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Abstract: Carbon capture and storage (CCS) has been identified as a critical enabling technology to mitigate the large quantities of carbon dioxide (CO2) emitted from coal-fired power plants and subsequently discharged to the atmosphere. While large-scale CO2 injection in geologic formations associated with enhanced oil recovery operations have been ongoing for over 30 years, different technical challenges face the injection of CO2 into saline reservoirs sourced from utility boilers. Beyond the high costs of capture, operational reliability related to the integration of capture with pipeline transport and injections are components of CCS with very little operational experience. Some issues unique to utility boiler capture include planned and forced outages, generation loading, and changes in CO2 purity. These operational issues can only be resolved through the integration of capture, transportation, and injection operations in demonstration-scale projects. Parametric testing provides an opportunity to evaluate how the integration of transportation and injection for storage respond to changes in plant operations. This paper will introduce a CCS demonstration-scale research program that involves a carbon capture unit designed to supply up to 500 metric tons (tonnes) per day (182,500 tonnes per year), a 19-kilometer pipeline and injection into a subsurface saline reservoir located at 3,060 meters below ground surface. The project will provide a test bed to begin to understand and resolve the challenges of integrating the key components of CCS with utility boilers. The paper will provide an update on the status of the project, covering the permits required to get the demonstration in motion, the geologic assessment of the proposed injection target reservoirs, and the engineering design for the injection and monitoring program. [Copyright &y& Elsevier]

Abstract: Most projected climate change mitigation strategies will require a significant expansion of CO2 Capture and Sequestration (CCS) in the next two decades. Four major categories of challenges are being actively researched: CO2 capture cost, geological sequestration safety, legal and regulatory barriers, and public acceptance. Herein we propose an additional major challenge category across all CCS operations: Water management. For example a coal-fired power plant retrofitted for CCS requires twice as much cooling water as the original plant. This increased demand may be accommodated by brine extraction and treatment, which would concurrently function as large-scale pressure management and a potential source of freshwater. At present the interactions among freshwater extraction, CO2 injection, and brine management are being considered too narrowly -in the case of freshwater almost completely overlooked- in the technical and regulatory CCS community. This paper presents an overview of each of these challenges and potential integration opportunities. Active management of CCS operations through an integrated approach -including brine production, treatment, use for cooling, and partial reinjection- can address challenges simultaneously with several synergistic advantages. The paper also considers the related potential impacts of pore space competition (with future groundwater use, gas storage and shale gas) on CCS expansion. Freshwater and brine must become key decision making inputs throughout CCS operations, building on existing successful industrial-scale integrations. [Copyright &y& Elsevier]

Abstract: The Netherlands is both heavily dependent on the success of carbon capture and storage (CCS) and renewable electricity for its decarbonisation policy. The same holds for the EU and some of its Member States like the United Kingdom. This paper discusses several scenarios for the Netherlands within the context of a liberalised and a more and more connected energy market in Northwest-Europe. The research reported here shows that CCS on new coal fired power plants does not pose a threat to the increase in the electricity production by large quantities of wind energy in the electricity system, and vice versa. For renewable energy, several additional policies are in place mainly in the form of financial support as long as these renewable options are not yet profitable. For CCS, financial support is only granted now for a selection of the first demonstration projects now planned in the EU. It is not yet clear if large scale CCS and high shares of wind energy can be incorporated in a balanced way in the electricity system. This paper shows that from a technical and economic point of view, there is room for both, and under which conditions such a two fold growth will be feasible. [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: ZeroGen Pty Ltd (ZeroGen) recently announced its plan to develop the world’s first commercial-scale 450MW clean coal power plant by 2017 in Queensland, Australia. Since the Queensland Government first announced the project in early 2006, stakeholder engagement activities have been a key priority for ZeroGen. The company understands that stakeholder perceptions, particularly of the safety of carbon dioxide (CO2) capture and storage (CCS) processes, represent a key challenge to the commercialisation of clean coal technologies. As a result, ZeroGen has developed and implemented an advanced consultation framework to actively engage a wide range of stakeholders to address this challenge. This paper details the consultation framework and outlines the findings of research conducted to assess the perceptions of community leaders where the project’s CCS activities are occurring. The paper confirms that the consultation processes deployed by ZeroGen to date have been successful in overcoming a key challenge to the commercialisation of clean coal technologies involving CCS. [Copyright &y& Elsevier]

