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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]

Abstract: The Chilled Ammonia Process (CAP) can be applied to capture CO2 from flue gases exhausted from coal-fired boilers and natural gas combined cycle (NGCC) systems, as well as a wide variety of industrial applications. Initial tests conducted at the We Energies Pleasant Prairie Power Plant indicate that CAP can absorb CO2 using regenerated ionic solution on a continuous basis. The We Energies facility is designed to capture over 35 tonnes/day of CO2 at design rates. The facility was engineered, installed, and is being operated as a co-operative effort between Alstom (the process supplier) who engineered and constructed the pilot; EPRI (including 37 funders) who is conducting data collection and process evaluation; and We Energies who is providing operating utilities and is serving as the site host. The CAP is a solvent-based regenerable process that uses an aqueous ammonium solution to capture CO2 by forming ammonium bicarbonate. The bicarbonate is subsequently heated to drive off the CO2 with the resulting carbonate returned to the CO2 absorption system for re-use. Anticipated advantages of the CAP over an amine-based process include: Lower energy for regeneration Regeneration at pressure Ability to offset LP steam consumption with reject heat (Not tested at We Energies) Cooling to minimize ammonia penetration from the absorber. Results from the initial operation of the CAP process at the We Energies site are presented in this paper. [Copyright &y& Elsevier]

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

Abstract: The designs of power plants fitted with carbon capture have been evaluated in many studies in order to establish the additional costs and efficiency reductions. Such studies generally focus on plants providing base load power with continuous capture of CO2. The energy efficiency and power output of such plants is significantly reduced because of the parasitic heat and power requirements of the capture process. Typically the efficiency reduction is 8–12% which means that if the capture process could be turned off roughly 20–30% more power could be delivered [J. E. Davison, Performance and costs of power plants with capture and storage of CO2, Energy 32 (2007) 1163–1176]. This paper examines options to extend the flexibility of power plants fitted with carbon dioxide capture to allow additional electrical demand to be met at times of peak capacity. One reason for designing and operating CCS plant in this way would be the high prices which usually prevail during periods of peak demand. Another reason of rising importance is to support the increasing amount of “variable” sources of power from renewables, particularly wind energy which are being connected to the electrical grid [H. Holttinen, Estimating the impacts of wind on power systems, Modern Power Systems, 28 (5) (2008) 49–52]. Options fall into two classes, those which result in cessation of some or all CO2 capture and those which maintain CO2 capture and hence revenues from emission certificates. The former option is shown to be economically unattractive unless peak prices are extremely high or carbon prices become extremely low. The abilities of each the three main capture technologies of pre, post and oxy combustion to modify their operation and design to provide some economic peak power capability are reviewed. There are two options to do this, one is to design the units so that they can operate at reduced capacity while retaining their normal CO2 capturing functionality. The other is to temporarily suspend energy consuming parts of the capture process. The technical operational and economic implications of doing the latter are discussed. [Copyright &y& Elsevier]

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

Abstract: The paper describes the development of a novel reactor concept for natural gas fueled chemical looping combustion (CLC). The reactor is best described as a rotating bed reactor in which a doughnut shaped fixed bed containing an oxygen carrier material is rotated between different sectors where air and methane are fed. The gases are fed radially outwards through the fixed bed. Between the air and methane sectors are sectors where an inert gas is fed to avoid uncontrolled mixing of air and methane. The rationale for the choice of reactor is discussed and a CuO/Al2O3 based oxygen carrier has been selected for the initial reactor evaluation. A major challenge with the proposed reactor setup is to avoid mixing between the air and methane side caused by the unavoidable insufficient sealing between the moving parts. Initial testing show that mixing is only partly avoided, and a degree of separation corresponding to around 80% is observed at ambient temperature for the first reactor prototype. Further work will be to improve the design in order to reduce gas mixing further and to demonstrate real CLC operation utilizing the reactor. [Copyright &y& Elsevier]

Abstract: There exists within the electricity generation sub-sector the potential for substantial GHG reductions through the application of CO2 capture and storage technologies. Many assessments of the cost and performance of power plants with CCS (Carbon Capture and Storage) have been undertaken but these studies almost always omit considering operability: the ability of a process to operate satisfactorily under conditions different than the nominal design conditions. Electricity systems rely upon generators with a high degree of operability in order to meet variations in power demand, ambient conditions, fuel supply, etc. and the need for operability is expected to increase in the future. The operability of CCS technologies could have a major impact on the extent to which CCS is used in the years to come and it could also affect the choice of the optimum CO2 capture technology. The attention given to the operability of power plants with CCS is in sharp contrast to its potential significance; only a handful of the research groups contributing to the sizeable CCS literature are explicitly investigating the operability of these technologies. This paper seeks to correct this oversight and proposes the scope of a comprehensive comprehensive assessment of the leading CO2 capture schemes—pre-combustion, post-combustion, and oxy-combustion— with respect to operability. In the final analysis, a layered approach is suggested with four major study areas: [•] flexibility [•] controllability [•] start-up/shutdown characteristics [•] assessment of trade-offs between operability and cost While the proposed undertaking is ambitious, it is believed that by building upon the existing process modelling and simulation expertise that exists with the CCS community, the work could be completed within a reasonable amount of time. [Copyright &y& Elsevier]

