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Abstract: Alstom is developing a portfolio of solutions to address CO2 emission reductions. Among them is CO2 Capture and Storage (CCS) for which Alstom is developing several CO2 capture systems based on post-combustion and oxycombustion processes. This paper will be oriented to utility and industrial companies that would like to be prepared to CCS challenges and understand the key features of the CO2 capture technologies, in this article focus will be on oxy-combustion. This paper is also oriented to “oxy-experts” community for an update coming from pilots operation. It will describe key features of the different pilot projects with Alstom’s involvement and will describe the work performed in there. The development of CO2 capture technologies are being pursued by European and US suppliers in collaboration with utility companies, academia, the US DOE, the European Union, and universities. The first part of this article will address the work of Alstom and corresponding results in three major oxy pilots: • Vattenfall Schwarze Pumpe Oxy-combustion pilot plant (30 MWth, coal)) and corresponding results (pilot is in operation since September 2008, a full PC oxy-combustion chain has been under evaluation there). • An oxy tangentially fired boiler development project (coal) with co-funding from the US DOE and other organizations, which includes pilot testing at the 15 MWth scale, conducted in Windsor CT (US). This pilot has started operation in September 2009. • The TOTAL Lacq Oxy-combustion pilot plant (30 MWth, natural gas) where Alstom did the retrofit of a conventional boiler for its conversion into oxy-combustion. Considerable knowledge has been gained with these pilots through different considerations, both on boiler components but also on the integrated oxy chain. All these positive outcomes confirm the expectations of the community in oxy-development and open the door to the next development step of ∼250 MWel large scale oxy-fired carbon capture and storage (CCS) demonstration plants. This paper provides an update about the CO2 capture pilot plant operation and also present the technical challenges expected to be demonstrated during large scale demonstration plants. [Copyright &y& Elsevier]

Abstract: After 3 years and over one thousand person-months of effort, the FP6 CACHET project was successfully concluded in the first half of 2009. CACHET focussed on pre-combustion capture of carbon dioxide (CO2) from natural gas fuelled power generation and hydrogen (H2) production. Through a combination of experimental and paper studies, CACHET developed, optimised and evaluated four promising capture technologies: Advanced steam methane reforming (HyGenSys), Redox technologies (chemical looping), Metal membranes and Sorption enhanced water gas shift (SEWGS). This paper reports the technical and economic conclusions of the project and provides a look ahead to the future for each of the technologies and the challenges for full scale deployment. All technologies showed the potential to reduce CO2 emissions by more than 90% and the opportunity to improve the energy efficiency compared to the state-of-the-art technology. [Copyright &y& Elsevier]

Abstract: A significant proportion of the research into CCS in the literature assumes ‘complete capture’ of the CO2, that is at least 85 to 90 percent of the CO2 from the flue gas is captured for the entire operating year (7,000 to 8,000 hours). Only a few papers have examined a model involving ‘flexible’ operation of the capture facility in which the CO2 is captured at variable or reduced rates for all or part of a day, week, season or year. This paper presents an assessment of the operational opportunities for deploying flexible CO2 capture at black coal fired power plants located in the state of New South Wales (NSW), Australia. Different models of flexible capture including part-time operation, partial CO2 capture rates and a combination of both operating modes are examined. The results show that it may be possible to reduce the current CO2 emissions from NSW coal-fired power plants by up to 50% during summer while still meeting the state electricity demand. The estimated cost of CO2 avoided ranges from A$120 to A$190 per tonne avoided for flexible capture. [Copyright &y& Elsevier]

Abstract: The Kansai Electric Power Co., Inc. (KEPCO) has developed energy efficient chemical absorbents and economical processes which aim to reduce the cost of CO2 capture, in collaboration with Mitsubishi Heavy Industries, Ltd. (MHI). Together the companies have been developing and critically testing high efficiency, economical absorbents according to the latest absorbent development procedures and process simulation for CO2 capture processes. This work has been ongoing since 1991, using several Japan based R&D facilities and a pilot plant, used to verify improvements, located at Nanko Power Station in Osaka, Japan. Following significant testing of a range of absorbents in the mid 1990s, KS-1TM, KS-2 and KS-3 were developed. Based on subsequent rigorous evaluation of the three solvents, KS-1TM was selected for commercialization because of its overall technical and economical merits. During long-term pilot plant testing, the improved absorbents demonstrated superior performance in relation to the regeneration energy requirements leading to the following results: 2.94 MJlkg- CO2 in combination with KS-1TM” and the Kansai Mitsubishi Carbon Dioxide Recovery (KM-CDR ProcessTM) commercial process. In addition, practical, commercially applicable improved absorbent properties such as low corrosiveness and low solvent consumption were also confirmed. KEPCO and MHI continue development work in this area and the current status is summarized as follows: The highly successful R&D phase has led to the commercial deployment of CO2 capture technology and seven (7) commercial CO2 capture plants are currently under operation, with a maximum CO2 capture capacity of 450 metric tons per day (tpd). These commercial plants are deployed in the chemical and fertilizer industry, where the operational performance is assisting in the improved development of R&D concepts. Two (2) further commercial plants are under construction, with commissioning expected in Q3 2010. For further cost reductions in relation to CO2 capture, recent work has focused on developing new energy efficient chemical absorbents and processes. Following modifications to the Nanko CO2 capture pilot plant a new “Energy Saving Process”, was developed, which leads to a greater than 10% steam consumption reduction over the MHI conventional process using KS-1TM absorbent. Additionally the same reduced steam consumption was recorded for tests using the KS-1TM absorbent. A thermal energy requirement of less than 2.5 MJ/kg- CO2 in combination with KS-1TM and the “New Energy Efficient Process” has been confirmed under the optimum operation condition of the CO2 capture process. In addition to select new absorbents which feature the best profile and fit to the actual operating condition, KEPCO and MHI have intensively evaluated vapor-liquid equilibrium (VLE) and reaction kinetics for a range of newly developed absorbents and their performance is presented in this paper. The above data was obtained using the Nanko CO2 capture pilot plant which operates under a natural gas fired boiler condition and we expect that the thermal energy requirement of coal fired boiler flue gas (with greater CO2 concentration condition) will be further reduced. KEPCO and MHI are continuing pilot tests for the “Energy Saving Process”, leading to the application of this new process in commercial CO2 capture plant design. This paper introduces and presents the current status of the KEPCO & MHI CO2 capture technology and concepts for future energy reduction improvements. The paper will also include test results in relation to newly developed absorbents, and the “New Energy Efficient Process”, which have enhanced the performance and reduced the associated energy penalty of the CO2 capture process. KEPCO and MHI are continuing the development of efficient absorbents and optimized processes, thus helping to facilitate the future wide scale deployment of CO2 capture technology as an effective counter measure against global warming. [Copyright &y& Elsevier]