Abstract: Over the past few years, several pieces of legislation have been introduced in Congress aimed at reducing US greenhouse (GHG) emissions by setting emission targets by specified years. One of the latest bills, America’s Climate Security Act of 2007 (S.2191) was introduced in October 2007 and sets a US GHG emissions target for 2050 that is 85% below the governments business-as-usual forecast. DOE/NETL has employed a multi-sector emissions accounting tool, CarBen, that identifies emission abatement options and their contribution, via a wedge analysis, to the total GHG emissions reduction needed to meet the 2050 emissions target laid out in S.2191. This paper begins with a review of expected greenhouse (GHG) emissions in the United States through 2050. Historical and projected trends in U.S. energy use per GDP and GHG emission per unit of energy delivered are assessed. The paper then explores “technical possibilities” that exist for the U.S. to mitigate its GHG emissions in line with S.2191. Within the power sector, these options include nuclear power, renewable power generation, refurbishing existing coal power plants, retrofitting existing coal power plants with carbon capture and storage (CCS) and deploying new coal and natural gas power plants with CCS Outside of the power sector abatement options cover non-CO2 GHG emissions abatement, terrestrial offsets, international credits, improved vehicle efficiency and electrification of the transportation sector through hybrid electric vehicles. The methodology for calculating the wedges and allocating emissions reduction among the different options is described. [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: This paper presents the results of ASPEN simulations of a carbon-dioxide (CO2) removal and recovery plant that captures CO2 from a 500 MWe (net) conventional coal-fired power plant flue gas stream. At a constant CO2 recovery rate of 86.5% by weight, the performance of aqueous ammonia solution as an alternative to various aqueous amino solvents (MEA, AMP and MDEA) is compared in terms of the process scenarios, solvent loadings and overall energy consumption. The overall mass transfer co-efficient and CO2 loading data generated for aqueous ammonia solutions using a laboratory scale wetted wall gas-liquid contactor are also presented. The ASPEN simulation results in conjunction with the laboratory data show, that capturing CO2 from coal-fired power plant flue gas, using aqueous ammonia solvent, will require ammonia concentration no more than 5% by weight and absorber temperature 10 ∘C or lower, if the vapor phase ammonia losses are to be contained and the precipitation of ammonium bi-carbonate in the absorber is to be avoided. Under such an operating scenario, the aqueous ammonia based CO2 capture process has overall energy requirement comparable to the conventional 30% by weight aqueous MEA based process. The ASPEN results further show that 30% by weight AMP based process has the lowest overall energy requirement among the solvents considered in this paper. [Copyright &y& Elsevier]

Abstract: Aqueous ammonia can be used to capture CO2 from flue gas of coal-fired power plant with quick reaction rate, high removal efficiency, and high loading capacity of CO2. It is thought to be a promising technology. However, the CO2 absorption rate, diffusion rate and VLE (Vapor liquid equilibrium) in aqueous ammonia have still been rarely researched. More research is necessary for these characters of ammonia solution as CO2 absorbent. The paper will focus on the fundamental characteristics of CO2 in aqueous ammonia. A series of tests were conducted in a semi-batch reactor that has been developed in this paper. CO2 removal efficiencies at different concentrations of aqueous ammonia have been studied in the similar operation conditions to compare their basic characters in the CO2 absorption process. And a small wetted wall column (WWC) with a contact area of about 41.45 cm2 was also built for the study of the absorption rate, diffusion, and solubility of carbon dioxide in the aqueous solution. In the paper, reaction rate and overall gas transfer coefficient were studied. The concentration of ammonia ranges from 1, 5, 10 to 15. CO2 and N2 are used to simulate the flue gas. The concentration of CO2 ranges from 5, 10, 15, to 20%. The reaction temperatures are 20 ∘C and 40 ∘C. It is indicated in this paper that the best concentration of aqueous ammonia should be selected from 5% to10%. And aqueous ammonia has a high Flux in WWC, which is three times higher than that of MDEA+PZ, under the same condition. It is also found that is appropriate to be used in the mass transfer process of the carbon dioxide absorption by aqueous ammonia. Alls of these experiments established foundation for the further study of CO2 removal by ammonia. [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: Safe candidate sites of reservoir for geologic storage including some oil or gas bearing structures on-shore or off-shore of the Taiwan island, and some near off-shore sedimentary basins were studied and screened. After screening out several potential engineering sites, an AHP ranking method was applied for ranking and selecting the preferred candidate on account of the economy factors, safety requirements, storage effectiveness, and potential storage capacity volume etc. As a result, preferred engineering site for pilot and demonstration plans were recommended. A deep saline aquifer under a Miocene basin near the western coast of Central Taiwan with estimated storage capacity up to 4 Gt- CO2 is now regarded as a very high potential storage reservoir with advantages of its high capacity volume, geological stability and the short distance away from the largest emission plants. More detailed investigation will be implemented during the year of 2010 to 2013 including works of site conformation, characterization prior to performing a pilot test with injection depth down to 2500 ∼3000 m. In this paper, the process and methodology of the screening potential reservoir and ranking of preferred engineering site are depicted and furthermore the tentative road map concerning Tai-Power’s CCS technology development for coal- fired power plant is introduced. [Copyright &y& Elsevier]

