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Abstract: Modern cement plants have high energy efficiencies and the scope to reduce CO2 emissions by further efficiency improvements is small. One of the few ways of greatly reducing CO2 production from cement production is CO2 capture and storage (CCS). This paper summarises a study which assessed the technologies that could be used for CO2 capture in cement plants, their costs, and barriers to their use. The work covered new-build cement plants with post-combustion and oxy-combustion CO2 capture. The basis of the study was a 5-stage preheater with precalciner dry process cement plant with a cement output of 1 Mt/y located in NE Scotland, UK. Process Flow Diagrams (PFDs) and heat and mass balance calculations for both options were developed. The plant costs were estimated and the costs per tonne of CO2 emissions avoided and per tonne of cement product determined. [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: In solvent absorption systems for carbon dioxide capture, potassium carbonate shows particular promise as a solvent. One of the advantages of this solvent is that it is more manageable by way of separation and/or cost effectiveness in the presence of SO2. This paper examines the feasibility of using the same absorber system for simultaneous capture of both CO2 and SO2 from post combustion flue gases. Using a dynamic equilibrium apparatus, the changes in the vapour pressure were measured upon the introduction of sulphur dioxide to a CO2/ N2 mixed gas stream. It has been shown that there is a small change in the resultant vapour pressure. The overall affect of SO2 on the efficiency of CO2 capture is discussed. [Copyright &y& Elsevier]

Abstract: The effect of the increasing concentration of CO2 in the atmosphere on climate change is a major driving force for the development of advanced energy cycles incorporating CO2 management options. Growing interest in the technical and economic feasibility of CO2 capture from large coal-based power plants has led to increased efforts worldwide to develop new concepts for greater CO2 reductions in the future. Greenhouse gas emissions, especially CO2, have to be reduced by 50–80% by 2050, according to the IPCC . The type of fuel used in cement manufacture directly impacts on CO2 emissions, with coal accounting for around 60–70% of CO2 emissions from cement installations. Therefore, the large amount of carbon dioxide emitted during cement manufacturing process - 5% of the total emissions of CO2 from stationary sources worldwide - is a cause of great concern and has to be tack led in order to comply with current legislation. Several technologies are available and have been proposed for the separation of CO2 from the flue gases from new and existing plants with retrofit capture units. Few studies have been undertaken on CO2 capture in cement plants to assess the suitable technologies, with oxy-combustion and amine scrubbing as the possible options (pre-combustion capture not being viable). This paper summarises the different CO2 capture technologies suitable for cement industry and assesses the potential of the calcium looping cycle as a new route for CO2 capture in the cement industry. The potential advantage of this system is the very low efficiency penalty expected (<6%) compared with other capture technologies as the heat required for calcination is balanced by heat released during the carbonation (CO2 capture) step and can be utilized efficiently at high temperature in the plant’s steam cycle. Since limestone is already used for cement manufacture, and because it is a cheap material with good geographical distribution, it allows the use of local limestone resources with minimal limestone-related infrastructure investment. Another envisaged benefit of this new technology is that the lime purged from the cycle could be us ed as a raw material for the production of cement clinker. Therefore, the calcium looping cycle can potentially have an important impact in reducing CO2 emissions from the cement industry, and may also be applicable in other sectors. [Copyright &y& Elsevier]

Abstract: This paper recognizes the urgency of implementing large-scale carbon capture and storage facilities, and discusses the technological challenges associated with scale-up. Historical data of scaling factors commonly used for chemical processes are investigated and compared to CO2 capture technologies. Furthermore, the traditional chemical engineering approach to the scale-up path from laboratory, via pilots, to commercial design is compared to the principles of a newly developed guideline by Det Norske Veritas (DNV) for “Qualification of CO2 capture technology”. The guideline is based on DNV’s generic recommended practice for qualification of new technology, DNV-RP-A203. The procedure explains how to identify, describe, and manage risks (failure modes or threats) with the implementation of new CO2 capture technology in a semi-quantitative way by following a set of sequential steps known as the qualification process.x [Copyright &y& Elsevier]