Abstract: At present, hydrogen is largely used in refineries and ammonia plants but in future it may be used as an energy carrier for vehicles, power generation and distributed heat production. One of the most promising technologies for hydrogen production with low CO2 emissions is coal gasification with CO2 capture and storage. Hydrogen can be co-produced with electricity in Integrated Gasification Combined Cycle (IGCC) plants. This paper summarizes the results of studies carried out by Foster Wheeler Italiana for the IEA Greenhouse Gas R&D Programme (IEA GHG). Performance and costs data are presented for five different coal gasification plants producing electricity and/or hydrogen with and without CO2 capture. The cost data are on a 2nd quarter 2008 basis and take account of the recent large increases in plant investment costs and coal prices. The paper assesses possible advantages of hydrogen and electricity co-production in future energy supply systems and the advantages of being able to operate plants flexibility to meet the varying demands for hydrogen and electricity. If hydrogen becomes used as an energy carrier it will displace some of the demands for natural gas, gasoline and diesel fuel. A market analysis of the demands for these fuels was performed for The Netherlands and the USA to determine possible future hydrogen demand and how it will vary throughout the year. Demands for electricity were also determined. Plant performance and costs are estimated and electric power production costs are evaluated. Electricity and hydrogen co-production plants are compared to plants that produce electricity only, with and without CO2 capture, to evaluate the cost of CO2 avoidance. The benefits of flexible co-production with and without buffer storage of hydrogen are also evaluated. [Copyright &y& Elsevier]

Abstract: Coal is central to China’s continued economic growth and CCS is one of the most promising technological solutions to curb the CO2 emitted from the continued use of coal. This paper introduces some areas of recent R&D on CCS in China and focuses, in particular, on the Near Zero Emission Coal (NZEC) project, a China-UK CCS initiative. NZEC is being undertaken in three phases, with the current project comprising the first phase. The ultimate aim of NZEC, following Phase 3, is to have constructed and operated a coal-fired power plant with integral CCS in China. In this paper, some of the early progress made in NZEC Phase 1 is described. Launched in November 2007, the objectives of Phase 1 are to build confidence in CCS and to explore technology options for demonstrating coal-fired power generation with CCS in China. The Phase 1 partnership of nine leading UK organisations and 20 from China demonstrates the strong collaborative working relationship that exists between China and the UK, at all levels, to develop CCS as a key climate change mitigation technology. Apart from NZEC, China is involved in several national and international CCS initiatives and some of these will be touched upon in this paper. The success of the 18-month first phase will, to a large extent, be measured against its contribution to increasing CCS capacity in China and against strengthened links between Chinese and British experts. Activities designed to raise capacity are described. [Copyright &y& Elsevier]

Abstract: This paper analyzes various aspects of the Zecomix cycle, a novel coal fired power plant, based on various innovative processes to achieve elevated efficiency and zero-emissions. A coal hydro-gasification process, using recycled steam and hydrogen as gasifying agents, converts carbon to CH4, which is then processed by two carbonator reactors where CH4, mixed with steam and contacted with calcium oxide, is converted to an H2/H2O based syngas while CO2 is absorbed by the solid sorbent generating CaCO3. The synthetic fuel produced in the chemical island is burned with oxygen in a semi-closed high temperature steam cycle, with a rather complex supercritical heat recovery steam cycle. The main relevant operating parameters for the chemical island are varied in order to evaluate their effect on plant performance and to optimize the process. In addition, the paper presents a rather detailed analysis of some critical issues, often neglected in previous works from the literature. Net plant efficiency of 44–47% with a virtually complete carbon capture was predicted, a very interesting results with respect to other proposed coal power plants with carbon capture. The high complexity of the chemical island and the importance of a good sorbent performance in the critical conditions typical of this plant should be however taken into account for a fair comparison with other plant concepts. [Copyright &y& Elsevier]

Abstract: The potential benefits of precombustion carbon dioxide capture are well documented, and adsorption remains a promising separation process in this area. This paper details work to identify and assess the potential of high temperature adsorbents suitable for precombustion capture. The aim of this paper is to schematically identify adsorbents that are suitable for carbon capture in different temperature ranges. A critical aspect of this work is to assess the materials not only in terms of carbon dioxide isotherms and absolute loading, but to consider the wide range of other properties that are required to achieve an industrially feasible adsorbent - selectivity, cycling capacity, stability, kinetics, high pressure loading, fate of other components (including water, H2S, NH3, CO and N2). It is only when all these requirements are sufficiently met, that an adsorbent can be consider worthy of industrial consideration. A range of analytic screening tests are described to enable a full characterisation of the merit of a specific adsorbent. The adsorbents investigated are zeolites (NaX, calcium chabazite), commercially available hydrotalcite, layered double hydroxides/oxides (LDH/Os), and magnesium double salts. Each operates in a different temperature range and offers potential for integration within an Integrated Gasification and Combined Cycle precombustion process train. Some of the promising and significant conclusions of this work are - [•] Magnesium double salts present very favourable carbon dioxide isotherms and demonstrate significant carbon dioxide loading and the isotherms are suitable for PSA or TSA operation at high temperature. [•] LDHs or their derivatives as layered double oxides can adsorb up to 1.5mol/kg CO2. Water does not affect CO2 sorption, and the material has good recyclability in TSA. [•] The selectivity of hydrotalcite is well documented. However there is no reported literature on the adsorptive behaviour of these materials with respect to trace components - H2S and NH3. These results are reported. [•] Calcium chabazite displays useful CO2 loading potential in a unique temperature range around 200 ∘C. [•] NaX has the potential to replace Selexol at an operating temperate of 130 ∘C. [Copyright &y& Elsevier]

Abstract: Oxyfuel combustion is one of the promising technologies to enable CCS for new and existing coal-fired power plants. For retrofit applications, oxyfuel is an attractive option because it does not have major impact on the boiler-turbine steam cycle. This paper presents a case study for retrofitting oxyfuel combustion technology in large state-of-the-art power plants that are originally commissioned and operated in air-fired mode. The overall process design for the modified power plant is outlined; necessary modifications of relevant components are explained. The paper also discusses results of experiments and numerical calculations on combustion behavior in the furnace. Retrofit measures ensure that the power stations still can run under both air-fired and oxyfuel-fired conditions if required by regulations/market conditions. This provides additional operational and commercial benefits for the operator of the plant and reduces the technical risk of implementing new components and processes not yet proven in the power sector. [Copyright &y& Elsevier]

Abstract: Ecofys and ECN conducted a study commissioned by the IEA Greenhouse Gas R&D Programme to identify the most suitable combinations of medium-scale CO2 sources (1–100 MWth) and capture technologies, with respect to potential and costs (see parallel paper by Hendriks et al.). An industrial coal-fired Circulating Fluidized Bed (CFB) boiler with oxyfuel combustion and Oxygen Conducting Membranes (OCM) appeared to be an economically attractive combination to capture CO2. This paper describes the principle and economic evaluation of this combination in comparison with a reference coal boiler without CO2 capture, as well as a coal boiler with CO2 capture based on amine scrubbing. [Copyright &y& Elsevier]

Abstract: Greenhouse gas emissions from industrial processes, such as cement manufacturing or steel production, in Australia accounts for more than 40 Mt CO2-e per annum, representing close to 20% of Australia’s potentially sequesterable emissions. Further, the emissions from these processes are highly concentrated in CO2 compared to the emissions from power generation. It is not clear if these higher concentrated gases may provide low cost options for demonstrating CO2 capture or if this benefit will be lost due to the smaller total volume of CO2 emissions of most industrial processes. Nevertheless, this sector of the economy requires further analysis. This paper will provide an overview of the emissions from Australian cement sector including both the emissions from the chemical process itself, as well as the associated emissions from energy use within those processes. Specific attention will be focused on the Australian cement industry. While CCS involves the integrated part of capture, transport and storage, the focus of this paper is on the capture side and will illustrate CCS options for the cement industry. [Copyright &y& Elsevier]

