option for mitigating CO2 emissions. To supply the thermal energy needed for CO2 capture, much of the literature proposes thermal integration of the existing coal plant’s steam cycle with the capture process’ stripper reboiler. This paper examines the option of using an auxiliary natural gas turbine plant to meet the energetic demands of carbon capture and compression. Three different auxiliary plant technologies were compared to integration for 90% capture from an existing, 500 MW supercritical coal plant. CO2 capture (via a monoethylamine (MEA) absorption process) and compression is simulated using Aspen Plus. Thermoflow software is used to simulate three gas plant technologies. In some circumstances, it is found that using an auxiliary natural gas turbine may make retrofits more attractive compared to using thermal integration. The most important factors affecting desirability of the auxiliary plant retrofit are the cost of natural gas, the full cost of integration, and the potential for sale of excess electricity. [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: Commissioned in 2009, the CO2CRC/H3 Capture Project is demonstrating post-combustion carbon capture (PCC) on a lignite fired power plant in the Latrobe Valley, Victoria, Australia. The facility is located within International Power’s Hazelwood Power Plant and uses three different CO2 capture technologies — solvent, adsorption and membrane processes. This project, addressing the PCC issues specific for Victorian brown coal fired power stations, was initiated in July 2007 as a three year research project by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) under the Victorian State Government’s Energy Technology Innovation Strategy (ETIS) program. The project is part of the Latrobe Valley Post Combustion Capture (LVPCC) Project — a multi site, multi scale, multi technology PCC trial. The integrated research and development program includes an evaluation of these technologies for commercial scale application. This paper describes the technologies used, how they have progressed from laboratory to pilot demonstration, the main outcomes, and plans for future developments. [Copyright &y& Elsevier]

Abstract: In May 2007, E.ON Group (E.ON) set an ambitious target for reducing the specific CO2 emissions of the overall group’s electricity generation. By 2030, E.ON will reduce the specific CO2 emissions to 360 grams per kilowatt hour, half the 1990 figure. Thus, besides increasing the share of renewables and maintaining the nuclear share, E.ON identified the need to advance the technology of fossil fuel fired power plants. E.ON pursues a strategy of replacing power stations at the end of their life cycle with new, state-of-the-art power stations which are ready to be equipped with CCS (carbon capture and storage) and therefore “capture ready”. Moreover, E.ON is developing CO2 capture and storage as this technology has the potential to drastically reduce emissions from coal-fired plants. Beginning in 2020, E.ON intends to have large scale CCS technology available. E.ON’s coordinated strategy encompasses research, development and demonstration (RD&D) and is directed towards pre combustion capture, oxyfuel and post combustion capture with a focus on the latter. E.ON is working together with international partners to further develop the existing technologies for capturing of CO2 by testing advanced technologies in several pilot plants at our sites. The goal of the pilot projects is to optimise the downstream capture of CO2 from flue gas (post combustion capture) hence reducing the auxiliary power consumption of the capture process. An update on the pilot projects, suppliers and achievement made will be given. Besides improving the capture process itself the technology needs a significant increase of the treatable flue gas capacity compared to today’s limits known from chemical industry. Therefore E.ON is also involved in the development of demo scale projects proving the feasibility of the full CCS chain (including transport and storage). E.g. our Kingsnorth power station in the UK has entered the next stage of the UK Government’s carbon capture and storage (CCS) competition after developers. We submitted an Outline Solution Bid competition on 9 November 2009. The competition is aiming to deliver the UK’s first fullscale CCS demonstration project. We have come to an agreement with both the European Commission and the Dutch Government on the funding of our ROAD-project. This is our joint project with Electrabel (part of GDF SUEZ) at RotterdamMaasvlakte (NL). The Dutch part of the funding is now before the European Commission for State Aid approval. We will report about the projects and the progress made in our market units. In addition E.ON is engaged in the development of storage sites and transport routes for CO2. Our business unit E.ON Gas Storage is involved in several research and development activities. The paper will highlight E.ON’s main CCS activities. An overview will be given as well as an update on the status of the current projects and available results. [Copyright &y& Elsevier]