Abstract: This paper presents a guideline for qualification of CO2 capture technology. The guideline provides a systematic and transparent procedure for the qualification of natural gas power generation technologies with CO2 capture. For new technology, there is generally a lack of relevant codes and standards. Qualification according to a set of requirements is therefore the only rational approach. The CO2 capture technologies available today need considerable efforts to integrate, optimize, and to scale up the process components to industrially mature processes. To secure the success and minimize the time to commercialisation of research and development projects for new CO2 capture technologies, it is vital that the technology is qualified in a step-wise and systematic manner. The guideline was developed as a joint industry project and was carried out through three phases: (1) Development of a draft guideline, (2) Test of the draft guideline in case studies, (3) Final guideline developed based on feedback from the case studies. The scope has been to develop a guideline that could cover the major routes to CO2 capture, post combustion, pre combustion and oxy-fuel processes. Thus, the qualification work process itself is described in a rather general way to be applicable for all three capture concepts, whereas further specifications are given as specific examples of applications to CO2 capture technologies. [Copyright &y& Elsevier]

Abstract: We used a 6.5 m tall packed tower prototype to study the capturing rate of CO2 from air. The tower was operated at a pressure drop of less than 27 pa in the packing at 0.7 m/sec air speed with a counter current flow mode and with NaOH or KOH solution as the absorbent. The tower consumed an average of ∼30 kJe per mole CO2. We found that via an intermittent operation with a 5% duty cycle, the fluid pumping work reduced by 90%. A novel process for removing carbonates ions from alkaline solutions based on titanate compounds is compared to the traditional lime cycle for the caustic recovery. The titanate process reduces the high-grade heat requirement by ∼50%. The results from experimental data of leaching and precipitation test support process design of the titanate cycle. In this paper, we also present the chemical process design. [Copyright &y& Elsevier]

Abstract: A 25 TPD post-combustion CO2 capture plant for brown coal and a 0.5TPD pre-combustion CO2 capture IGCC process have been designed and are being built in Victoria, Australia to assess developments in solvent absorption capture technologies. In this paper, the flowsheets developed for these processes will be discussed along with the underpinning research in the following areas: [•] New contact equipment — recent work has shown that the SMR packing has enhanced performance over structured packing and standard Pall rings. [•] The influence of promoters to enhance kinetics - using a wetted-wall column, experiments have been conducted with boric acid added to potassium carbonate solvent with results showing an enhancement in CO2 absorption rates. [•] The influence of flue gas impurities - post-combustion impurities, including SO x and NO x , have been studied with potassium carbonate to evaluate their effects on CO2 absorption. [•] Process modeling — ASPEN Plus™ simulations have been developed to predict column performance and the effects of impurities on the equilibrium relationship. [Copyright &y& Elsevier]

Abstract: This paper presents results from a 30 -month project devoted to taking the chemical-looping combustion (CLC) technology to the next level of development. The project is part of the EU’s Sixth Framework programme with support from the CCP (Carbon Capture Project) and has mainly focused on the critical issues for an up-scaling of the technology. In an earlier project the CLC technology was demonstrated successfully for the first time for 100 h using Ni -based oxyge n carrier particles using natural gas as fuel. The current project has built on these experiences and : i) established industrial-scale NiO particle production with suitab le commercial raw materials. Oxygen carrier particles have been produced with both s pray -drying and impregnation and investigated extensively with respect to parameters important for CLC operation, such as reactivity in batch and continuous operation, strength, defluidization phenomena, operation at high temperatures and effect of imp urities suc h as H 2S in the fuel; ii) extended operational experience in long term tests of particles in the available 10 kW prototype for more than 1000 hours combustion and iii) succesfully scaled -up and operated the process in a 120 kWth combustor using syn gas and natural gas. Further, the project has included extended and verified modelling of the reactor system for scale-up in addition to process and technology scale-up and economic assessment. The paper will present the main results of the project. [Copyright &y& Elsevier]

Abstract: During the last decades significant effort has been put into research on the social, economical, political and technical issues related to large scale deployment of Carbon Capture and Storage (CCS). A complete CCS cycle requires safe, reliable and cost efficient solutions for transmission of CO2 from the capturing facility to the location of permanent storage. The current initiative originates from DNV’s long engagement in developing standards and guidelines for offshore pipelines and an identified need to specifically address the technical challenges related to transmission of CO2 with associated contaminants. The guideline will be based on a comprehensive literature review and gathering of experience from existing (both onshore and offshore) CO2 pipeline operators. Available pipeline codes, standards, guidelines and regulations combined with the latest available research and technical developments is set as the point of departure for this guideline development. Issues related to pipeline design, commissioning and operation as well as re-qualification/conversion of existing pipelines for transmission of CO2 will be addressed. The guideline is being developed as a joint industry project and is scheduled for delivery by end of July 2009. After completion of the JIP, the guideline will be converted into a public available Recommended Practice (RP) by Det Norske Veritas (DNV). The guideline will give “how to?” answers for safe, reliable and cost-effective transmission of CO2 in pipelines. This paper addresses main technical issues one need to manage. [Copyright &y& Elsevier]

Abstract: Interest is growing regarding the potential size of a future U.S.-dedicated carbon dioxide (CO2) pipeline infrastructure if carbon dioxide capture and storage (CCS) technologies are commercially deployed on a large scale within the United States. This paper assesses the potential scale of the CO2 pipeline system needed under two hypothetical climate policies (WRE450 and WRE550 stabilization scenarios); a comparison is then made to the extant U.S. pipeline infrastructures used to deliver CO2 for enhanced oil recovery and to move natural gas and liquid hydrocarbons from areas of production and importation to markets. The analysis reveals that between 11,000 and 23,000 additional miles of dedicated CO2 pipeline might be needed in the United States before 2050 across these two cases. While either case represents a significant increase over the 3900 miles that comprise the existing national CO2 pipeline infrastructure, it is important to realize that the demand for additional CO2 pipeline capacity will unfold relatively slowly and in a geographically dispersed manner as new dedicated CCS-enabled power plants and industrial facilities are brought online. During the period 2010–2030, this analysis indicates growth in the CO2 pipeline system on the order of a few hundred to less than 1000 miles per year. By comparison, during the period 1950–2000, the U.S. natural gas pipeline distribution system grew at rates that far exceed these growth projections for a future CO2 pipeline network in the U.S. This analysis indicates that the need to increase the size of the existing dedicated CO2 pipeline system should not be seen as a major obstacle for the commercial deployment of CCS technologies in the United States. While there could be issues associated with siting specific segments of a larger national CO2 pipeline infrastructure, the sheer scale of the required infrastructure should not be seen as representing a significant impediment to U.S. deployment of CCS technologies. [Copyright &y& Elsevier]