Abstract: Amino acid salts are of great interest as potential solvents for CO2 capture because they are considered to be environmentally friendly. In the present paper, results of experimental work with a pilot plant with 3.5 M potassium sarcosine are presented. Both absorption kinetics and energy consumption are studied. The results show clearly that the amino acid salt system has a high absorption rate and high energy requirement compared to 30 wt-% MEA. The solvent system has been modeled in an in-house tool and simulation results are compared with the some performance results obtained experimentally. The soft-model approach developed for the potassium sarcosine solvent systems represents the absorber fairly well, while it seems to be too simplified to represent the stripper conditions. The present study is part of an ongoing EU project, Cesar. [Copyright &y& Elsevier]

Abstract: Oxyfuel combustion CO2 capture technology presents an excellent opportunity for achieving near zero emissions from the coal-fired power plants. In the oxyfuel technology, the volume of flue gas is reduced by a factor of four to five (on a dry basis) due to elimination/reduction of nitrogen from combustion. This reduced volume of CO2-rich flue gas has to be compressed to 25 to 35 bar (a) for purification, thus further reducing the actual volume of flue gas by a factor of 25 to 35. If the equipment for removing trace impurities (SOx, NOx and Hg) is installed downstream of the flue gas compressor, the capital investment could be significantly reduced compared to that for the air-fired operation. Furthermore, by processing the entire volume of flue gas in the CO2 purification unit, it is possible to remove and concentrate the trace impurities in the solid and liquid waste streams and to produce a vent stream with near zero emissions and a high purity CO2 relatively free of trace impurities. Praxair is developing an oxy-combustion flue gas purification technology that will leverage these synergies. This technology will reduce emissions of CO2, SOx and Hg by >99% and NOx emissions by >95% compared to an air-fired pulverized coal power plant. The benefits of the technology include management of air ingress problems, capital and operating cost savings for SOx and NOx removal, reduction in CO2 capture cost and production of high purity CO2 stream for sequestration. These benefits will translate to lower cost of electricity for power plants with CO2 capture. This paper presents the experimental data for the SOx/NOx removal and high CO2 recovery processes and the results of the commercial viability assessment. [Copyright &y& Elsevier]

Abstract: This paper investigates the performance of SEWGS (Sorption Enhanced Water Gas Shift), an innovative reactor for CO2 capture, applied to Integrated Gasification Combined Cycle (IGCC). Firstly, two IGCC reference cases based on dry feed slagging Shell gasifier, with and without CO2 capture, are defined. Then, two different integrations of SEWGS are investigated. The first assumes a conventional low-temperature acid gas removal process adopted upstream the SEWGS; this solution shows slight thermodynamic advantages towards the reference case with CO2 capture (higher efficiency of 1% point), but not from lay-out simplification and equipment savings. The second solution assumes a simultaneous CO2 and sulphur separation from the syngas; this results in a net electric efficiency gain over the reference case of about 2 percentage points. Moreover, this solution allows a significant plant simplification and equipment reduction with further advantages from economic point of view, which is not evaluated in this work. This activity is carried out under the FP7 project CAESAR financed by the EU community. [Copyright &y& Elsevier]

Abstract: Chemical-looping combustion (CLC) is a combustion concept with inherent separation of CO2. The process uses a solid oxygen carrier, which consists of metal oxide, to transfer the oxygen from air to fuel. This paper presents findings from batch tests performed in a 10 kWth CLC pilot for solid fuels. The pilot, which is the world’s first chemical-looping combustor for solid fuels, is based on interconnected fluidized-bed technology and features a fuel reactor (FR) and an air reactor (AR) as the principal reaction chambers. In the FR, fuel is gasified with steam whereupon gasification products react with the oxygen carrier to form, ideally, CO2, H2O and SO2. Oxygen-carrier particles exit the FR through a weir and are led to the AR, where they are regenerated to their oxidized state. The pilot has been operated using a natural iron-titanium ore called ilmenite as oxygen carrier. Previous continuous tests have demonstrated a need for batch tests in order to obtain complementary information on system performance. In this study, five fuels were fed to the fuel reactor in batches of 20–25 g at four temperatures; 940 °C, 970 °C, 1000 °C and 1030 °C. By using devolatilized fuel, it was possible to determine (a) oxygen demand associated with syngas from char gasification as well as (b) kinetics of char conversion to gas. Rates of char conversion were found to be temperature dependent, as expected, whereas no temperature dependence was found for the oxygen demand. Activation energies for conversion of char to gas were calculated using Arrhenius plots. The minimum oxygen demand for char was found to be around 5%. [Copyright &y& Elsevier]

Abstract: The Calcium Looping (CaL) process using CaO as sorbent for capturing CO2 from flue gases is a promising postcombustion CO2-capture technology that is economically competitive with other capture technologies with an overall increased output in electric power and a low electric efficiency penalty associated with CO2 capture. The process can be realized in a Dual Fluidized Bed (DFB) system utilizing a Circulating Fluidized Bed (CFB) reactor as carbonator operating at 600–700 °C and a second CFB as regenerator operating at temperatures between 850–950 °C. The separation of CO2 from the flue gas takes place through the carbonation reaction (CaO+CO2→CaCO3). The regeneration of the sorbent is realized via the reverse reaction in the regenerator at higher temperatures. The feasibility of the CaL process has already been shown at IFK, University of Stuttgart on a lab-scale size. In order to investigate the calcium looping process using real combustion flue gas and to evaluate the process on a long-term basis, a 200 kWth pilot plant has been built at IFK. This paper delineates the design of the pilot plant to capture over 90% CO2 and provides an overview of the main components and the control philosophy. First results from the successful commissioning of the pilot plant are also shown. [Copyright &y& Elsevier]

Abstract: Through technical discussion of oxyfuel retrofit of Meri–Pori’s supercritical power plant (565 MWe net), it was recognized that a deep analysis of the risks associated with the retrofit solution would be necessary for learning more about oxycombustion technology and to clarify the actual risks. As the result of the risk analysis, it was concluded that oxyfuel retrofit and oxyfuel operation would only involve low magnitude risks. This paper describes methodology of the risk analysis and major results including mitigation methods of the risks. [Copyright &y& Elsevier]

Abstract: The development of CO2 capture technologies is being pursued by US, European, Japanese and other suppliers in collaboration with utility companies, universities and Governments in the USA, Europe, Canada and Australia. Among the more promising post-combustion solutions is the Advanced Amine Process (AAP), jointly developed by Alstom and The Dow Chemical Company (Dow). This paper describes the AAP pilot plant located at a Dow-owned site in South Charleston, West Virginia, USA. It provides an update on how the experience from the pilot plant is used to improve the design and predicted performance of large-scale demonstration plants. It will summarize pilot plant results and show the progress of the technology development. The pilot plant is processing flue gas from a bituminous coal-fired boiler with UCARSOLTM FGC 3000 series of solvents, advanced amine solvents specifically developed by Dow for flue gas applications. The pilot plant has a CO2 removal capacity of ∼5 tonne CO2/day and can capture in excess of 90% of inlet CO2. A test program with a wide range of operating conditions provides information on capture performance, including solvent and operational stability. A state-of-the-art laboratory measures solvent composition, CO2 loading, solvent contamination and degradation species. Long term solvent composition is controlled by a combination of flue gas pre-treatment and solvent reclamation. These results are being used to develop a large-scale demonstration plant (above 250 MWe) under the EU Flagship program in Europe. [Copyright &y& Elsevier]