Abstract: The Dutch Ministry of Spatial Planning and the Environment (VROM) engaged Jacobs Consultancy to develop a definition and measuring tool aimed at quantifying the CO2 Capture Readiness of a combustion plant. The tool developed tests the level and completeness of pre-project execution information. The testing of pre-project information is a standard practice in the refining and petrochemical industry and Jacobs Consultancy has adapted and tailored these practices to develop the Capture Readiness tool. The tool was developed in 2008 and was pilot tested on two already permitted coal fired power plant projects in 2009. The Capture Readiness tool is similar in concept to the well known Project Definition Rating Index originally introduced by the Construction Industry Institute for Major Capital Projects. The tool quantifies the readiness of a project to accommodate future CO2 capture and parallels the phased approached to Major Capital Projects used by the Project Definition Rating Index. A short introduction to the application of the PDRI methodology to test the completeness of the project development information–often also referred to as Front End Loading or FEL, is included in this paper to establish the parallel approach we have used in the development of the Capture Readiness tool. The Jacobs Consultancy Capture Readiness tool is then discussed in more detail. [Copyright &y& Elsevier]

Abstract: This paper presents an environmental assessment of three scenarios postulating a national deployment of the Carbon Capture and Storage (CCS) chain by 2020–2050 on the French biggest industrial CO2 emitters (41 emitters among 9 industrial sectors) that had been carried out as part of the SOCECO2 project. 1 [1] SOCECO2 project, funded by the French National Research Agency, 2006–2009, involving the following partners: ALSTOM Power, APESA, BRGM, CNRS-CIRED, GDF Suez, IFP Energies nouvelles, INERIS, TOTAL. This analysis is based on the comparison of these CCS scenarios with reference scenarios without CCS at the same timeframe. Results detailed below focus on greenhouse gas (GHG) emissions and energy consumption, although NOx and SOx emissions balances have also been evaluated in the same project. Conclusions of this study provide information about the extent and main contributing factors of potential environmental outcomes (negative or positive) associated to CCS deployment. [Copyright &y& Elsevier]

Abstract: Using CO2/N2 gas separation membranes for post-combustion capture, the most important problem is how to create the driving force efficiently because the feed flue gas has only ambient pressure and a relatively low CO2 content. In order to fulfill the separation target – 95mol% CO2 purity and appropriate degree of CO2 separation – multi-stage systems are necessary using feasible membranes. This paper describes a detailed parametric study for multi-stage membrane systems used in a coal-fired power plant. According to the above-mentioned boundary conditions, the investigation process was divided into two steps: (a) energy consumption and (b) capture cost analyses. In the first step, by varying the position of the compressors and vacuum pumps and recycling the flue gas to the feed side, cascade variants were developed and analyzed in detail. The cascade system was integrated in the 600MW North Rhine-Westphalia reference power plant and compared with the chemical absorption process. In the second step, an economic model was developed to make a further analysis of the cascade system. A correlation was established between the membrane parameters (selectivity, permeability) and system performance (energy consumption, capture cost). [Copyright &y& Elsevier]

This paper presents the Life Cycle Assessment (LCA) analysis concerning the selected options of supercritical coal power units. The investigation covers a pulverized power unit without a CCS (Carbon Capture and Storage) installation, a pulverized unit with a "post-combustion" installation (MEA type) and a pulverized power unit working in the "oxy-combustion" mode. For each variant the net electric power amounts to 600 MW. The energy component of the LCA analysis has been determined. It describes the depletion of non-renewable natural resources. The energy component is determined by the coefficient of cumulative energy consumption in the life cycle. For the calculation of the ecological component of the LCA analysis the cumulative CO2 emission has been applied. At present it is the basic emission factor for the LCA analysis of power plants. The work also presents the sensitivity analysis of calculated energy and ecological factors. [ABSTRACT FROM AUTHOR]