Abstract: In this paper we present a spatial optimization model that comprehensively models carbon capture and s torage (CCS) infrastructure, from source -to -sink. The model optimally and simultaneously chooses at which sources and how much CO2 should be captured, at which reservoirs (or sinks) and how much CO2 should be injected and stored, where a pipeline network should be constructed and at what capacity, and how to distribute CO2 among the networked sources and reservoirs. A key contribution of the model is the ability to link sources and reservoirs using a realistic and capacitated pipeline network. [Copyright &y& Elsevier]

Abstract: For carbon dioxide capture and geologic storage to be deployed commercially and in a widespread manner will require well thought out approaches for transporting the CO2 in a pipeline system from the capture facility to the injection site. Establishing a widespread CO2 transportation infrastructure will require strategic long-term planning, taking into account the potential magnitude of future deployment scenarios for CCS, up to a scale of infrastructure that could be comparable to the scale of oil & gas infrastructure. This paper outlines the results of a study, commissioned by the CO2 Capture Project (CCP) and completed by Environmental Resources Management (ERM) that evaluated the benefits and risks of two approaches to developing CO2 pipeline systems. The two basic approaches are described in the paper as: 1. On a point-to-point basis, which matches a specific source to a specific storage location; or 2. Via the development of pipeline networks, including backbone pipeline systems, which allow for common carriage of CO2 from multiple sources to multiple sinks. An integrated approach to pipeline infrastructure approach offers the lowest average cost on a per ton basis for operators over the life of the projects if sufficient capacity utilization is achieved relatively early in the life of the pipeline. Integrated pipelines also reduce the barriers to entry and are more likely to lead to faster development and deployment of CCS. Without incentives to encourage the development of optimized networks project developers are likely to build point to point pipelines because they offer lower costs for the first movers and do not have the same capacity utilization risk. [Copyright &y& Elsevier]

Abstract: Along with public transport modification, building and consumer efficiency, renewable energy and bio-fuels, among other greenhouse gas mitigation strategies within the European Union (EU), Zero Emission Power utilising Carbon Capture and Storage (CCS) is one of the key options to significantly reduce CO2 quickly as the world begins the transition away from fossil fuels and high CO2 emissions. Transporting CO2 from capture locations to storage sites will play an integral part in the implementation of this strategy, as geography, urbanism, regulation, regionalism and currently installed transport systems challenge the ability of the EU and its member states to store billions of tonnes of CO2 before the middle of this century. While the building of a CO2 transportation infrastructure is the primary subject of this paper, no discussion of transport can begin without at least a brief discussion of how and where CO2 will be safely and securely stored, and the identification and rationalization of the capture sites to the storage locations. Only after this exercise is complete can a transport infrastructure be devised that will safely deliver the captured CO2 for long-term storage and sequestration. The EU Zero Emissions Technology Platform SSI workgroup report used the latest data available from public sources to identify within each EU member state, both the largest point sources of CO2 emissions and the most likely storage locations. Early opportunities for success whereby relatively pure CO2 streams might be captured with minimal cost and complexity were also identified. Lastly, the concept of the EU Flagship programme was rationalized to storage locations. Recommendations were given for the assigned tasks. Within this context the SSI workgroup reviewed options that might afford member states the opportunity to begin the construction of transport systems and how an EU wide storage infrastructure might be devised and evolve, including efforts for the EU Flagship Programme, as well as a discussion on what such an infrastructure would likely not become. The report used as its primary analogue the history of the currently installed natural gas pipeline system in Northwest Europe. Transport considerations used estimations from energy modelling of how much CO2 might ultimately be stored by 2050 as a basis for the EU wide transport design. From that, geographical and urban considerations, physical movement and pressure limitations, CO2 quality variations, regulatory impediments, legal options, economic unknowns and value chains, pubic acceptance and education, along with verifiable, certifiable storage locations, both offshore and onshore were used to create an overall transport scenario that may prove a workable option in the coming decades. [Copyright &y& Elsevier]

Abstract: The deployment of carbon capture and storage technology involves a spatial coupling of point sources of carbon dioxide with geologic reservoirs capable of storing carbon dioxide. Carbon dioxide captured from these point sources will be injected into these geologic reservoirs, which may or may not be proximal to the sources. This spatial coupling will occur through a dedicated carbon dioxide pipeline network that connects the industrial organization of carbon dioxide production and capture with the geologic organization of carbon dioxide injection and storage. The relative locations of these sources and sinks are an important component of the overall returns to scale for the integrated carbon capture and storage system. Aggregating CO2 flows in close proximity to sources and reservoirs increases the utilization of economies of scale in pipeline transportation and impacts the returns to scale and preferred paths forward for targeted deployment of the entire coupled technological system. This paper derives deployment preferences by investigating how the spatial clustering and centralization of carbon dioxide sources and reservoirs affects the ability to aggregate CO2 flows into networked pipelines. One major result is that, depending on the clustering within and between carbon dioxide sources and reservoirs, it can be advantageous to transport captured carbon dioxide to reservoirs that are not proximal to the point(s) of capture. [Copyright &y& Elsevier]