Abstract: This paper evaluates the opportunities and associated costs for post-combustion capture at a world-scale complex refinery. It is concluded that it is technically feasible to apply post-combustion capture at such a refinery. The CO2 source most suited for capture appears to be a combined stack, but there are a number of other sources that may be targeted at comparable costs. In total these sources may form about 40% of the overall refinery emissions. Our evaluations show the costs of capture from such sources based on available amine technology will be about 3–4 times higher than the current carbon trading values. The capture of CO2 from a large amount of smaller CO2 sources will bring along even much higher costs. A high-level study of the CO2 emissions profile of a number of Shell refineries shows that, typically, up to 50% of the emitted CO2 may be captured at costs comparable to those found at the reference refinery. About 10–20% of concentrated CO2 associated with hydrogen manufacturing may be captured at lower costs. The remainder of emitted dilute CO2 will bring along significantly higher costs. Based on this study, it is concluded for the justification of the implementation of post-combustion capture at refineries, either a significant increase in carbon trading values, mandatory regulations, or a major technological break-through is required. [Copyright &y& Elsevier]

Abstract: Carbon dioxide is considered to be one of the main contributors of the world climate change and flue gases from power plants emit the most CO2. To reduce the carbon footprint, CO2 capturing from flue gas becomes increasingly unavoidable to meet the CO2 emission requirements. CO2 removal with amine solvent has been gaining more and more attention as it may be the only feasible approach technically and economically. Formulated amine solvents are promising over traditional amine solvents to enhance the CO2 absorption considerably, Kohl and Nielsen (1997) . It can be seen as a challenge for a CO2 removal unit to handle flue gas with a variety of CO2 concentrations, especially when the power plant is upgraded, in which its flue gas becomes enriched with CO2. In this paper, a comparison study is carried out to demonstrate the economic potential of capturing CO2 from enriched and non-rich CO2 flue gas stream with Monoethanolamine (MEA) and HTC formulated amine solvent, which is based on mixed amines. Flue gas from combined heat and power plant with 3.5 mol.% CO2 is used as a base case and enriching it with CO2 up to 9.2 mol.% is done to simulate the gas turbine exhaust gas recycling. The study shows that it is advantageous to use HTC formulated solvent over the conventional MEA solvent mainly due to its lower steam consumption, circulation rate, power requirements, and cooling water requirements. The study also shows that the working capacity of the HTC formulated solvent is higher than the MEA solvent. These findings result in significant operating cost savings when processing enriched CO2 flue gas stream using HTC formulated solvent. [Copyright &y& Elsevier]

Abstract: If CO2 emissions are to be reduced to control global warming, many large scale projects will need to be executed on a short term that capture and sequester the CO2. Most studies to date have focused on CO2 capture from power plant flue gas and concluded that the cost of CO2 scrubbing is in itself expensive and that more mature and efficient technologies are needed. CO2 emission control is also complicated by the need to provide SO2 and NOx emission control as well. Burner modifications can be used to control NOx, but other scrubbing technologies are needed to control SO2 emissions. For high sulfur coals, limestone scrubbing is generally applied, adding to the cost of power through purchases of limestone reagent and disposal of by-product gypsum. Cansolv has evolved amine based regenerable technologies that capture SO2 and CO2 and that release them in a water wet, nearly pure condition. SO2 can be converted to sulfuric acid and CO2 can be dried, compressed and sequestered without further treatment. Most importantly, energy used to capture SO2 can be recycled to help capture CO2, reducing the net energy demand of the CO2 process. The use of these two technologies together allows power companies to use higher sulfur, lower cost fuels and reduce energy consumption rates for CO2 capture. By-product sulfuric acid from the SO2 scrubbing system also provides a ready source of revenue to offset scrubbing costs. Cansolv has proven its SO2 scrubbing technologies in commercial applications since 2002. It has operated CO2 pilot plants at several different locations, logging over 6,000 hours of operation. The two technologies will come together in an integrated system, in a plant designed to generate 50 tons per day of CO2, which will start up in 2009. This paper presents important design and performance advantages of these systems. [Copyright &y& Elsevier]