Abstract: The ultimate goal of this R & D program is to develop better and more effective CO2 separation processes that can be used to recover CO2 from industrial sources such as fossil fuel-fired power stations, coal gasification plants, petroleum refinery facilities and hydrogen production units at the lowest possible capital and operating costs. This paper presents the latest research results on fundamental studies of CO2 capture process technologies at the International Test Center for CO2 Capture (ITC). Specifically, it looks at recent advances made in reducing the reboiler heat duty. Four approaches were developed and evaluated for their contributions to the reduction of reboiler heat duty. These were: development of energy efficient solvent, process optimization, process configuration optimization, advanced process configuration optimization plus thermal energy optimizer, and activated process. In all cases, the CO2 capture process was operated at 90% absorber efficiency. All these approaches were compared with the conventional process using 5 molar MEA (case 1). The test results for the first 6 scenarios were obtained experimentally in 12-inch ID absorber and regenerator columns (1 tonne/day CO2 capture pilot plant) and by modeling using Promax. The results for the last scenario (activated process) were obtained experimentally using 2-inch ID absorber/regenerator columns. The results showed that for the conventional configuration with 5 molar MEA, the heat duty was 5.1 GJ/tonne of CO2 produced whereas with the same configuration with RS-2 solvent, the heat duty was 4.3 GJ/tonne of CO2 produced. For the process optimization case, the heat duties were 3.0 and 2.9 GJ/tonne of CO2 produced for MEA and RS-1 solvents, respectively. In the case of process configuration optimization, the heat duties were 2.6 and 2.1 GJ/tonne of CO2 produced for MEA and RS-2 solvents, respectively. For advanced process configuration optimization plus thermal energy optimizer, the heat duties were reduced to 1.8 and 1.6 GJ/tonne of CO2 produced for RS-2 and RS-3 solvents, respectively. It was interesting to observe that with the catalyst activated process with MEA, the heat duty was 2.0 GJ/tonne CO2 produced, and when the catalyst activated process was superimposed on the advanced process configuration process, the heat duty reduced drastically to 1.2 GJ/tonne CO2 produced. [Copyright &y& Elsevier]

Abstract: N.V. Nuon (part of the Vattenfall Group) operates an IGCC in Buggenum and is developing a multi-fuel IGCC with CO2 capture and storage (Nuon Magnum) in Eemshaven, the Netherlands. In order to prepare for large-scale application of CO2 capture and storage, a CO2 capture pilot plant is constructed at the Buggenum IGCC plant and will be ready for testing in January 2010. The overall objective of the CO2 Catch-up project is to demonstrate pre-combustion CO2 capture and to generate knowledge in the form of useful data and operational experience. In parallel with the development, realisation and operation of the pilot plant, a test and R&D programme has been initiated together with Delft University of Technology, ECN and KEMA. In this paper, the technology is described in more detail and the test and R&D programme is outlined. [Copyright &y& Elsevier]

Abstract: Packed towers are common as gas/liquid contacting units for separation processes. Several studies have been performed to measure and model pressure drop, liquid hold-up and effective mass transfer area. However, most investigations have concentrated on distillation operation and the correlations obtained may not be directly applicable to reactive absorption. The present work presents a study of hydrodynamics and mass transfer properties of Sulzer structured packing Mellapak 2X using both an inorganic and an amine solvent. The pilot plant has an absorber column with packing height of 5 m and diameter 0.5 m. In this paper results for absorption studies and pressure drop, liquid hold-up and effective mass transfer area are presented. Dependencies of liquid flow, gas flow and viscosity were in agreement with correlations found in literature. New correlations for the hydrodynamic characteristics will be implemented in an in-house software as a basis for absorber and desorber design. [Copyright &y& Elsevier]

Abstract: In this paper, a new synthesis method to obtain mixed CaO/Ca12Al14O33 solids for high temperature CO2 capture is presented. The modification of a pure phase Ca3Al2O6 solid through a thermal treatment under controlled conditions leads to a high CO2 absorption capacity material, with very promising long term stability during absorption/desorption cycles. The influence of the calcination temperature during the synthesis of the Ca3Al2O6 powders, and the temperature and atmosphere applied during the thermal treatment was studied. Therefore, optimum conditions for high stabilization rate and high final CO2 absorption capacity of the sorbent could be determined. Comparison with a natural sorbent (dolomite) over 150 carbonation/calcination cycles is also included, showing a substantial improvement of the synthetic solid CO2-uptake at long term use, compared to that of natural sorbents. [Copyright &y& Elsevier]

Abstract: This paper presents an analysis of the application of Molten Carbonate Fuel Cells (MCFC) in a natural gas fired combined cycle power plant to capture CO2 from the exhaust of the gas turbine. The gas turbine flue gases are used as cathode feeding for a MCFC, where CO2 is transferred from the cathode to anode side, concentrating the CO2 in the anode exhaust. This stream is then sent to a CO2 removal section consisting either in (i) an oxygen combustion of residual fuel compounds, or (ii) a cryogenic CO2 removal section, cooling the exhaust stream in the heat recovery steam generator. The MCFC is based on Ansaldo Fuel Cells experience, fed with natural gas processed by an external reformer which is thermally integrated within the FC module. Differently from more conventional approaches to CO2 capture, it works increasing the plant power output, acting as an active CO2 concentrator. The plant shows the potential to achieve a CO2 avoided ranging between 58 and 68%, depending on the configuration while taking advantage from the introduction of the fuel cell, the final electric efficiency is lower from 0.2 to 0.8 points lower than the original combined cycle (57.8% LHV in the most efficient configuration). The power output increases by about 22%, giving a potentially relevant advantage with respect to competitive carbon capture technologies. [Copyright &y& Elsevier]

Abstract: To make the deployment of carbon capture possible, it is highly needed to develop original solutions that induce low energy penalty and that are easy to operate. This paper aims at presenting the DMX™ process developed at IFP Energies nouvelles based on special solvents which are characterized by the formation of two immiscible phases for given temperature and CO2 loading conditions. The concept of demixtion is briefly described in terms of physico-chemical properties, its interest and all required steps for appropriate process development are discussed. The corresponding process is presented and a technico-economic analysis is given. It is shown than one can reach a reboiler duty as low as 2.1 GJ/t CO2 which is significantly lower than the 3.7 GJ/t CO2 of the 30wt.% MEA reference process. It is also discussed that the energy consumption at reboiler cannot be the only parameter to consider for comparison with other processes and some further information about the DMX™ process are given. Operational issues are particularly discussed. In that sense, the performances of the DMX-1TM solvent in terms of degradation and corrosion are shown. Similarly a particular focus is made on the liquid/liquid separation which is a key aspect of the DMX™ process. [Copyright &y& Elsevier]