Abstract: The permeability of the coal seam is the main petrophysical property controlling the performance of the ECBM operation, since it affects both the CO2 injection and CH4 recovery. In the present paper, coal swelling of intact coal samples is studied both under unconstrained and constrained conditions. Unconstrained swelling experiments are performed in a view cell under a static high pressure gas atmosphere, whereas gas injection experiments are carried out in a flow cell, where the sample is subjected to a given hydrostatic confinement. Both experiments are performed by using different gases, namely He, CO2, CH4 and N2, and under typical coal seam conditions, i.e. at high pressure and at 45 ∘C. The results of the unconstrained coal sample showed that swelling increases monotonically with pressure up to a few percents for adsorbing gases, with CO2 swelling coal more than CH4 that swells more than N2, whereas for helium, a non-adsorbing gas, volume changes are negligible. The results of the flow experiments were successfully described using a mathematical model consisting of mass balances accounting for gas flow and adsorption, and mechanical constitutive equations for the description of porosity and permeability changes during injection. Results showed increase in permeability with decreasing effective pressure on the sample. Moreover, when CO2 is used a permeability reduction was observed compared to Helium, which can be explained by taking into account the effects of swelling on the flow dynamics. [Copyright &y& Elsevier]

Abstract: This paper is the synopsis of a larger work completed under the auspices of the CO2 Capture Project, an international effort funded by eight of the world’s leading energy companies. It seeks to explain the rationale for the geological storage of carbon dioxide (CO2) based on insights from the practical experience of the oil and gas industry. It considers the key technical applications that will make storage possible, and the subsurface management processes that will provide confidence to all stakeholders that storage is effective. Four broad areas are described including, the selection and characterization of sites for CO2 storage; issues of well integrity and well construction; the requirements of monitoring programs for appropriate data collection and risk management. Finally, issues arising from storage operations and the eventual closure and decommissioning of CO2 storage sites are addressed. [Copyright &y& Elsevier]

Abstract: Effective large scale deployment of CCS requires recognized standards and guidelines. This paper presents a new 18 month Joint Industry/Public Project (CO2QUALSTORE) that aims to develop a systematic risk-based procedure for selection, characterization and qualification of sites and projects for geological storage of CO2. The project will integrate and interpret results from R&D and pilot projects into a guideline format. Target users are operators, authorities, verifiers, and other stakeholders. The guideline will include examples from case studies; links to decisions during development, operation and closure; assistance in complying with regulations; as well as accounting for emissions avoided. [Copyright &y& Elsevier]

Abstract: Since the end of First Phase of the IEA GHG Weyburn CO2 monitoring and storage research project in 2004, the leading sponsors, PTRC, and the project team have been moving forward with the Final Phase. International interest in this project has remained strong, with new industry sponsors and continued support from First Phase sponsors. This paper highlights the key activities undertaken and issues encountered during the transition period between the conclusion of the First Phase and the start of the Final Phase. A detailed overview is provided of the proposed Final Phase technical work program, progress on ongoing technical research activities and other key activities planned. The technical research program consists of four main technical themes: [1.] Site Characterization-Geological Integrity [2.] Wellbore Integrity [3.] Storage Monitoring Methods-Geophysical & Geochemical [4.] Risk Assessment. A key deliverable from this Final Phase is development of a Best Practises Manual to help guide implementation of CO2 geological storage in conjunction with enhanced oil recovery and to provide learnings extracted from the project that are generally applicable to other geological storage projects. [Copyright &y& Elsevier]

Abstract: Carbon capture and storage will likely be a crucial bridging technology as we move to a low-carbon global economy. The WRI CCS project was initiated to develop stakeholder consensus on policies and procedures for safe and effective demonstration and deployment of technology. This effort is taking place in the context of rapidly changing policy arena. The U.S. EPA initiated a process to develop geologic sequestration regulations and several efforts are being undertaken globally. This paper presents a review of WRI guidelines in the context of the U.S. EPA Draft Geologic Sequestration Rule and the Draft European Union Geologic Sequestration Directive. [Copyright &y& Elsevier]

Abstract: Modelling CO2 storage in saline aquifers on a reservoir scale, for example, for feasibility studies and risk analyses is very demanding with respect to computational cost due to the complex geometries that need to be described and due to the diversity of interacting hydraulic, thermal, mechanical, and geochemical processes. In most cases it is not necessary to be able to describe all these processes for the whole simulation time period or for the entire model domain. Within this paper it is outlined how model coupling could help in reducing the model complexity and increasing model efficiency while the relevant processes are still taken into account. Since the work on this topic is at an early stage, this paper is restricted to a discussion of coupling concepts. [Copyright &y& Elsevier]