Abstract: At present, the use of fossil fuels in the current energy mix represents the largest source of carbon dioxide (CO2) emissions, an important greenhouse gas (GHG), which is largely blamed for global warming. It is estimated that roughly 26 to 30 percent of all CO2 emissions due to human activities come from fossil fuels used for generating electricity. Moreover, a variety of other industrial processes such as oil refineries, fertilizer and cement plants also emit large amounts of CO2. The opportunity therefore exists for a significant reduction of CO2 from industrial processes and power plants through CO2 Capture and Storage (CCS). Currently, there are three main pathways to capturing CO2 from fossil fuel energy conversion processes, namely, pre-combustion capture, post-combustion capture, and oxy-fuel combustion with CO2 capture. Among these approaches, pre-combustion and oxy-fuel combustion take advantage of the fact that CO2 capture is further facilitated by increasing the concentration of CO2 in the flue gas stream, or by increasing the flue gas pressure, or both. There are several different processes available for CO2 capture and compression from low-pressure flue gas streams rich in CO2. These processes vary from simple straight or once through low-temperature separation and compression to more complex processes involving some form of recycle and/or auto-refrigeration. Given the economic constraints often placed on the cost of CO2 capture, and based on energy demand of each process, the ultimate success of these processes hinges on further refining the existing ones or developing new processes that can lower the cost of CO2 capture. The CANMET Energy Technology Centre in Ottawa is currently pursuing a leading research and development program in the field of near-zero emission fossil fuel technologies. This program includes the development of next generation oxy-fuel combustion technologies, as well as the design and development of efficient CO2 capture and compression processes to recover CO2 from oxy-fuel and other fossil fuel energy conversion systems. In this paper, we present and discuss the technical challenges, development stages and commissioning of the CANMET’s pilot-scale CO2 capture and compression unit (CO2CCU). This pilot-scale CO2 separation and compression unit provides an excellent test platform to study the impact of flue gas impurities on the CO2 capture process. This advanced gas separation system is first-of-a-kind pilot-scale unit that represents an integrated approach to oxy-fuel combustion of coal and other fossil fuels with CO2 capture for storage. [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]

Abstract: In this paper simulation results for integration of CO2 pre-combustion capture by steam methane reforming (SMR) in membrane reactors (MR) with natural gas fired combined cycle (NGCC) power plants are presented. The integrated combined cycle was simulated by GTPRO (Thermoflow) simulator along with the results from simulation of membrane reactor for SMR process developed in this work. The results show that the overall efficiency of the integrated combined cycles decreased due to the energy required for SMR process. On the other hand, by integration of MR in combined cycles, emissions of CO2 to the atmosphere can be avoided. [Copyright &y& Elsevier]

Abstract: In this paper, the use of two Water Gas Shift (WGS) Hydrogen Separator Membrane Reactors (HSMRs) is proposed downstream of a natural gas Autothermal Reformer (ATR), for hydrogen and electricity co-production with low carbon dioxide emissions. Starting from an advanced ATR plant based on state-of-the-art technologies with carbon capture, a novel configuration is proposed. Application of HSMRs allows a significant layout simplification and the reduction of the number of components. Hydrogen separation by means of membrane reactors allows carbon capture higher than 99% compared to 87% of the reference case. Simulation results show that the membrane based power plant achieves higher equivalent fuel conversion efficiency even with a significant amount of electricity produced. Moreover, the innovative solution allows to produce electricity and hydrogen at different ratio without affecting the overall performances. [Copyright &y& Elsevier]