Abstract: This paper describes an investigation for multi-stage systems used in coal-fired power plant. The whole work was divided into two steps: energetic and economic analyses. In the first step: on the basis of a serial concept, through varying the position of compressors and vacuum pumps, recycling the retentate of the 2nd membrane to the feed side of the 1st membrane, a cascade variant was developed and analysed. In the second step: an economic model was developed to calculate the capture cost of the cascade system. The total cost is composed of investment cost, operation and maintenance (O&M) cost and electricity cost. A correlation between the membrane parameters: selectivity & permeability and capture performance: energy consumption & capture cost was built up. Using Polyactive® membrane developed by GKSS with CO2 permeance of 3 Nm3/m2hbar and CO2/N2 selectivity of 50, under the separation target of 70% degree of CO2 separation and 95 mol% CO2 purity, adopting the cascade membrane system in the 600 MW NRW-reference power plant, the specific energy consumption including CO2 compression (110 bar, 30 °C) is 256 kWh/tseparatedCO2 with 6.4%-pts efficiency loss. The capture cost is 31 euro/tseparatedCO2 , which could be a promising solution as a retrofit for the existing power plants. [Copyright &y& Elsevier]

Abstract: This paper presents steady state and dynamic modelling of post combustion CO2 capture using 30 wt% MEA integrated with models of CO2 compression and the steam power cycle. It uses multivariable optimization tools to maximize hourly profit of a 100 MWe coal-fired power plant. Steady state optimization for design provided optimum lean loading and CO2 removal as a function of price ratio (CO2 price/electricity price). The results indicated that for price ratio between 2.1 and 7, the plant should be designed at removal between 70% and 98% and lean loading in the range of 0.22–0.25. Dynamic optimization determined the operation of the capture system in response to two partial load scenarios (reboiler steam load reduction and power plant boiler load reduction) and provided optimum set points for steam rate, solvent circulation rate and stripper pressure control loops. Maximum profit is maintained by allowing the stripper pressure to drop and implementing a ratio control between solvent and steam rate (and flue gas rate for partial boiler load operation). [Copyright &y& Elsevier]

Abstract: Significant quantities of water are utilized in thermoelectric power plants, mostly for the purpose of cooling. Water is becoming critically important for low carbon power generation. To reduce greenhouse gas emissions from pulverized coal (PC) power plants, post-combustion carbon capture systems are receiving considerable attention. However, current systems require a significant amount of cooling, which puts further pressure on cooling water resource. This paper quantifies cooling water use and evaluates technical and economic effects of carbon capture on cooling systems at PC power plants. Included are recirculating systems with wet cooling towers and air-cooled condensers (ACCs) for dry cooling. For a wet cooling tower, water has to be provided to make up losses due mainly to evaporation and blowdown. Adding an amine-based carbon capture system to the plant would approximately double water use. When air-cooled condensers (ACCs) are used as the dry cooling system, in spite of the advantage in reducing water usage, the dry cooling system has a much larger capital cost than the wet cooling system, depending strongly on specific site and system characteristics. [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: In this paper we analyze the relative importance and mutual behavior of two competing base-load electricity generation options that each are capable of contributing significantly to the abatement of global CO2 emissions: Nuclear energy and coal-based power production complemented with CO2 capture and storage (CCS). We also investigate how, in scenarios developed with an integrated assessment model that simulates the economics of a climate-constrained world, the prospects for nuclear energy would change if exogenous limitations on the spread of nuclear technology were relaxed. Using the climate change economics model WITCH we find that until 2050 the growth rates of nuclear electricity generation capacity would become comparable to historical rates observed during the 1980s. Given that nuclear energy continues to face serious challenges and contention, we inspect how extensive the improvements of coal-based power equipped with CCS technology would need to be if our economic optimization model is to significantly scale down the construction of new nuclear power plants. [Copyright &y& Elsevier]