Abstract: Large scale geologic sequestration tests are in the planning stages around the world. The liability and safety issues of the migration of CO2 away from the primary injection site and/or reservoir are of significant concerns for these sequestration tests. Reservoir models for simulating single or multi-phase fluid flow are used to understand the migration of CO2 in the subsurface. These models can also help evaluate concerns related to brine migration and basin-scale pressure increases that occur due to the injection of additional fluid volumes into the subsurface. The current paper presents different modeling examples addressing these issues, ranging from simple geometric models to more complex reservoir fluid models with single-site and basin-scale applications. Simple geometric models assuming a homogeneous geologic reservoir and piston-like displacement have been used for understanding pressure changes and fluid migration around each CO2 storage site. These geometric models are useful only as broad approximations because they do not account for the variation in porosity, permeability, asymmetry of the reservoir, and dip of the beds. In addition, these simple models are not capable of predicting the interference between different injection sites within the same reservoir. A more realistic model of CO2 plume behavior can be produced using reservoir fluid models. Reservoir simulation of natural gas storage reservoirs in the Illinois Basin Cambrian-age Mt. Simon Sandstone suggest that reservoir heterogeneity will be an important factor for evaluating storage capacity. The Mt. Simon Sandstone is a thick sandstone that underlies many significant coal fired power plants (emitting at least 1 million tonnes per year) in the midwestern United States including the states of Illinois, Indiana, Kentucky, Michigan, and Ohio. The initial commercial sequestration sites are expected to inject 1 to 2 million tonnes of CO2 per year. Depending on the geologic structure and permeability anisotropy, the CO2 injected into the Mt. Simon are expected to migrate less than 3 km. After 30 years of continuous injection followed by 100 years of shut-in, the plume from a 1 million tonnes a year injection rate is expected to migrate 1.6 km for a 0 degree dip reservoir and over 3 km for a 5 degree dip reservoir. The region where reservoir pressure increases in response to CO2 injection is typically much larger than the CO2 plume. It can thus be anticipated that there will be basin wide interactions between different CO2 injection sources if multiple, large volume sites are developed. This interaction will result in asymmetric plume migration that may be contrary to reservoir dip. A basin- scale simulation model is being developed to predict CO2 plume migration, brine displacement, and pressure buildup for a possible future sequestration scenario featuring multiple CO2 storage sites within the Illinois Basin Mt. Simon Sandstone. Interactions between different sites will be evaluated with respect to impacts on pressure and CO2 plume migration patterns. [Copyright &y& Elsevier]

Abstract: In Salah Gas Project in Algeria has been injecting nearly one million tonnes CO2 per year over the past four years into a water-filled strata at a depth of about 1,800 to 1,900 m. Unlike most CO2 storage sites, the permeability of the storage formation is relatively low and comparatively thin with a thickness of about 20 m. To ensure adequate CO2 flow-rates across the low-permeability sand-face, the In Salah Gas Project decided to use long-reach (about 1 to 1.5 km) horizontal injection wells. In this study we are using field data and coupled reservoir-geomechanical numerical modeling of CO2 injection to analyze geomechanical responses and to assess the effectiveness of this approach for CO2 storage in relatively low permeability formations. Among the field data used are surface deformations evaluated from recently acquired satellite-based inferrometry (In SAR). The In SAR data shows a surface uplift on the order of 5 mm per year above active CO2 injection wells and the uplift pattern extends several km from the injection wells. We use the observed surface uplift to constrain our coupled reservoir-geomechanical model. We conduct sensitivity studies to investigate potential causes and mechanisms of the observed uplift. Preliminary results of our analysis presented in this paper indicates that most of the observed uplift magnitude can be explained by poro-elastic expansion of the 20 m thick injection zone, but there could also be a significant contribution from pressure changes within the adjacent caprock. Moreover, we show that surface deformations from In SAR can be useful for tracking the fluid pressure and for detection of a permeable leakage path (e.g. in a permeable fault) through the overlying caprock layers. [Copyright &y& Elsevier]

Abstract: Forecasting and demonstrating the long-term isolation performance of engineered geologic CO2 storage requires a technology portfolio that explicitly integrates state-of-the-art site characterization, experimental, modeling, monitoring, and verification components. In this paper, I review the fundamental elements of isolation performance; outline the technical requirements of advanced site characterization, modeling, and monitoring methods; discuss key challenges to identifying screening criteria that permit optimal source/sink matching and quantifying the uncertainties that surround modeling and monitoring efforts; and, finally, describe a next-generation stochastic methodology that facilitates explicit integration of uncertainty-bound performance prediction, monitoring, and site characterization. [Copyright &y& Elsevier]

Abstract: Latera is a volcanic area north of Rome where deep, naturally-produced carbon dioxide migrates to the surface and is released to the atmosphere. The region provides an environment in which many processes relevant to the geological storage of carbon dioxide can be studied. This paper describes system-level modelling studies using Quintessa’s QPAC–CO2 code, which includes a novel soil–plant model that represents both fertilization and toxicity effects from elevated carbon dioxide concentrations. Good comparisons have been obtained between model calculations of surface venting patterns, soil gas concentrations and plant responses, giving confidence that the key features of the system are well understood. [Copyright &y& Elsevier]

Abstract: For any project that is supported by a risk analysis, the assessment generally needs to evaluate the consequences of health, safety and the environmental (HSE) impacts, and geological CO2 storage projects are no exception. To date, however, assessments of storage projects have focussed more on the performance of the storage reservoir in terms of its ability to contain the CO2 or at least prevent its leakage to the surface or near-surface environment, rather than determine the potential impacts of leakage of CO2 (and any gases such as H2S or radon that may be transported with the CO2) on specific environmental targets. This situation has been dictated to some extent by the lack of information or data on the nature of the potentially broad range of environmental impacts that might arise from elevated levels of CO2 in the environment. Thus, this paper provides input on two fronts: the results from (i) a scoping analysis of potential environmental impacts from a specific storage project, and (ii) a review of work being carried out on the potential environmental impacts that might be expected from geological CO2 storage projects. Of the two cases considered as a basis for deriving limiting leakage of CO2 from the geosphere, the CO2 leakage to a potable aquifer provides the overall limiting case under the conditions considered in this study. The review of the current literature on potential environmental impacts indicates that information and data are lacking in a number of areas, to the extent that some prioritisation will be necessary to focus technical work on specific ecosystems in order to make significant progress in the short term. [Copyright &y& Elsevier]