Abstract: Carbon Capture and Storage technology (CCS) has the potential to play a key role in reducing CO2 emissions as required by international commitments. CCS must be included in the portfolio of solutions in order to reach the target of world emissions reduction by 50% in 2050. One of the most relevant European initiatives for the deployment of CCS technologies is promoted by the Fundacion Ciudad de la Energia (CIUDEN). CIUDEN has a complete programme focused on the development of CCT and CCS, particularly oxycombustion technology. This paper includes the description of CIUDEN’s Capture Technology Developing Plant, currently under construction in NW Spain. The installation includes a 20 MWth PC boiler, a 30 MWth CFB boiler, a fuel preparation unit, a biomass gasifier, a flue gas cleaning train, and a CO2 processing unit. The commissioning of the TDP is planned for November 2010. This is the only installation in the world with two large pilot oxy boilers capable of burning a wide range of coals, biomass and pet coke under conventional combustion or oxycombustion conditions. Results are expected to significantly contribute to the development and deployment of oxycombustion technologies, particularly valuable as technical support for the OXYCFB300 Compostilla Project which aims to validate this technology at demo scale. The Compostilla OXYCFB300 Project is based on a 300 MWe Circulating Fluidised Bed (CFB) supercritical oxycombustion plant, with CO2 storage in a saline aquifer. The operation of this installation is planned to start in 2015. [Copyright &y& Elsevier]

Abstract: The Separations Research Program (SRP) pilot plant is located at The University of Texas (UT) Pickle Research Campus and has been operated as a carbon capture facility since 2002. The semi-works scale pilot facility uses air and 3–14 mol% CO2 as flue gas as it applies the latest advancements in carbon dioxide recovery technology. The capacity of the pilot plant is approximately 15 m3/min of gas and 130 liters/min of solvent. Past experimental studies include solvent performance characterization using potassium carbonate with piperazine, monoethanolamine, concentrated piperazine and other proprietary solvents. In recent years, the pilot plant has been utilized to determine the mass transfer and hydraulic characteristics of various structured and random packings using amine-based solvents for CO2 absorption. In 2002, the UT/SRP began developing improved measurement techniques and operating procedures to ensure reliable process control and closure of material and energy balances. Past experience and learning with the UT/SRP pilot plant is currently being utilized for the design and operation of several future pilot plants that will process actual coal-fired flue gas. The purpose of the presentation is to provide a brief description of the UT/SRP CO2 capture pilot plant capabilities, innovative operational procedures and instrument accuracies. The objectives of this paper are to discuss SRP pilot plant experience including: process description, operations and control, key equipment, measurement methods including novel techniques, overall process performance, and future work. [Copyright &y& Elsevier]

Abstract: (1) It is becoming increasingly evident that the prolonged utilization of fossil fuels for primary energy production, especially coal which is relatively cheap and abundant, is inevitable and that Carbon Capture and Storage (CCS) technology can significantly reduce CO2 emissions from this sector thus allowing the continued environmentally sustainable use of this important energy commodity on a global basis. (2) MHI has co-developed the Kansai Mitsubishi Carbon Dioxide Recovery Process (KM-CDR Process™) and KS-1™ absorbent, which has been deployed in seven CO2 capture plants, now under commercial operation operating at a CO2 capture capacity of 450 metric tons per day (tpd). In addition, a further two commercial plants are now under construction all of which capture CO2 from natural gas fired flue gas boilers and steam reformers. Accordingly this technology is now available for commercial scale CO2 capture for gas boiler and gas turbine application. (3) However before offering commercial CO2 capture plants for coal fired flue gas application, it is necessary to verify the influence of, and develop countermeasures for, related impurities contained in coal fired flue gas. This includes the influence on both the absorbent and the entire system of the CO2 capture plant to achieve high operational reliability and minimize maintenance requirements. (4) Preventing the accumulation of impurities, especially the build up of dust, is very important when treating coal fired flue gas and MHI has undertaken significant work to understand the impact of impurities in order to achieve reliable and stable operating conditions and to efficiently optimize integration between the CO2 capture plant, the coal fired power plant and the flue gas clean up equipment. (5) To achieve this purpose, MHI constructed a 10 tpd CO2 capture demonstration plant at the Matsushima 1000 MW Power Station and confirmed successful, long term demonstration following ∼5000 hours of operation in 2006–07 with 50% financial support by RITE, as a joint program to promote technological development with the private sector, and cooperation from J-POWER. (6) Following successful demonstration testing at Matsushima, additional testing was undertaken in 2008 to examine the impact of entrainment of higher levels of flue gas impurities (primarily SO x and dust by bypassing the existing FGD) and to determine which components of the CO2 recovery process are responsible for the removal of these impurities. Following an additional 1000 demonstration hours, results indicated stable operational performance in relation to the following impurities; (1) SO2: Even at higher SO2 concentrations were almost completely removed from the flue gas before entering the CO2 absorber. (2) Dust: The accumulation of dust in the absorbent was higher, leading to an advanced understanding of the behavior of dust in the CO2 capture plant and the dust removal efficiency of each component within the CO2 recovery system. The data obtained is useful for the design of large-scale units and confirms the operating robustness of the CO2 capture plant accounting for wide fluctuations in impurity concentrations. (7) This important coal fired flue gas testing showed categorically that minimizing the accumulation of large concentrations of impurities, and to suppress dust concentrations below a prescribed level, is important to achieve long-term stable operation and to minimize maintenance work for the CO2 capture plant. To comply with the above requirement, various countermeasures have been developed which include the optimization of the impurity removal technology, flue gas pre treatment and improved optimization with the flue gas desulfurization facility. (8) In case of a commercial scale CO2 capture plant applied for coal fired flue gas, its respective size will be several thousand tpd which represents a considerable scale-up from the 10 tpd demonstration plant. In order to ensure the operational reliability and to accurately confirm the influence and the behavior of the impurities in coal fired flue gas, it is necessary to gain further operational experience with coal fired flue gas at large scale. To this extent, MHI has partnered with Southern Company and the Electric Power Research Institute (EPRI) in the United States for a large scale CCS demonstration project using the KM-CDR Process™ and KS-1™ absorbent. MHI’s coal fired CO2 capture experience and know how at 10 tpd scale aided in the design of the 500 tpd CO2 capture demonstration plant to be deployed at Plant Barry Power Station in Alabama. Commissioning of the plant will take place in Q2 2011 and an extensive test program is planned. Following successful demonstration of this plant, in relation to the effect of scale-up concerning the behavior of impurities, it is envisaged that larger-scale commercial CO2 capture plants can be designed and deployed for the coal fired power sector. (9) This paper will summarize the status of the Matsushima plant operational results and the optimization and examination of impurity removal efficiency within the individual plant components. In addition, the current status of the 500 tpd CO2 capture demonstration plant project will be reported. (10) MHI, as a heavy industrial equipment manufacturer, can provide an integrated plant design through the provision of power generation equipment, flue gas clean up, process plants and CO2 compressors. MHI is actively developing solutions to mitigate global warming through the deployment of economically efficient environmental control technologies and advanced optimization of plant equipment. Related activities such as the large scale demonstration of CO2 capture, with our global partners, are important steps leading to the commercialization of this technology for application in the coal fired power generation sector, thus helping to reduce atmospheric industrial emissions of CO2. [Copyright &y& Elsevier]