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: The performance of post-combustion CO2 capture processes depends on the applied solvent as well as on the chosen process configuration and the integration concept with the power plant. Siemens bases its development efforts on an amino-acid salt solution as solvent, which has a negligible environmental impact and provides favourable properties for a low-energy capture process. The solvent features a high chemical and thermal stability and is easy to handle. The capture process is characterized by near-zero emissions. As a first step for validation of the determined solvent and process features on an industrial scale, the implementation of the capture process in a pilot plant is required. For this purpose, Siemens has installed a pilot plant at E.ON’s coal-fired power plant Staudinger in Germany and started the operation in August 2009. The measured pilot plant process data are used to validate the computational process model, which refines the model accuracy and improves the reliability in terms of plant performance. The findings from pilot plant operation confirmed that an overall net plant efficiency penalty of less than six percentage points (without CO2 compression) for a state-of-the-art coal-fired steam power plant can be achieved. The paper also presents experiences from pilot plant measuring campaigns with regard to the impact of trace components such as SOx and NOx. Solvent losses due to related degradation effects can be minimized by an intelligent reclaiming concept. Loss due to oxygen degradation can be estimated to be less than one percent of hold-up per year. Suitable construction materials have been qualified. The results of the pilot plant operation will serve as basis for the implementation of a demonstration plant, which will be the final step before a full-scale commercial carbon capture plant project. Siemens has been selected as technology provider for the Meri-Pori Carbon Capture and Storage project in Finland, which is a potential funding candidate of the European Flagship Programme. The Meri-Pori power plant has an installed capacity of 565 MW and the capture demonstration project is supposed to treat half of the power plant’s flue gas and to capture 90% CO2 from the treated flue gas. In addition to the Siemens capture process, the demonstration project will include ship transportation and geological storage. [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: To fulfill the energy demand now and in the next decades, coal-fired power plants will be an essential part of the portfolio of power plants that supply electricity cheaply and in a reliable way. The specific CO2 emissions of these plants can be reduced by increasing the efficiency. For that reason KEMA did optimize the steam water cycle of ultra super critical (USC) coal-fired power plants within the EOS program. The improvements are based on the application of the so-called Master Cycle, and on the application of higher steam temperatures. In the Master Cycle cold reheat steam is used in an extra turbine and with steam extraction of this turbine feed water preheating is realized with reduced exergy losses. The turbine is called a tuning turbine reflecting the improved possibilities to tune and optimize the steam cycle with the new coupling where the regenerative heater train and the re-heaters have been decoupled. The Master Cycle is proposed by Dong Energy . The first approach deals with the USC technology with a steam temperature of 600 °C and reheat temperatures of 620 °C. This technology is available at the moment and is applied in new built coal-fired power plants. The second approach deals with the USC technology with a steam temperature of 700 °C and reheat temperature of 720 °C. The expectation is that this technology can be applied around 2025 with the same availability as the USC units with 600 °C. The thermodynamic analyzes are carried out with KEMA’s flow sheeting package SPENCE®. In all considered cases the thermal input was 2400 MWth. In case of the application of the Master Cycle a second reheat is introduced. Results will be discussed and presented in tables, t-s diagrams and h-p diagrams. Improvement of efficiency of coal fired power station technology can reduce the amount of CO2 emitted significantly. This paper shows that with current available technology and improvements an additional emission reduction of almost 10% can be realised by applying the USC 700 + MC. Compared to the world wide average an emission reduction of 66% can be achieved without CCS. In the continuation of the analysis post combustion technology will be integrated in the concept to analyze possible additional benefits of the master cycle with respect to steam supply for the regeneration of the solvents. [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: The COACH project (Cooperation Action Within CCS China-EU 1 [1] EC/FP6 Contract #038966, co-ordinated by F. Kalaydjian, IFP Energies nouvelles, France. ) was launched on November 1st 2006 for a period of 3 years, as part of the 6th framework programme of the European Commission 2 [2] The French Agency for Development (AFD) is gratefully acknowledged for its financial support to the dissemination, knowledge sharing and capacity building activities developed in COACH. . Gathering 20 partners comprising 8 Chinese partners and 12 European partners, the COACH project was conceived as contributing to the first phase of the Near Zero Emission Coal fired power plants (NZEC) programme, a 3-phase programme developed between the European Union and China, aiming at combating climate change by enabling the deployment in China of thermal power plants equipped with capture and storage (CCS) facilities. The objective of the COACH project was to establish the basis for the large-scale use of coal for polygeneration in China with pre-combustion capture, transport and geological storage of CO2. Main efforts were place on a future CCS demonstration operated on an Integrated Gasification Combined Cycle (IGCC) thermal power plant fully equipped for converting and splitting the produced syngas into a hydrogen-rich fuel gas and CO2, and with a subsequent storage of CO2 in either mature hydrocarbon reservoirs (Dagang or Shengli oil provinces), deep saline formations or unmineable coal seams. Focus was made on the emission sources and storage sites located in the part of the Bohai Basin in the Shandong Province. The paper will present the main outcomes of the project as follows : [•] Structuring the China-EU COACH venture: In order to enabling the sharing of knowledge between European and Chinese COACH partners and building capacity a survey of CCS activities was performed, workshops were organised in EU and China, a cooperative website was created and two one-week long CCS schools were organised in China gathering more than 100 students 2/3 thereof coming from China and the remaining from Europe; [•] Technical actions and challenges relating to CCS, gasification and polygeneration: A generic IGCC concept implemented with CO2 capture was defined and compared against a plain IGCC based on the GreenGen Phase I system without CO2 capture. A detailed analysis of technologies needed for implementing an option for CO2 capture in an IGCC process with provision for production of electricity and methanol was carried out as well as a cost analysis of both CO2 capture and transport; [•] Geological assessment and storage sites mapping: A quantitative assessment of the potential storage sites (the Dagang and Shengli oil provinces, the deep saline aquifers nearby and the Kailuan coal mining area) was performed along with a mapping of the possible transport infrastructure (by pipelines or ships) that could be developed to connect CO2 sources to CO2 sites; with regards to storage capacity, the main capacity was found to reside in the deep saline aquifers (several giga tonnes) but would require further geological investigation for delivering definite values. The storage potential in oil fields was found to be much smaller (less than one giga tonne) but could provide opportunities for enhanced oil recovery. Finally, the coals of Kailuan mining area exhibit a high ability to adsorb CO2 and provide enhanced coalbed methane recovery, but their injectivity remains to be verified. [•] Case studies and recommendations for CCS demonstration in China: By integrating results obtained in the previous tasks dealing with CO2 capture and CO2 storage, two scenarios (one small scale–from 0.1 to 1 million tonnes of CO2 per year, one large scale–2 to 3 million tonnes of CO2 per year) were designed to screen options for a possible CCS demonstration project. These alternative CO2 streams are both considered captured from the GreenGen IGCC power plant in Tianjin and transported to one or more geological formations in the Bohai Bay geological basin for permanent disposal. Storage for the smaller scale scenario could be accommodated in the Dagang or Shengli oilfields. Storage for the larger scale scenario (2–3 million tonnes a year) could be accommodated in the Shengli oilfield province (in a number of fields) or potentially in the saline formations that can be found in the Huimin sub-basin area. For each of these options, a preliminary risk assessment was performed. A thorough cost analysis was performed. Policy and regulation issues pertaining to a shift towards CCS in China. The 3-year targeted cooperative actions under the COACH project have mobilised capacities in China and Europe and paved the ground for subsequent CCS demonstrations in China. The next phase of the China-EU NZEC programme should start in 2010 and deliver FEED studies which should allow starting operating a CCS demonstration in China by 2015. [Copyright &y& Elsevier]