Abstract: This paper provides a preliminary assessment of the potential impact that future demand for groundwater might have on the commercial deployment of carbon dioxide capture and storage (CCS) technologies within the United States. A number of regions within the U.S. have populations, agriculture and industries that are particularly dependent upon groundwater. Moreover, some key freshwater aquifers are already over-utilized or depleted, and others are likely to be moving toward depletion as demand grows. The need to meet future water demands may lead some parts of the nation to consider supplementing existing supplies with lower quality groundwater resources, including brackish waters that are currently not considered sources of drinking water but which could provide supplemental water via desalination. In some areas, these same deep saline-filled geologic formations also represent possible candidate carbon dioxide (CO2) storage reservoirs. The analysis presented here suggests that future constraints on CCS deployment–due to potential needs to supplement conventional water supplies by desalinating deeper and more brackish waters–are likely to be necessary only in limited regions across the country, particularly in areas that are already experiencing water stress. [Copyright &y& Elsevier]

Abstract: In August 2007, Petrobras and IFP have initiated a common research project on Carbon Capture Storage to determine the feasibility of CO2 injection and underground storage in an oil field located in Recôncavo Basin, a mature basin of northeastern Brazil. Petrobras has a strong experience of more than 15 years in the management of CO2 for EOR and aims to develop a long term vision of CO2 permanent storage. IFP is developing an ambitious R & D program on CCS for knowledge acquisition and technology development on the all chain, both under in-house projects and large collaborative efforts (EU project CASTOR, CO2STORE, CO2ReMoVe…). The aim of the first phase of the project is to take the opportunity of the existing CO2 injection for more than 15 years in the Buracica oil field for the development and validation of technology needed for CO2 storage. The main reservoir unit is predominantly constituted of eolic sandstone facies and is isolated from the other reservoirs by a shaly sand barrier. The cap rock is a thick clay formation. The CO2 was only injected in the top reservoir of the field. A unique program was design to combine detailed experimental and modeling work to assess the impact of CO2 injection on the storage. Both petrophysical and mineralogical changes will be assessed along the CO2 path within the reservoir from the injection to the production wells. One of the main goals is to asses the rock/fluid interactions due to CO2 injection and the different reactions that took place along the CO2 migration path within the reservoir and its impact on the cap rock. The aim is to provide a documented data set to enable reaction transport modeling benchmarking. To complement the standard monitoring measurements, geochemical monitoring will be initiated both at reservoir and surface level to ensure storage integrity after CO2 injection. The paper presents the main features of the project, as well as the results attained so far. [Copyright &y& Elsevier]

Abstract: The paper describes a CO2 sequestration pilot test being conducted i n northwestern North Dakota in a lignite coal seam. Laboratory and field tests conducted to date indicate that the lignite provides a viable target for CO2 sequestration while, as could be expected, potential for methane production from lignite is questionable. It is suggested that in the future evaluation of gamma-ray logs and vertical pressure profiles can improve performance of enhanced coalbed methane production from lignites. [Copyright &y& Elsevier]

Abstract: This paper is the first of a series that attempts to assess the possible health and safety risks associated with large scale CO2 sequestration in deep brine reservoirs. The approach is based on analysis of available data on the operational track record from CO2 transportation and injection associated with enhanced oil recovery (CO2-EOR) in the US. This paper is particularly concerned with identification of the main business risks facing a company engaged in geological sequestration. Such risks include both the operational risks of capturing, compressing, transporting and injecting CO2, as well as the risk of accidental, rapid CO2 release from wells (including an analysis of blow out data from CO2 injection wells, worked over wells as well as abandoned wells). Observations of the outcomes from accidents in real pipelines and CO2 injection wells in CO2-EOR projects provide the most concrete basis to predict the future safety of the above ground operations of CO2 sequestration in deep brine reservoirs. [Copyright &y& Elsevier]

Abstract: Geologic sequestration of CO2 in an oil reservoir is generally considered a different category than sequestration in formations that contain only brine. In this paper, the significance and validity of this conceptualization are examined by comparing the performance of CO2 injected into a depleted oil and gas reservoir with the performance of similar injection into non-oil-bearing sandstones using a field test at Cranfield field, Mississippi, as a case study. Residual oil and gas in the reservoir under miscible conditions reduces CO2 breakthrough time and rate of pressure buildup as compared to a reservoir containing only brine. Dense wells provide improved assessment of oil reservoir quality, leading to improved prediction, as well as verification of CO2 movement in this reservoir as compared with the sparsely characterized brine leg. Assessment of the difference made by the presence of residual oil and gas requires a good understanding of reservoir properties to predict oil and gas distribution. Stratal slicing, attribute analysis, and petrographic analyses are used to define the reservoir architecture. Real-time pressure response at a dedicated observation well and episodic pressure mapping have been conducted in the reservoir under flood since mid2008; comparison measurements are planned for 2009 in downdip environments lacking hydrocarbons. Model results using a CMG-GEM compositional simulator compare well in general to measured reservoir response under CO2 flood; imperfections in the model match of flood history document uncertainties. Time-lapse Reservoir Saturation Tool (RST) logging is under way to validate fluid composition and migration models. Monitoring performance of the wells during injection of CO2 suggests at this site that the value of wells for characterization exceeds the risk of leakage. [Copyright &y& Elsevier]

Abstract: In this paper, we present the results of geophysical and geochemical observations at the Nagaoka site, where the first Japanese project on CO2 geological storage is currently underway. We collected formation water and rock samples from the reservoir, and conducted laboratory experiments to investigate the seismic wave response and geochemical reactions due to the CO2 injection under simulated in situ conditions. The results of time-lapse crosswell seismic tomography indicate an area of P-wave velocity decrease due to CO2 saturation, and the CO2-bearing zone near the injection well expanded clearly along the formation up dip direction during CO2 injection. The presence of CO2 was also identified by induction, sonic and neutron logging at the observation wells. The results of geochemical reactions demonstrated the potential of reservoir sandstones at the Nagaoka site for the effective solubility, ionic, and mineral trapping of CO2. [Copyright &y& Elsevier]