Abstract: This paper presents the contextualized overview of the CO2 capture technology, with critical evaluation of state-of-art and technological development through patents applications and scientific articles. The scientific research and technological development and innovation of CO2 capture is mapped, providing not only an overview, but also concrete basis to define and optimize research and development (R&D) perspectives. It relates the stage of scientific, technologic and innovation development relate to the actions of the Intergovernmental Panel on Climate Change (IPCC) to ensure the reduction of the global warming due to anthropogenic emissions of greenhouse gases (GHG) into the atmosphere. The yearly monitoring of actions is presented, focusing on scientific, technologic and innovation from governments and companies acting within various countries in an attempt to mitigate the effects of global climate change. The mapping of the capture technologies was focused on absorption, adsorption, membranes, cryogenic, enzymatic and hybrid. The capture technologies are also mapped according to the CO2 capture process (post-combustion, pre-combustion and oxy-combustion). The results are analyzed in terms of priority date, annual evolution of the patents portifolia, technology owners (country, continent, sector of society, companies, (R&D institutions), inventors and their countries, authors of scientific articles, article copyright owners, institutions and countries where the scientific research reported in the articles was performed, patent type (process, method, prototype, product, etc.), patents classification codes showing technologic trends and fields, type of gas source where CO2 is captured, type of processes and type of gas outputs after CO2 capture, details of the components and of the processes for each method capture, among other trends. The results are contextualized in terms of methods of CO2 capture processes, focusing on technology for IPCC, roadmaps, and government programs and strategies for reducing CO2 emissions into the atmosphere. All the capture technologies are growing yearly, both in patent applications and in articles. Absorption and adsorption are the most used capture technologies, post-combustion is the most used capture process, and most of the patents refer to CO2 separation and removal. Most of the copyrights belong to Elsevier and American Physical Society, USA detains 52% of the patent applications and 31% of the articles published. The other patent applications belong mainly to Germany, France, Japan and United Kingdom. The countries with more aggressive appropriation policies are France, Norway, Germany, USA and Netherland. There is a strong correlation between countries of the technology owners and clear CCS government policies. The patent applications refer to over thirty entry gas currents, being focused on combustion and post combustion processes, followed by natural gas specification. New trends like Chemical Looping Combustion (CLC), Chemical Looping Reforming (CLR) are also focused. [Copyright &y& Elsevier]

Abstract: Studies have been carried out to show that there could be benefits in employing a hybrid of the post combustion capture and oxyfuel processes. The former is suited for retrofit purposes but involves an energy intensive solvent regeneration process. The oxyfuel process would result in high partial pressures of CO2 in the flue gas making separation easier. However, the Air Separation Unit is also energy intensive and significant modifications would have to be made on the power generation process. An enhanced- O2 coal power plant with post combustion CO2 capture would produce flue gas with reduced mass flow and higher CO2 partial pressures. The dynamic response of the downstream CO2 capture plant was studied in this paper. [Copyright &y& Elsevier]

Abstract: This paper presents the methodology and the preliminary results of a techno-economic assessment of CCS implementation on the iron and steel sector. The results show that for the short-mid term, a CO2 avoidance cost of less than 50 € /tonne at a CO2 avoidance rate of around 50% are possible by converting the conventional blast furnace (BF) to Top Gas Recycling Blast Furnace (TGRBF). However, large additional power consumption for CO2 removal and oxygen generation, and reduction in BF gas export, makes the economic performance of the technology very sensitive to energy prices. Add-on CO2 capture for conventional BF may achieve similar costs (40–50 € /t CO2 avoided), but the CO2 avoidance rate will be only about 15% of the specific CO2 emissions. For the long term future, although there are large uncertainties, advanced CO2 capture technologies do not seem to have significant economic advantages over conventional technologies. The results also indicate that in a carbon-constrained society, when considering new plants, smelting reduction technologies such as the COREX process, may become a strong competitor to conventional blast furnace based steel making process when equipped with CO2 capture. Although conventional iron and steel making using BF is expected to dominate the market in the long term, strong need for drastic CO2 emissions reduction may drive the sector towards large scale implementation of advanced smelting reduction technologies. [Copyright &y& Elsevier]

Abstract: Currently, Australia emits approximately 600 MT equivalent of CO2 annually, of which approximately 30% is directly linked to the electricity generation using both brown and black coals. To restrain the CO2 emissions, coal based power generators are looking to retrofit the existing power plants with commercially available technology for the post combustion capture (PCC) of CO2 as well as invest in the new power plants with high efficiency steam cycles. Since Australian coals are low in sulphur and the coal-fired power plants are well away from densely populated regions, the flue gas desulphurisation (FGD) and de- NOX regulations are currently not there for the coal based electricity generation in Australia. This is not an advantageous situation for straightforward retrofitting of the existing power plants with 30 wt% aqueous MEA based commercially available PCC technology that has very limited tolerance for SOX and NOX (less than 10 ppmv). In addition, Australia is a dry continent with very limited cooling water availability for the power plants. Hence, the Australian power generators are considering both the power and the post combustion CO2 capture plants to be air cooled. This paper, therefore, assesses the impact of introducing post combustion capture of CO2 on the existing and new Australian coal-fired power plants, both brown and black coal-fired, in terms of the cost of electricity generation, the cost of CO2 avoidance, the cooling water demand and the overall plant efficiency. The existing power plants are considered to be conventional subcritical and supercritical single reheat steam cycle based whereas the new power plant designs have allowed for ultracritical steam conditions (35 MPa, 922 K) with double reheat. The CO2 capture plants are considered to be either in service full time or in service on demand with 90% capture efficiency and the product CO2 ready for sequestration at 10 MPa and 313 K. The process and cost models for integrated power and capture plants have been obtained using ASPEN Rate-Sep, Steam-Pro, Steam-Master and PEACE software packages for process modelling and cost estimation. The results clearly show that an air cooled integrated power and capture plant has lower overall plant efficiency and slightly higher cost of electricity generation in comparison with a water cooled equivalent plant. An ultracritical single reheat power plant when integrated with capture plant that is in service full time has potential for lowest cost of electricity generation with minimum cost for CO2 avoidance. These results further show that replacing an existing turbine with a new LP turbine optimised for continuous steam extraction for CO2 plant duty minimises the adverse impact of PCC integration but the power generator looses the flexibility for electricity generation. The results also provide important insights into the major contributions to the increased cost of power generation. For both the existing and the new power plants, the amortised capital charge component dominates the cost of PCC integrated electricity generation. In spite of the large reduction in efficiency for Australian power plants when PCC is applied, it appears that reducing the capital costs of PCC will be at least equally important. This is an important outcome for the prioritization of research activities aimed at reducing the costs of capture. For example, the novel solvent development work for improved PCC technology should focus on increasing absorption rates at the same CO2 carrying capacity of the solvent to reduce the capital cost component. [Copyright &y& Elsevier]

Abstract: The oxygen requirements for oxycoal combustion in a coal-fired power station are unusual in several respects. The amount of oxygen required is large, for instance a 500  MWe power plant will require around 10,000 tonnes per day of oxygen. The oxygen purity is low and the pressure required is essentially atmospheric pressure. There is no demand for any significant quantity of co-products, such as argon or nitrogen. The parasitic nature of the power means that high efficiency is important but the large scale means that capital cost should also be minimised. These factors open up new possibilities to optimise the process cycle and machinery configuration to minimise the power consumption of the air separation unit without compromising the requirement for low cost. This paper presents the results of a study to develop Air Products’ air separation unit (ASU) offerings for oxycoal CO2 capture projects. A scalable “reference plant” concept is described to match particular sizes of power generation equipment, taking into account factors such as safety, reliability, operating flexibility, efficiency, and of course low capital cost. We describe the selection of a process cycle to exploit the low purity requirements as well as the options for compression machinery and drivers as the scale of the plant increases and the sizes of referenced equipment limit the possibilities. We also explore integration with other elements of the oxycoal system, such as preheating condensate or heating and expanding pressurised nitrogen. Finally, the advantages and disadvantages of different execution strategies for air separation unit projects are discussed, as well as alternative commercial models for the supply of oxygen. [Copyright &y& Elsevier]