Abstract: Using a power generation dispatch model of the Electric Reliability Council of Texas (ERCOT) to estimate CO2 capture from retrofitting an existing coal power plant, this paper estimates the system cost and revenue associated with handling CO2 input and output mismatch in an integrated source-sink pipeline by installing more injection wells into a saline reservoir to handle peak CO2 capture rates. The fluctuations in CO2 capture (e.g. supply) are assumed to come from an existing coal-fired power plant in Texas operating according to a merit-order dispatch model with an imposed CO2 price. We analyze a 20-year cash flow with CO2 demand for enhanced oil recovery (EOR) based upon a nominal purchase schedule over an 11-year lifespan of a high-quality candidate oil field, Conroe, along the Gulf Coast of Texas. With an assumed structured and inflexible use of CO2 for EOR, the deeper saline reservoir can sequester captured CO2 that is not injected for EOR. By performing a cash flow analysis with and without the EOR field and saline reservoirs included, the economic costs and benefits of coupling EOR and saline storage to a single coal generator are determined for a specific Texas case study. At low CO2 prices, the EOR reservoir contributes more value than the saline reservoir, but the opposite is true at high CO2 prices. This answer can be partly explained because as CO2 price increases, the analysis assumes constant demand of electricity and endogenously increases electricity prices but uses an exogenous constant oil price. The method can be generalized to include additional coal-based plants as well as EOR and saline reservoirs in Texas to envision an entire carbon capture and sequestration network in a region with high EOR potential. [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: In this paper, we evaluate alternate commercial structures for an integrated CCS-EOR project where the source of CO2 is a coal-fired power plant, and the CO2 is transported via a dedicated pipeline to an oil field where the CO2 is injected for EOR. We evaluate alternative contract types that link the involved entities in light of exogenous market risks, such as the fluctuating price of oil recovered. The choice of the contract type determines who would bear the risks along the value chain, and the incentives that the risk allocation produces fixes the total project value. We see that the fixed price contracts have weaknesses in terms of ex-post insolvencies and poor incentive structures that result in a sub-optimal decision-making by the involved entities. The risk-sharing offered by the indexed price contracts reduces the likelihood of ex-post insolvency and provides incentives to each entity to optimize the total project value. [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: 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: The use of water is a critical aspect in the design, engineering and operation of any fossil-fuel-fired power plant and it is an important element in any environmental assessment and life cycle analysis. A large amount of water is needed to generate electricity from any fossil-fuel-fired power plant. This paper summarizes the results of a study carried out by Foster Wheeler for the IEA Greenhouse Gas R&D Programme (IEA GHG) with the purpose of evaluating the water usage in plants with and without CO2 capture. The study focuses on the techno-economic evaluation of five different alternatives establishing, for each of them, the water usage and the possibility of reducing the water consumption in areas where availability of water could be limited. The study evaluates several alternative bituminous-coal-fired power plant configurations based on the following technologies: [•] Pulverised coal-fired power plant with ultrasupercritical steam cycle (USC-PC); [•] Pulverised coal-fired power plant with ultrasupercritical steam cycle using oxyfuel combustion; [•] IGCC using GEE quench-type gasifier. All cases are evaluated without and with capture of the CO2. The CO2 capture rate is assumed to be at least 85% of the total CO2 emissions. In all cases the plant is located in an area where water supply could be severely limited and therefore special attention is paid to any possibility of reducing the water usage and consumption. Reference plants located in areas without water limitations, used as a basis for this study, are taken from reports already issued by IEA GHG R&D Programme, assessing the performance of power plants with and without CO2 capture. Some of the reference reports have been developed by Foster Wheeler and some by other engineering companies. The following study objectives are pursued: [•] To establish a rigorous accounting of water usage throughout the different power plants and compare water usage in power plants with and without CO2 capture, providing a breakdown of water consumption for each case. [•] To establish an acceptable methodology that can be used to compare water usage in power plants and provide a baseline set of cases and water loss data for assessing potential improvements and evaluating R&D programs. [•] To evaluate water usage and loss of power plants using oxyfuel, pre- or post combustion CO2 capture technologies. [•] To assess and evaluate the performance, the costs and the potential impact on the water usage of power plants with CO2 capture located in areas where water supply could be severely limited. The performance of the power plants is estimated based on the power plants that could be ordered today, including all the features needed to reduce the water consumption (e.g. maximization of air cooling, recycle of treated water to the process up to a zero discharge plant, etc). [Copyright &y& Elsevier]