Abstract: This paper reports the well design, drilling and completion operation as well as the coring technique applied in the CO2SINK project. Three boreholes, one injection well and two observation wells have been drilled to a total depth of about 800 m. 200 m of recovered 6” core material has been real-time analysed in a research field lab. The wells have been completed as “smart” wells, containing a variety of permanently installed down-hole sensors for the continuous monitoring of the CO2 in the reservoir. All wells were cased with stainless final casings equipped with pre-perforated sand filters in the reservoir zone and wired on the outside with fiber-optical and multi-conductor copper cables. The reservoir casing section is externally coated with a fiber-glass-resin wrap for electrical insulation. [Copyright &y& Elsevier]

Abstract: Italy is one of the most promising prone areas to study the CO2 behavior underground, the caprock integrity to the CO2 leakage, mostly in presence of pervious/geochemically active faults, due to a wide availability of CO2 rich reservoirs at a depth between 1 and 10 km, as highlighted by recent literature. These deep CO2 reservoirs generate at least 200 leakage areas at surface throughout Italy which have been defined “Diffuse Degassing Structures” (DDS) by INGV. These are widely studied by INGV institutionally by a long term convention with the Civil Protection Department (DPC) with the aim to catalog, monitor and assess the Natural Gas Hazard (NGH, namely the probability of an area to become a site of poisonous peri-volcanic gas exhalation from soils). More than 150 researcher of INGV are involved in monitoring areas affected by the CO2 presence underground and at surface, by continuous monitoring on-line networks (around 40 stations throughout Italy, including the Etna area, Aeolian Islands, Umbria region, Piemonte region, etc.) and discretely (9 groups of research were involved in the last years to localize, define and monitor almost all the DDSs in Italy), by sampling and analyzing chemical and isotopic compounds, useful to discriminate the origin, evolution and natural gas hazards of the examined DDS. In this paper, we will discuss some DDS catalogued and studied by a Rome INGV Research Unit (UR 11) which focused its work in Central Italy, throughout different DDS, also in relation to the diverse seismotectonic settings, to discover buried faults as possible gas leakage pathways, mostly if they are “geochemically” activated. In particular we discuss, among the discrete monitoring techniques exploited by INGV, soil gas surveying, which consists in a collection of gas samples from the soil zone not saturated (dry zone) to measure the geogas gaseous species both in fluxes (CO2, CH4, 222Rn) and in concentration (He, H2, H2S, helium, hydrogen, CO2, CH4, 222Rn), that permeate the soil pores. The total CO2 flux budget was calculated as “baseline” degassing rate of these “ CO2 analogues”. A good discrete areal monitoring is prerequisite to design sound continuous monitoring network to monitor CO2 related parameters in liquid/gas phases, to review the protocol of the Annex II of the European Directivity on CCS. [Copyright &y& Elsevier]

Abstract: The effects of global climate change due to increased greenhouse gas emissions are a growing concern. It is important that technology-based solutions be evaluated in the event they need to be implemented. One method of mitigating anthropogenic CO2 emissions is through geologic storage or sequestration. Most efforts involving Carbon Capture and Storage (CCS) focus on CO2 injection in deep geologic formations. Two issues that arise with CCS technology are public acceptance and monitoring of the horizontal and vertical movements of the CO2 plume. With most CCS sites the risk for leak will be extremely low; however, it will be critical to assure the public of their safety. One way to mitigate public concern is through an integrated surface monitoring campaign. Natural surface background CO2 fluxes must be understood to characterize potential leak sites. LI-COR Biosciences has developed the technology to aid researchers in monitoring potential surface leak sites in areas where CCS is implemented. The LI-8100 Automated Soil CO2 Flux System measures diffusion of CO2 from the soil into the atmosphere, and the LI-7500 Open Path CO2/H2O Analyzer, when integrated with a sonic anemometer, can measure the CO2 flux over a large area. In this paper we discuss these two monitoring methods in detail and present data that illustrates the need for natural surface flux measurements in areas where CCS will be implemented. We will also provide examples of how this technology is currently being used for monitoring CO2 injections at geologic storage sites. [Copyright &y& Elsevier]

Abstract: The Krechba field is one of several gas fields located in the Algerian Sahara desert, and was set in operation in August 2004 as part of a joint venture with BP, Sonatrach and StatoilHydro. The natural gas in the fields contains up to 10% CO2, which has to be reduced to 0.3% before the gas is sold, resulting in the production of around 1 million tonnes/year CO2. Rather than vent the CO2 to the atmosphere (business as usual), it is re-injected into the water leg of the Krechba Carboniferous Sandstone gas producing reservoir (20 m thick) via three horizontal wells at a depth of around 1,900 metres. CO2 injection started in August 2004 and to date nearly 2.5 million tonnes of CO2 have been injected, amounting to approximately 25% of the gas extracted from the Krechba field over the same period. A number of key technologies to monitor the injection, and the subsurface movement and storage of CO2 have been, and will continue to be, deployed to provide long term assurance of sequestration. Time lapse satellite images (using PSInSARTM Technology) which measure ground deformation to assess the movement of CO2 in the subsurface have proven to be much more successful than initially thought, despite the depth of injection and the low voidage replacement rate (25%). Satellite images collected since start of injection show clear increases in ground elevation of up to 30mm around the three injectors while subsidence is also apparent in the area of maximum gas production. The images have also confirmed the CO2 is moving in the direction of preferred fracture orientation at reservoir level. Recent downhole pressure measurements in one of the injectors also indicates that the CO2 is being contained within the injection horizon. Work is ongoing to integrate the satellite images with geomechanical and seismic data to better understand how these images can be used for monitoring of CO2 movement in the subsurface. A key part of the forward monitoring programme will be the acquistion of time-lapse 3D seismic, deployment of tiltmeters and GPS to confirm and calibrate the satellite imagery data, microseismic detectors in shallow boreholes to assess the degree of rock strain and use of shallow wells to monitor the water chemistry in the vadose zone. These will supplement the ongoing tracer, wellhead sampling and satellite imagery data acquistion. This paper shares the latest results of the ongoing CO2 monitoring project. [Copyright &y& Elsevier]