Abstract: A core mission of the U.S. Department of Energy’s (DOE) Carbon Sequestration Program is to foster the development of commercially-ready technologies for CO2 capture and sequestration. An R&D program goal of 90% carbon capture, at an increase in the cost of electricity (COE) no greater than 10% above current state-of-the-art designs without capture, has been established for electric power generation from next-generation Integrated-Gasification Combined-Cycle (IGCC) plants. Advanced gas separation membranes for separating H2 from CO2 are one possible technology for achieving these goals. For IGCC CO2-capture applications, membranes will need to out-perform existing chemical and physical absorption processes. Gas separation membranes, however, can be integrated into a number of different locations in the IGCC process in addition to post water-gas-shift (WGS), the preferred location for current absorption technologies. Due to the many integration options possible, membranes could potentially be required to operate over a wide range of conditions. It is preferred that the membrane operate at pressures and temperatures normally encountered at that point in the IGCC flowsheet where it is being placed. And, clearly it is beneficial that the membrane be placed in a location with relatively high pressure in order to maximize separation. If this is possible, the feed and product gases need not be compressed/expanded or heated/cooled. In addition, membrane materials being considered, whether ceramic, metallic or polymeric, have physical and chemical limitations in regards to operating temperature and tolerance to various compounds that might be present in synthesis gas. It is therefore unlikely that one type of membrane will be able to perform over the entire range of conditions possible. In this paper, we identify preferred membrane locations and quantify performance requirements for a wide range of membrane materials currently under consideration for H2/CO2 separation. [Copyright &y& Elsevier]

Abstract: Oxyfuel combustion in a pulverised fuel coal-fired power station produces a raw CO2 product containing contaminants such as water vapour plus oxygen, nitrogen and argon derived from the excess oxygen for combustion, impurities in the oxygen used, and any air leakage into the system. There are also acid gases present, such as SO3, SO2, HCl and NOX produced as byproducts of combustion. At GHGT8 we presented reactions that gave a path-way for SO2 to be removed as H2SO4 and NO and NO2 to be removed as HNO3. In this paper we present initial results from the Oxyfuel-UK project in which these reactions are being studied experimentally to provide the important reaction kinetic information that is so far missing from the literature. This experimental work is being carried out at Imperial College London with synthetic flue gas and then using actual flue gas via a sidestream at Doosan Babcock’s 160kW coal-fired oxyfuel rig. [Copyright &y& Elsevier]

Abstract: This paper investigates the transient behaviour of an oxygen mixed conducting membrane (OMCM)-based gas turbine (GT) power plant. Several operation and material constraints limit the operability of the power plant. For part-load operation two strategies are analysed: (i) reduction in mass flow of air to the GT in conjunction with reduced fuel supply to the afterburner while keeping the turbine exit temperature (TET) constant (TET control strategy), and (ii) reduction of fuel supply to the afterburner at constant air supply to the GT while the TET is allowed to vary (turbine inlet temperature (TIT) control strategy). Simulation reveals that this GT power plant shows rather slow dynamics because of the recirculation of large amount of gas. The OMCM-based GT power plant is compared to a simple GT power plant with respect to design, off-design as well as transient behaviour during load reduction. Information about controlled and manipulated variables in the GT power plant is given for the development of control strategy. [Copyright &y& Elsevier]