Abstract: The paper presents the structure and achievements of the BIGCO2 R&D Platform, an international collaborative research project aiming at developing several enabling technologies and innovative solutions supporting a large-scale deployment of CO2 capture from power generation and underground storage of CO2. All main routes for CO2 capture are investigated, and emphasis is put on combining experimental work with theoretical analyses. The project is coordinated by SINTEF Energy Research and the budget of the current project period (2007–2011) is 16 M€. [Copyright &y& Elsevier]

Abstract: Considering the dramatic increase of greenhouse gases concentration in the atmosphere, especially carbon dioxide, reduction of these gases seems necessary to combat global warming. Fossil fuel power plants are one of the main sources of CO2 emission and several methods are under development to capture CO2 from power plants. In this paper, CO2 capture from a natural gas fired steam cycle power plant using oxy-fuel combustion technology is studied. Oxy-fuel combustion is an interesting option since CO2 concentration in the flue gas is highly increased. The Integrated Environmental Control Model (IECM) developed by Carnegie Mellon University (USA) is used to evaluate the effect of this capture technology on the plant efficiency and economic parameters of the system. The IECM uses regression models based on other studies to evaluate the required energy for oxygen production unit (air separation unit) and CO2 purification and compression unit. In this work, these two units are simulated using the Aspen Plus software in parallel with the IECM, and the results are compared with the results of the IECM. This comparison verified that the power requirement evaluations from the IECM performance model and the Aspen Plus software are approximately the same. Since CO2 capture and transport are cost and energy intensive, the cost of electricity (COE) in capture plants increases significantly. According to the assumptions in this study, the cost of electricity for both the base plant and the capture plant are calculated using the IECM cost model. The cost of electricity for the base plant is equal to 66.8 $/MWh while the cost of electricity for the capture plant is 123.7 $/MWh. In addition, cost of CO2 avoided can be calculated by using the cost of electricity and CO2 emission rate in the base and capture plants. If CO2 storage cost or CO2 benefit is not considered, the cost of CO2 avoided is about 104 $/ton CO2 for a 237 MW power plant. However, it is shown in this study that if the captured CO2 is used for Enhanced Oil Recovery (EOR) in the nearby oil fields (assuming 100 km distance), the revenue gained can compensate for the extra cost of electricity produced by the oxy-fuel combustion natural gas steam cycle and consequently reduces the cost of CO2 avoided. A rule of thumb is used to evaluate the amount of EOR revenues. According to this rule of thumb, 0.25 ton of crude oil is recovered per ton of CO2 injected. A relation between gas and oil price is therefore required to consider an integrated natural gas fired steam power plant, CO2 pipeline and oil field as an overall system. Assuming that natural gas price is a function of oil price, a rough estimation of oil price in which Carbon Capture and Storage (CCS) is economically feasible can be found. In this study, the relationship between oil and gas price is based on a polynomial function. This function is determined according to the time series information of natural gas and oil price in recent years (1997–2008) in the United States. The prices of these fuels in Iran were not used because the prices are heavily subsidized. The results show that at high oil prices, about $60/bbl, all the costs of CO2 capture and transport to oil field can be compensated by EOR revenues which makes the integrated power plant and CCS with EOR economically feasible. [Copyright &y& Elsevier]

Abstract: BIGCCS Centre is an international research centre aiming at extending and releasing the potentials for large scale deployment of CO2 capture and storage by developing new knowledge, fostering breakthrough technology and promoting innovation and future value creation at all steps along the CO2 chain. The centre is managed by SINTEF Energy Research, it involves 22 partners from industry and academia, and administers a budget amounting to 45 million € over 8 years. The paper presents the objectives of the BIGCCS Centre, outlines the research approach and strategy for promoting innovation, and presents some results after one year of operation. [Copyright &y& Elsevier]

Abstract: The UK carbon capture and storage consortium (UKCCSC) is a £2M multidisciplinary project involving academics from 15 universities and research institutes in the UK. The project has sought to improve understanding of CCS with a UK perspective in a global context. This paper outlines the broad range of activities undertaken by the consortium, including science and engineering achievements, contributions to the ongoing policy debate and capacity building. [Copyright &y& Elsevier]

Abstract: The business case for investment in power plants with CO2 capture is greatly improved if they are able to accommodate uncertainty in future market conditions and variations in local operating requirements.. This paper will outline a range of operating modes that could be important in determining the value of power plants with CO2 capture from various stakeholder perspectives. Different quantitative techniques that could provide useful insights into plant value with flexible operation are discussed and some preliminary baseline results from a deterministic simulation are reported. [Copyright &y& Elsevier]

Abstract: This paper presents a summary of technical-economic studies allowing to evaluate the production cost of electricity derived from coal and gas power plants with the capture of CO2, and the cost per ton of CO2 avoided, in the French context. Three systems were studied: an Integrated Gasification Combined Cycle (IGCC), a conventional combustion of Pulverized Coal (PC) and a Natural Gas Combined Cycle (NGCC). For the IGCC, two gasification types have been studied: a dry coal gasification at 27 bars, and a technology based on gasification of a coal - water mixture (slurry) that can be compressed to 64 bars (GE/Texaco slurry type). [Copyright &y& Elsevier]

Abstract: This paper examines dynamic operation of CO2 capture with absorption/stripping using 7 m MEA, where the absorber is operated at full capacity with the stripper at reduced load. Depending on the cost of CO2 emissions, doing so in response to variations in electricity demand could improve annual profits by $10–$100 million or more at facilities with CO2 capture. Dynamic scenarios were simulated with a controlled, constant ratio of heat rate and solvent rate. With an 80% load reduction, scenarios that turn CO2 capture off and on affect stripper performance only slightly and reach the steady state in about 90 and 18 minutes respectively. [Copyright &y& Elsevier]

Abstract: Considering the traditional coal-based energy infrastructure in the German state North Rhine-Westphalia the question arises how to face the needs of embanking climate change. To reduce greenhouse gas intensive electricity generation in the Ruhr area, the introduction of carbon capture and storage (CCS) is an option of particular relevance. The paper investigates and discusses possibilities of setting up a CCS infrastructure in NRW. It shall clarify whether, and possibly how, highly efficient conventional fossil fired power plants could be refitted with CO2 capture to flexibly react to potentially changing climate policy conditions and to keep up with the market. [Copyright &y& Elsevier]

Abstract: This paper presents strategy and structure of “ECCO–European Value Chain for CO2” project. ECCO is a new collaborating project under the 7th framework programme for research of the EU. It was initiated in 2008, with the main objective to facilitate robust strategic decision making regarding early and future implementation of CO2 value chains in the face of uncertainty. SINTEF Energy Research is coordinator of the project, which has a total budget of 5.35 M€over three years. This is the first project funded by EU having a relevance to oil and gas production through the focus on enhanced oil and gas recovery with CO2 injection (EOR/EGR). [Copyright &y& Elsevier]