Abstract: While CCS is demonstrated globally utilities will face a period with fast learning curves for capture technologies. Technology and cost uncertainty is a topic of particular concern for first-movers. For post-combustion capture plants, costs are expected to decrease in the future and improved solvents are likely to become commercially available after the first CCS plants have started operating. Given that power generation assets are usually paid back over extensive periods of time it is important that, in this context, the first generation of plants and any capture-ready plants can be future-proofed to incorporate future technological improvements. This paper presents selected results from a forthcoming report commissioned by the IEAGHG. A methodology based on a sensitivity analysis of solvent properties is used to identify pieces of equipment, which contribute to locking-in performance with capture. Finally, some principles for analysing power plant economics with improved solvents and assessing the potential financial benefits in competitive electricity market of mitigating these technology risks are examined. [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: Making best use of existing assets is a high priority for industry, particularly when significant capital expenditure would be required to construct replacement capacity to meet continued demand if they were taken out of service. In this context, the potential to retrofit carbon dioxide (CO2) capture to existing power plants so that they can continue to operate in plausible future scenarios where significant cuts in CO2 emissions are required from the electricity sector has become an increasingly ‘hot topic’. One potentially important characteristic of retrofitted plants that is typically over-looked in assessments of CO2 capture retrofit is that they are likely to have ‘built-in flexibility’. For example, for plants that retrofit post-combustion capture without any significant changes to the power cycle (i.e. that do not undertake a boiler/turbine retrofit at the time as adding capture), it should be technically feasible for the plant to avoid the majority of the efficiency penalty associated with operating CO2 capture by temporarily bypassing the capture unit. The low pressure steam turbine, condenser and generator will be sized so that they are able to use the steam that is diverted away from the CO2 capture unit for power generation without any additional expenditure, since this steam was included in the design flow before capture was fitted. This paper and a related PhD thesis contributes to developing understanding of the potential value of built-in flexibility of coal-fired power plants retrofitted with post-combustion capture and potential enhancements associated with temporary storage of rich solvent. This analysis is important to inform investment and policy decisions and brings together engineering and economic assessment. Thus, it is able to draw robust conclusions that are relevant in determining both priorities for future technical design work and decisions about which modes of operating flexibility may be sufficiently valuable to warrant further analysis within investment appraisal or policy-making related to retrofitting post-combustion capture to pulverised coal plants. [Copyright &y& Elsevier]

Abstract: This paper provides a financial analysis for new supercritical pulverized coal plants with carbon capture and sequestration (CCS) that compares the effects of two relevant climate policies. First, an updated cost estimate is presented for new supercritical pulverized coal plants, both with and without CCS. The capital cost escalation of recent years can be attributed to rising materials, plant supply, and plant contractor constraints. This estimate is then compared with recent estimates from public sources. Second, several current and proposed public policies relevant to CCS are presented. Finally, a financial analysis is performed to evaluate the effectiveness of two likely US carbon regulations on deploying Nth-plant CCS technology. The major conclusion is that the leading US carbon cap-and-trade bills will likely not be sufficient to deploy CCS technology in a manner consistent with a 550 ppm CO2 stabilization scenario. A more aggressive carbon policy including CCS research, development, and demonstration must be considered to achieve this goal with significant CCS deployment. [Copyright &y& Elsevier]

Abstract: China has built at least 70 GW of new coal- fired power installed capacity annually since 2005 and the growth is expected to continue (CEC, 2008). Chinese government, industry and academic stakeholders perceive that China will not mandate new plants to be built with carbon dioxide capture and storage systems in the short term and there is little incentive even to contemplate the first steps needed to fit plants with capture equipment [Reiner, D., Liang, X., Sun, X., Zhu, Y., Li, D., 2007. Stakeholder attitudes towards carbon dioxide capture and storage technologies in China, International Climate Change Conference, Hong Kong, May 29–31 2007]. We investigate the value of making new plants CO2 Capture Ready (CCR), which would enable them to retrofit to capture CO2 without unnecessary additional costs when the appropriate policy and /or economic drivers are in place (IEA, 2007). In order to understand the value and investment characteristics of CCR in China, a typical 600 MW pulverized-coal -fired ultra-supercritical power plant, locating at Guangdong province, was examined. Combined with a detailed engineering assessment, we obtained the costs for different CCR scenarios. To analyze CCR investment opportunities, we apply a cash flow model for valuing Capture Options, as developed in [Liang, X., Reiner, D., Gibbins J., Li J., 2007. Fianncing CCR coal-fired power plants in China by issuing capture options, EPRG Working Paper Series, EPRG0728, Cambridge, December. Available at: www.electricitypolicy.org.uk/pubs/wp/eprg0728.pdf]. Results are obtained by Monte-Carlo simulation, based on engineering surveys and the IEA (2007) CCR study, as well as plant performance information and expert projections on carbon prices, coal prices and electricity prices. CCR investments are justified by factors such as higher retrofitting probabilities, lower early-closure probabilities and fair economic return. However, the economic case for CCR largely depends on the type of investments made, for example, CCR-essential investments tend to be more economic than additional non-essential CCR features such as CCR Essential with clutched low-pressure turbines. Carbon price, coal price and discount rate also were found to have significant impacts on the economics of CCR. Overall, it appears that the value of capture options are significant, and therefore clear retrofitting strategies would be valuable for any CCR investment. [Copyright &y& Elsevier]