Abstract: The Babcock & Wilcox Company (B&W), through its Power Generation Group, and Air Liquide (AL) have been actively involved in the development of oxy-coal technologies for power generation throughout the past decade. After successful demonstration of oxy-combustion at B&W’s 1.5 MWth Small Boiler Simulator (SBS) and very promising full-scale (300–500 MWe) engineering studies, B&W and Air Liquide initiated a project to scale-up the oxy-combustion technology at B&W’s 100-million Btu/hr (30 MWth) Clean Environment Development Facility (CEDF). During 2007 and 2008, the technology was successfully demonstrated with eastern bituminous, sub-bituminous and lignite coals. During this demonstration project, two near full-scale burners were developed: 1) the B&W DRB-XCL® burner for oxy-firing of eastern bituminous coal, and 2) the DRB-PAX™ burner for oxy-firing with low-rank coals. An operating procedure for smooth transition from air to oxy-combustion then back to air-fired modes has been developed. Stable flames, attached at the burner throat, have been obtained under the oxy-combustion conditions even for the high-moisture, low-Btu lignite while heat absorption in the boiler and convection pass was maintained similar to air-blown combustion. B&W’s new scrubber equipped with integrated cooling surface (patent in progress) successfully reduced moisture and SO2 from the flue gas without the need of a large and expensive gas cooler. Following the completion of this work, the ensuing commercialization process will focus on an at-scale demonstration at a host Utility. A demonstration plant design is being developed, and will involve input from the Utilities that are members of our Oxy-Coal Advisory Group. Project economics, technical design and a near-zero emissions profile are highlighted. The paper describes the experimental demonstration results of the technology at 30 MWth, and the next step in the demonstration of the B&W/AL oxy-combustion technology. [Copyright &y& Elsevier]

Abstract: Chemical-looping with oxygen uncoupling (CLOU) is a novel method to burn solid fuels in gas-phase oxygen without the need for an energy intensive air separation unit. This paper presents batch laboratory fluidized bed CLOU tests where six different solid fuels are used with a Cu-based oxygen carrier. The results show that CLOU results in a factor 3 to 15 faster fuel conversions than conversional chemical-looping combustion. [Copyright &y& Elsevier]

Abstract: This paper is devoted to the state of the art of the most important aspects of high temperature ceramic air separation membranes for oxygen production and oxidation processes. Materials choice, membrane and module design, seal development and fabrication issues will be discussed. [Copyright &y& Elsevier]