Abstract: The potential impacts of climate change, recent world events, and a dramatic rise in oil prices have resulted in renewed interest in alternative transportation fuels. When considering the many options, tradeoffs exist between environmental, energy security and economic concerns. A portfolio of multiple alternatives that balances these concerns may turn out to be the most prudent. In particular, the coupling of conventional and non-conventional fossil resources with carbon sequestration and renewable biomass may mitigate greenhouse gas (GHG) emissions from fossil carbon-intensive resources, while providing economic and security benefits. To achieve this result, it is very desirable that all resources employed produce fungible fuel blending components, so that single, specificationfuels can be easily supplied. As a first step in examining the alternatives, it is necessary to establish baseline lifecycle greenhouse-gas emissions profiles for current and future alternative-transportation fuel supply-chains. JM Energy Consulting has been working with clients involved in development of alternative fuels technology to establish such baselines. This paper presents some results from these analyses, which examine both conventional and non-conventional resources for the production of jet and automotive diesel fuels. The primary focus here is on the upgrading/refining step that converts the energy resource as produced into finished distillate fuels. A bottom-up approach is taken to estimating GHG emissions using process-level data and models. This approach not only allows the carbon footprint of the various fuel chains to be distinguished, but also provides valuable insights relative to the carbon intensity of the various upgrading and refining steps required to produce specification distillate fuel blends. Resources considered here are seven classes of conventional crude oils, bitumen, shale oil, and three XtL feedstocks, natural gas, bituminous and subbituminous coal. Also briefly discussed are opportunities for co-processing of sustainable biomass resources and the capture and sequestration of CO2 generated during processing. [Copyright &y& Elsevier]

Abstract: This paper describes the reach done in the Dutch CAPTECH programme. The research aims to reduce the CO2 capture cost with 50%. In order to achieve this, a wide portfolio of future technologies is being investigated. [Copyright &y& Elsevier]

Abstract: Carbonate Looping is a promising post-combustion capture process involving the separation of CO2 from the flue gas of a coalfired power plant at high temperatures (600–700 ∘C) using the reversible exothermic CaO carbonation reaction and the endothermic calcination reaction of CaCO3. The core of the carbonate looping process is a dual fluidized bed reactor in which the CO2 acceptor material (CaO) is transported between the carbonator (CO2 absorption) and regenerator (CO2 desorption). Due to the heat requirements for the regenerator, the carbonate looping acts as a CO2 separation unit and an add-on power plant, thereby offering the opportunity for increasing the site electricity production while inflicting only a low electric efficiency penalty on the total power plant. However, the quantity and quality of the Carbonate Looping heat sources differ significantly from a conventional coal-fired power plant. This paper presents the design and simulation of the carbonate looping steam cycle for a large coal-fired plant. The simulation involves the coupling of the carbonate looping reactor model from Aspen Plus with the steam cycle in EBSILON Professional code which is a mass and energy balance cycle calculation program specifically tailored for steam cycle calculations. The resulting simulation includes penalty deduction for the Air Separation Unit and the CO2 conditioning unit, resulting in a net efficiency of 39.2% and while increasing the net power input from 1052 MWe to 1533 MWe, an addition of 481 MWe for the retrofitted power plant. [Copyright &y& Elsevier]

Abstract: Post combustion absorption technologies represent one of the most commercially ready technologies for CO2 capture. Solvent selection is the critical consideration in post-combustion absorption capture technology. In order to compare the performance of different solvents, it is necessary to perform simulations on a consistent basis and perform a process analysis of the system. The focus of this work was to develop consistent simulations for MEA and K2CO3 systems in ASPEN. The simulations have been developed within the ASPEN RateSep framework and are valid for both natural gas and coal fired power plants. This paper describes the methodology of the simulations and some results from the two systems. The MEA base case was validated with reported values in literature. Potassium carbonate was found to be particularly useful for pressurized combustion and for CO2 removal from product gases of reforming of natural gas or coal. [Copyright &y& Elsevier]

Abstract: One of the most promising options for CO2 capture in large power generation facilities is the system based on the CO2 sorption loop. This method has gained rapid importance due to promising carbonator CO2 capture efficiency, the existence of low cost sorbents and the fact that no gas pre-treatment unit is needed before entering the system. The sum of these features results in a competitively low cost CO2 capture system when using low cost natural sorbents. Different regenerable sorbents are being investigated for large-scale CO2 capture purposes and high temperature Mg-based, Li-based and Ca-based sorbents are considered as suitable candidates. This study considers the applicability of lithium orthosilicatum, hydrated limestone and raw natural limestone. A basic configuration that makes use of two interconnected circulating fluidized beds (carbonator and calciner) has been studied. Among the key variables that influence the performance of these systems, the carbonation conversion of the sorbent and the heat requirement at calciner are the most relevant. Both variables are mainly influenced by sorbent/CO2 ratio and make-up flow (purge) of solids. Purge is necessary to mitigate the sorbent deactivation. Large sorbent/CO2 ratios improve the carbonation conversion but also increase the cost of the system due to a more intensive solid circulation. Large make-up flow also improves the extent of sorption phenomena and hence the CO2 capture, but increases the heat demand at calciner and the fresh sorbent cost. The aim of this paper is to calculate the optimum make-up flow of fresh sorbent and sorbent/CO2 ratio for a set of these regenerable sorbents in order to minimize the capture cost of the system integrated into a power plant. Resulting optimal values are compared to assess the energetic performance and CO2 capture cost of the cycle for each sorbent material. [Copyright &y& Elsevier]

Abstract: A series of different amines was immobilized on a silica support by grafting or impregnation and tested for CO2 adsorption in simulated flue gases. This paper compares the adsorption isotherms and the cyclic adsorption capacities of these materials. Furthermore, we estimate the diffusion rate of CO2 from simulations of the breakthrough curves and discuss some aspects of the design of a potential adsorption process for CO2 capture. [Copyright &y& Elsevier]

Abstract: The retrofitting of existing coal-fired power plants with a carbon dioxide capture offers a promising opportunity to achieve the global target reduction in CO2 emissions. This paper deals with the integration of an amine-based flue gas scrubber with a coal-fired power plant including compression of CO2 and the resulting effects of the integration on the power plant’s operation. [Copyright &y& Elsevier]

Abstract: In the plant configuration discussed in this paper, CO2 rich flue gas from an air fired coal boiler is contacted with CaO in a fluidized bed reactor (carbonator) generating CaCO3 and capturing more than 90% of the CO2 generated. Sorbent is regenerated in a second fluidized bed (calciner) via oxyfuel combustion of coal, generating a CO2 rich stream ready for compression and sequestration. Kunii–Levenspiel model, together with correlations for the estimation of sorbent performance after a number of carbonation–calcination cycles were used, in order to estimate carbonator dimensions and pressure losses. A net LHV efficiency of 37.4% was predicted for the selected reference case, with 97% of CO2 captured. As a comparison, for full oxy-combustion and amine based plants, net efficiency of 36.3% and 32.6% were obtained respectively. [Copyright &y& Elsevier]

Abstract: Post combustion CO2 capture with chemical solvents is performed in packed columns operating in the counter current mode. Good predictions of the pressure drop and of the mass transfer characteristics is critical for their design. Many experimental works are dedicated to characterization of packings. However, experiments are carried out at a laboratory intermediate scale, with almost no possibility to bring information neither at small scale nor at very large scale. It is shown in this paper how CFD, via an original multi scale approach from the liquid film thickness to the industrial column dimensions, can help in complementing experimental data. [Copyright &y& Elsevier]