Abstract: Plug-in hybrid electric vehicles (PHEVs) have the potential to be an economic means of reducing direct (or tailpipe) carbon dioxide (CO2) emissions from the transportation sector. However, without a climate policy that places a limit on CO2 emissions from the electric generation sector, the net impact of widespread deployment of PHEVs on overall US CO2 emissions is not as clear. A comprehensive analysis must consider jointly the transportation and electricity sectors, along with feedbacks to the rest of the energy system. In this paper, we use the Pacific Northwest National Laboratory MiniCAM model to perform an integrated economic analysis of the penetration of PHEVs and the resulting impact on total US CO2 emissions. Under the assumptions used in this analysis where PHEVs obtain 50–60% of the market for passenger and light-duty trucks, the ability to deploy PHEVs under the two climate policies modeled here results in 6000–7300 Mt CO2 of additional cost -effective emissions reductions from the US economy over the period 2005–2050. The additional demand for geologic CO2 storage created by the introduction of the PHEVs is approximately equal to the cumulative geologic CO2 storage demanded by two to three large 1000 MW IGCC+CCS power plants over a 50 -year period. The introduction of PHEVs into the US transportation sector, coupled with climate policies such as those examined here, can also reduce US demand for oil by 20–30% by 2050 compared to today’s levels. [Copyright &y& Elsevier]

Abstract: Coal is China’s primary fuel for power generation and will almost certainly remain so for the foreseeable future. China had an installed power generation capacity of a little over 700GWe in 2007, which is projected to nearly double within the next 20 years. NZEC (Near Zero Emission Coal) is a major Sino-British initiative on carbon capture and storage. One of its key aims is to complete the work required to construct a coal-fired power generation plant in China with CCS. The first phase of NZEC is a feasibility study, due to complete in late 2009, in which options for CCS in China are being explored. As part of the feasibility study, an energy systems analysis using the China MARKAL model is being undertaken to provide a perspective on the energy technologies that may be deployed in China to meet its energy needs. The energy situation in China is being analysed, with a detailed investigation undertaken of the various technologies and fuels employed at present. Based on growth forecasts and national plans for China, predictions will be made of the technologies and fuels that may be deployed to meet its future needs. The role of coal and the various technology options for utilising that coal will be identified. An estimate of the CO2 emissions arising from the utilisation of coal and the potential impact of their release to the atmosphere will be made. The potential for CCS to reduce CO2 emissions to the atmosphere, and the cost and impact of deploying CCS will be examined. In this paper, the authors will provide a progress review of this analysis and present provisional results. [Copyright &y& Elsevier]