Abstract: Doosan Babcock is aiming to develop a competitive oxyfuel firing technology suitable for full plant application post 2010, and is taking a phased approach to the development and demonstration of oxyfuel technology. Doosan Babcock is leading a number of UK Government supported collaborative projects that are developing oxyfuel combustion technology. The “Fundamentals and Underpinning Technologies” project aims to develop a competitive oxyfuel firing process based on the integration of well proven and innovative power plant design components, addressing critical technology gaps such as combustion fundamentals, furnace design and operation, novel flue gas purification technologies and generic process issues. The “Demonstration of an Oxyfuel Combustion System” project aims to demonstrate an oxyfuel combustion system of a type and size (40MWt) applicable to new build and retrofit advanced supercritical boiler plant. These two projects are discussed in the paper and preliminary results from pilot-scale testing undertaken in the first of these are presented. [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: Steam demand is increasing for Oil & Gas projects, and in particular oil sands and extra-heavy oils thermal recovery schemes. Use of oil residues and bitumen can be a cost-effective solution for natural gas substitution in SAGD (Steam Assisted Gravity Drainage). However, use of such fuels gives rise to higher specific GHG emissions. Oxy-combustion technology is an elegant solution to this problem since oxygen allows complete combustion of very high viscosity and heavy fuels, and because it provides a concentrated CO2 stream, for easier Carbon Capture and Storage (CCS). Air Liquide has acquired over the last two decades extensive industrial experience of full oxy-combustion for the glass, metals, cement and waste treatment industries. This expertise and extensive scientific knowledge have been used to develop an innovative oxy-burner technology, specific to steam and power production applications. This oxy-burner technology presents novel and differentiating features, which will be described in this paper. In particular, it features a direct oxygen injection into the burner, without external mixing of oxygen with the flue gas recycle, which provides additional flue gas recycle rate flexibility, and enables a safe handling of the oxygen. Air Liquide has demonstrated the performance of this oxy-burner concept through downscaled (1 MW) oxy- combustion tests in a dedicated cold-wall test-rig with flue gas recycle. Total will retrofit the air-fired boiler at its Lacq CO2 Project (SW of France) with an intermediate size of this oxy- burner technology (four 8 MW oxy-burners). The paper presents: [•] the innovative oxy-burner technology, its challenges and novelties, [•] a description of the Air Liquide 1 MW oxy-combustion test rig and the test results obtained over a wide range of flue gas recycle rates, [•] the integration of the oxy-combustion system into Total’s existing 30 MWth boiler. [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: Vattenfall is presently taking an experimental large-scale pilot test facility into operation for the detailed investigation of the oxyfuel firing process. The plant is located southeast of Berlin in Germany in the vicinity of the existing lignite-fired power plant Schwarze Pumpe. The oxyfuel pilot plant consists of a single 30MWth, top-mounted, PF burner and the subsequent flue gas cleaning equipment, electrostatic precipitator, wet flue gas desulpherization and the flue gas condenser. In addition to these components, a CO2 separation plant is placed downstream of the flue gas condenser to produce liquid CO2. A cryogenic air separation unit located at the site will supply gaseous oxygen with a minimum purity of 99,5% needed for the combustion. The burner is designed for both pre-dried lignite and bituminous coal which will be tested in a later phase. The construction started in January 2007 and the first major test phase is planned to start in November 2008. The liquid CO2 is planned to be used for test injections to qualify the Altmark gas field in Germany as a storage site for CO2 for up-coming carbon capture and storage projects and to investigate opportunities for enhanced gas recovery. This paper will present some background information and describe the planned measurements. Initial experiences from the commissioning of the pilot plant will be presented. [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 the development of carbon-based adsorbents for CO2 separation in integrated gasification combined cycle (IGCC) processes for energy generation and hydrogen production. The research presented forms part of a Research Fund for Coal and Steel funded project “Hydrogen separation in advanced gasification processes” (HYDROSEP) with the ultimate aim of developing technologies to reduce the costs for the capture of CO2 when compared to existing absorption processes. A range of carbon adsorbents were developed by MAST Carbon. They present significant microporosity and in some cases also meso or macroporosity. CO2 adsorption isotherms have been determined using a dual limb differential pressure apparatus under realistic operating conditions. CO2 and H2 high pressure adsorption isotherms at room temperature have also been evaluated in a high pressure adsorption balance. Maxima CO2 uptakes of 58 wt.% at 3 MPa and H2 uptakes of 0.3 wt.% at 4 MPa were obtained. The significant differences observed in CO2 and H2 adsorption at high pressures showed the high selectivity for CO2 of the tested MAST Carbon adsorbents. [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: There is considerable interest in identifying carbon dioxide capture processes that can be incorporated within Integrated Gasification and Combined Cycle (IGCC) systems. In this paper, two novel adsorption based process configurations are proposed to operate in the temperature window (250–500 ∘C) suitable for an IGCC process after the water gas shift reactor. These process configurations are numerically simulated with an in-house simulator MINSA (Monash Integrated Numerical Simulator for Adsorption), and the simulation results indicate that good performance can be achieved with low operating cost. Carbon dioxide purity of greater than 95% and carbon dioxide recovery of greater than 90% can be obtained by both process options. [Copyright &y& Elsevier]

Abstract: The second pre-combustion decarbonisation technology Sorption Enhanced Water-Gas Shift (SEWGS) combines the WGS reaction with simultaneous CO2 capture by using a mixture of WGS catalyst and CO2 sorbent. Accordingly, the WGS catalyst is exposed to all conditions encountered in the cyclic SEWGS process, such as exposure to steam in the regeneration step. This paper shows that commercial precious metal, FeCr, and CoMo WGS catalysts are robust towards periodic exposure to these atypical conditions. Catalyst behavior is reported to periodic exposure to these atypical conditions at a temperature of 400 ∘C, pressures up to 5 bara and H2S contents from 1 ppm to 2,000 ppm. Although additional experiments need to be performed at increased pressure, it appears that all catalysts can potentially be used in the SEWGS process. [Copyright &y& Elsevier]

Abstract: This paper presents the results of system assessments that were conducted to compare conventional and advanced water-gas shift reaction section in Integrated Gasification Combined Cycles (IGCC) with pre-combustion CO2 capture. The advanced shift reaction section comprises four staged reactors with distributed feeds of syngas and quench water in between the reactors. This configuration reduces the steam requirement of the shift reaction up to 70% in comparison with conventional configurations, at carbon capture ratios of approximately 85%. The specific lost work per amount of CO2 was used to determine the optimum carbon capture ratio for each case. [Copyright &y& Elsevier]

Abstract: This paper presents the results of gas turbine simulations that were conducted to compare state-of-the-art and re-designed gas turbines operated on syngas, in Integrated Gasification Combined Cycles (IGCC) with pre-combustion CO2 capture. The effects of the desired carbon capture ratio on efficiency and power output were evaluated, for retrofit applications both with and without capacity building. The results indicate that re-designed gas turbines for syngas applications can achieve higher efficiencies than natural gas turbines that were modified for syngas applications. [Copyright &y& Elsevier]

Abstract: Increasing world energy demand and pricing trends have encouraged oil and gas companies to look at developing contaminated natural gas fields previously deemed uneconomic. At the same time, world wide perceptions on climate change are pressuring energy companies to adopt global best practices to reduce carbon emissions. Developing currently unviable contaminated natural gas fields requires developing new technologies for high CO2 gas treatment. Current technologies available in the market for natural gas treating may not be ideally suitable for treating highly contaminated natural gas where CO2 geo-sequestration is required. Use of physical and chemical absorption solvents have been the most popular method for treating natural gas with high CO2, and to a lesser extent, membranes and adsorption methods. These technologies remove CO2 at near ambient pressures thus requiring substantial amount of compression to levels needed for geo-sequestration. Cryogenic CO2 removal methods can capture CO2 in a liquid form thus making it relatively easy to pump underground for storage or send for enhanced oil recovery. This new cryogenic CO2 removal method has been researched and tested in a demonstration plant and is soon to be implemented in commercial field applications. This paper intends to share recent field experience and test results from Cool Energy’s CryoCell® demonstration plant in Western Australia. The CryoCell® process was developed by Cool Energy Ltd and tested in collaboration with other industrial partners including Shell Global Solutions. This presentation will also discuss and compare existing CO2 treatment technologies for developing high CO2 natural gas fields requiring CO2 geo-sequestration with the CryoCell® CO2 capture process. Basic economic comparisons between the CryoCell® process and an amine based process including CO2 geo-sequestration will be presented. [Copyright &y& Elsevier]

Abstract: In this paper a rector model is presented for a SE-SMR reactor. The reactor model comprises simplified mathematical representation of the flow regime, differential equations for mass and heat transfer, sub-model for chemical reaction kinetics and absorption equilibria. The model was used to investigate various operational modes for the reformer as well as for comparison of the reformer performance with use of various sorbents (Li4SO4,Na2ZrO3,CaO). A semi-empirical model for apparent reaction kinetics of dolomite was developed based on thermogravimetrical analysis whereas the reaction kinetics for the other types of sorbents was taken from literature. [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: 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: Adsorption is considered to be one of the more promising technologies for capturing CO2 from flue gases. The efficient adsorption of CO2 at low partial pressures, associated with post-combustion capture, require chemical type adsorbents containing basic amine functional groups. It has been demonstrated that amine polymers, for example polyethylenimine (PEI), immobilised on various porous substrates, silica, zeolites and fly ash, are effective adsorbents for CO2. When considering the use of adsorption for large scale CO2 capture, the ease of regeneration and the lifetime of the adsorbents are critical factors in determining their efficiency, cost and therefore feasibility for use. In this paper two approaches, thermal swing adsorption (TSA) cycles over a range of temperatures and time in an atmosphere of CO2 and thermally assisted pressure swing desorption, are explored for the regeneration of the PEI based adsorbents. The reactions occurring during the TSA regeneration of PEI based adsorbents in an atmosphere of CO2, especially the formation of a thermostable complex between PEI and CO2 above 130 ∘C are described. Identification of the complex by FTIR, XPS and 13C NMR as a urea linkage will be described. Overall, the results from this research have implications for the selection of regeneration strategies of all amine based CO2 adsorbents. [Copyright &y& Elsevier]