Abstract: Reducing the energy and cost penalties is the critical problem of CO2 abatement. In this paper, through analyzing the effect of system integrating charact eristic of polygeneration system on system thermo -economic performance, the interaction between economic performance and thermodynamic performance is disclosed. And based on the analysis of the components of CO2 avoidance cost, the essence of lower cost penalty for CO2 avoidance in the polygeneration system is revealed. Through sys tem integration, the polygeneration system ca realize the n energy couple between the chemical island and power island, and simultaneously realize the trade-off between the insta lled capital cost and the primary energy saving, which result in very low cost p enalty for CO2 avoidance, 2.7 $/t - CO2, in which the reduction of energy penalty for CO2 avoidance plays the critical role. Furthermore, through analyzing the sensitivity of the cost of CO2 avoidance to the capital cost and fuel cost in the polygeneration system, the results show that it is more sensitive to the capital cost, and then reducing the manufacture cost of equipment is an efficient way to reduce the cost penalty of CO2 avoidance. [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 presents a study of two integrated processes for power production with CO2 capture : a post-combustion process involving an amine based CO2 capture unit; and an oxyfuel process involving air separation units, O2 combustion boiler and flue gas purification. These two integrated processes have been compared to a base case air-fired CFB boiler using bituminous international coal as fuel. A complete techno-economical study has been carried out, and electricity production costs have been compared to the base case. The results were also expressed in equivalent CO2 penalties (€/ tco2) as an economic limit to allow CCS processes to be economical against CO2 taxes. It has been found out that both zero emissions post-combustion and oxyfuel integrated process have a big impact on the power plant economics. The study showed oxy- and post-combustion processes led to similar CO2 penalty: around 44€/ tco2 for postcombustion capture and 46€/tco2 for the oxyfuel process. [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: 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: Residual SO2 accumulates as sulfate in aqueous amine used for CO2 capture from coal-fired power plants. This paper reports research results on a new process to remove this sulfate by crystallization of K2SO4. The K2SO4 solubility in CO2 loaded aqueous amine solutions was measured and correlated with an empirical relationship and with the electrolyte-NRTL model in AspenPlus®. The volume median particle size of K2SO4 by continuous crystallization ranges from 90 to 340 m. A case study of the new reclaiming process was done in AspenPlus®and the total estimated cost to remove sulfate is about $ 1.1/ton CO2. [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 capture of CO2 is a key technology for the reduction of greenhouse gas emissions from Australian coal fired power stations. It is an emerging technology, which still faces significant challenges in scaling up to full commercial scale suitable for power station applications. To increase adoption by the power industry significant cost reductions in capital and operating cost must be realised. CSIRO has developed an integrated post-combustion capture R&D and pilot plant program aimed at bringing down the barriers for commercial deployment. This paper provides an overview of the program and its status. [Copyright &y& Elsevier]

Abstract: Among the technologies that are under study for CO2 capture from flue gas, the separation process using monoethanolamine (MEA) could be the first to be available for immediate industrial applications in the next few years. The principles of CO2 separation using alkanolamines were discovered nearly a century ago. The process has been applied successfully for several decades in areas such as natural gas processing or coal gasification. The application to flue gas treatment was introduced in the early 1980s, but was not widespread. In such industrial processes, corrosion represents one of the major operational problems. For the capture of CO2 from flue gas using MEA, the problem is even more critical since (i) MEA is one of the most corrosive amine when compared to secondary or tertiary amines that are also used for gas sweetening, and (ii) flue gas contains a certain amount of oxygen, which can react with the amine to form corrosive degradation products. In the framework of the CAPRICE project, which is an International cooperation and exchange project supported by the EU, The International Test centre for CO2 Capture from the University of Regina (CA) and IFP (F) have shared their experience on corrosion monitoring from CO2 capture pilot plants. The first pilot plant facility is owned by ITC. It has a capacity to capture 1 ton CO2/day from a natural gas burner. It is equipped with corrosion control instruments and other monitoring systems. The second pilot plant is located in a coal fired power station in Esbjerg (DK). It was built with the financial support of the UE through the CASTOR project under the lead of IFP. It has been in operation since early 2006, and has a capacity of 1.0 ton CO2/hour. It is equipped with weight loss coupons for corrosion evaluation at different locations in the process. This paper presents the major results of corrosion testing from both pilot plants under MEA operation. It appeared from both pilot plants that the areas most susceptible to corrosion were the stripper inlet and outlet, with corrosion rates around 1 mm.year−1 for carbon steel. [Copyright &y& Elsevier]

Abstract: As part of the EU project CASTOR, a 1 t/h CO2 absorption pilot plant has been erected at Esbjergværket (Esbjerg power station) in Denmark. The main purpose of the pilot plant is to demonstrate the post combustion capture technology in conjunction with a coal-fired power station. Additionally, the pilot plant has been used to test the performance of new energy efficient solvents and to validate modelling work. The pilot plant operates on a slipstream of flue gas from the power plant without any further pre- treatment. During the CASTOR project, four 1000-hours test campaigns have been conducted at the facility using conventional solvent, 30%-weight MEA as well as two novel amine-based solvents, CASTOR 1 and CASTOR 2. Among others, the test campaigns consisted of parameter variation tests and longer periods of continuous operation. This paper summarises the operation experience and some of the results obtained during the CASTOR project. [Copyright &y& Elsevier]

Abstract: The co-production of electricity and hydrogen from fossil fuels with the simultaneous capture of CO2 is an attractive proposal for the future European power generation system. A plant based on this technology and with the ability to vary the electricity-tohydrogen output could operate in base-load mode irrespective of the electricity demand, with significant economic advantages. This paper focuses on this type of plant fuelled by coal and lignite and identifies the most suitable gasification technologies that could be adopted for each fuel type, proposes optimal plant configurations and assesses plant performance. [Copyright &y& Elsevier]

Abstract: This paper describes a detailed process optimization of the mass and energy balances for multi-stage membrane systems used in coal-fired power plants. Based on the recovery rate of 50% or 90% CO2 with 95 mol% CO2 purity, different concepts using recirculation of flue gas and variation of feed gas compressor and vacuum pump on the permeate side were developed and optimized to obtain minimum energy consumption. Simultaneously, a cost model was developed to make a further analysis of the optimized concept in view of the tradeoff balance between material and energy consumption. [Copyright &y& Elsevier]