Abstract: Increasing awareness of the influence of greenhouse gases on global climate change has led to recent efforts to develop strategies for the reduction of carbon dioxide (CO2) emissions. The strategy that is receiving the most attention involves the capture of CO2 from large point sources, such as fossil fuel-fired power plants, and long-term storage underground or in the ocean. CO2 capture can be achieved either by post or pre-combustion capture at ambient or high pressure respectively. Aqueous solutions of amines have long been used by industry as absorbents for acid gas (CO2,H2S) removal, but have a large number of short comings. As an alternative, adsorption is one of the more promising technologies for capturing CO2 from flue gases, potentially avoiding the shortcomings of aqueous amine systems. In this paper the development of solid adsorbents for post-combustion capture will be described. The generation and testing of a range of adsorbents for post-combustion capture of CO2 at ambient pressure has demonstrated the need for chemical type adsorbents. A range of chemical type adsorbents have been generated by two methods: [•] Modification of the surface chemistry of both low cost carbons and mesoporous silica by impregnation with a basic nitrogen-containing polymers (i.e., polyethylenimine). [•] Generation of a range of high nitrogen content carbon matrix adsorbents by carbonisation and subsequent thermal or chemical activation of a range of nitrogen compounds. CO2 adsorption capacities at equilibrium and under dynamic conditions using a simulated flue gas will be described at different temperatures and gas residence times. Regeneration using simulated temperature, pressure swing cycles and steam stripping and the effect of the processes on the lifetime of the adsorbent will be discussed. [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]

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: 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: The chemical reactions involved in CO2 absorption and desorption by chemical absorbents such as aqueous amines are being investigated and modelled to identify and make potential improvements in efficiency. Recent advances in FT-IR spectroscopy have allowed for convenient and rapid analysis of chemical species to be carried out in an aqueous environment. This paper presents the findings of an investigation of carbon dioxide absorption and desorption into/from amine solutions. The amines investigated, including primary capture solvents (eg. MEA) as well as promoters (eg. MDEA), have been selected to demonstrate that both carbamate and carbonate formation can be monitored using this technique. New insights into a much applied but little understood industrial chemical process have been revealed. [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: 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: 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: There is strong world-wide interest in developing new and improved processes for post-combustion capture of CO2, usually using chemical absorption. Developers of new processes make positive claims for their proposals in terms of low energy consumption, but these are usually difficult to validate. This paper demonstrates that rigorous application of thermodynamic analysis and process simulation provides a powerful way to quantitatively evaluate the energy requirements of CO2-capture processes by applying this methodology to the analysis of the chilled-ammonia process. [Copyright &y& Elsevier]

Abstract: Metal organic frameworks (MOFs) have emerged as one of the more interesting classes of materials for adsorption based separation of CO2 from other gases in exhaust mixtures. To improve efficiency in developing structure property relationships, we have developed a general methodology to model, based on molecular grand canonical Monte Carlo (GCMC) methods, the adsorption of CO2 and other gases within these framework structures. This approach also provides insight into the relative importance of various mechanisms of CO2 adsorption. So far, we have demonstrated good correlation between calculated and experimental isotherms for a number of synthetic MOFs. Through systematic (virtual) variation of structural motifs we are striving to develop an und erstanding of structure-property relationships that will enable the identification, and hence the design, of optimum materials for CO2 separation from various exhaust gas mixtures and under varied conditions of temperature and pressure. The paper present s details of the approach, a comparison between predicted and experimentally determined isotherms, and preliminary identification of some preferred structural features. [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: 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: 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: 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: 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]