Abstract: The creation of a robust Baseline, Monitoring, and Verification (BMV) plan is key to assuring containment integrity in CO2 geological storage projects. A BMV plan has three main aims: Monitor CO2 movement in the subsurface, Calibrate dynamic earth models and finally, Verify volume of stored CO2. Wide ranges of potential BMV technologies available are currently tested in CCS pilots and industrial scale projects. This paper describes how to optimize the BMV plan design by adopting a risk-based approach and how the value of information (VOI) of specific monitoring technologies needs to be assessed to meet program objectives. [Copyright &y& Elsevier]

Abstract: Minimizing the cost of large-scale geologic storage of CO2 is a paramount concern, and consequently many aquifer storage projects may be implemented without a detailed characterization of the target formation. On the other hand, CO2 migration beyond the volume designed for effective trapping is a paramount risk. Thus, inexpensive methods of monitoring the plume movement will be valuable for operators and regulators alike. Unanticipated heterogeneities within the target formation, whether high-permeability channels or low permeability barriers, are one of the most likely causes of migration beyond the design volume. We propose that routine measurements of injection rate and injection pressure in each well can be used to infer the existence of heterogeneities large enough to affect the plume path. We do not seek from these measurements a detailed spatial distribution of permeability in the formation, but merely an indication of features that affect the overall migration path. The advantage of this approach is that these measurements will be acquired routinely, frequently and cheaply in all projects, whereas methods yielding higher resolution (time-lapse seismic surveys, electromagnetic surveys, cross-well seismic, monitoring wells, etc.) are specialized and expensive. We have implemented this idea by combining (i) our previously developed research software (Pro-HMS) which carries out geologically consistent parameter estimation from injection and production data and (ii) a commercial compositional simulator (GEM from CMG) as a forward model which has been tuned to the full physics and phase behavior of the CO2/brine/rock system. In this paper we test the approach on model aquifers that exhibit permeability heterogeneity prescribed by a spatial correlation model. The permeability estimation process is performed within a fully probabilistic framework. We include the noise typical of pressure/rate data from real wells and find that signal of large heterogeneities can still be discerned. [Copyright &y& Elsevier]

Abstract: Monitoring is essential to assess whether sequestered carbon dioxide (CO2) behaves as expected and whether unexpected migration or leakage occurs. A variety of monitoring techniques have been proposed and examined. Although those techniques provide useful information, such as CO2 migration and distribution, individual information yields only limited insight into CO2 behavior in geological reservoirs. To deepen our understanding of migration and containment of sequestered CO2, a monitoring framework must be established to comprehend the individual sources of information. This paper describes the monitoring framework that was applied to a test field of CO2 sequestration conducted at an onshore site in Nagaoka, Japan. The target aquifer was the early Pleistocene sandstone bed, around 60m thick and 1,100 m below the ground surface. During the 550-day injection period, around 10,000 tonnes of CO2 were sequestered. Three monitoring wells were completed around an injection well and several monitoring schemes, including pressure and temperature measurements, well logging, crosswell tomography, in-situ fluid sampling, were applied. Based on the monitoring results, meso-scale as well as macro-scale migration is examined and discussed. This study addresses monitoring issues in an integrated framework, with emphasis on the importance of comprehensive analyses, since they can bridge the gap between the individual monitoring results. [Copyright &y& Elsevier]

Abstract: Recent CO2 sequestration pilot projects have implemented novel approaches to well-based subsurface monitoring aimed at increasing the amount and quality of information available from boreholes. Some of the drivers for the establishment of new well-based technologies and methodologies arise from: (1) the need for data to assess physical and geochemical subsurface processes associated with CO2 emplacement; (2) the high cost of deep boreholes and need to maximize data yield from each; (3) need for increased temporal resolution to observe plume evolution; (4) a lack of established processes and technologies for integrated permanent sensors in the oil and gas industry; and (5) a lack of regulatory guidance concerning the amount, type, and duration of monitoring required for long-term performance confirmation of a CO2 storage site. In this paper we will examine some of the latest innovations in well-based monitoring and present examples of integrated monitoring programs. [Copyright &y& Elsevier]

Abstract: A critical component of long term geological sequestration of anthropogenic CO2 will be our ability to adequately monitor a chosen site to ensure public and environmental safety. Near surface monitoring is particularly important, as it is possible to conduct sensitive and direct measurements at the boundary between the subsurface and the biosphere (i.e. surface water or atmosphere). While discontinuous surface monitoring is often performed, continuous monitoring is preferable if one hopes to observe a leak in its early stages to allow for rapid remedial action. The geochemical signal that may result from a near-surface CO2 leak might take the form of increased soil gas concentrations (on land) or changing pH, Eh, and aqueous chemistry (in groundwater or surface water), and thus continuous monitoring stations capable of analyzing for these parameters have great potential for early leak detection. In the framework of the EC-funded CO2GeoNet and CO2ReMoVe projects innovative monitoring systems have been designed and constructed for autonomous deployment in marine environments above geological CO2 storage sites. The system developed within CO2GeoNet was tested at a site in the Gulf of Trieste where there is no gas release; this site was chosen due to easy access and the presence of an existing oceanographic buoy onto which the monitoring station was mounted. Tests on this early prototype highlighted the various difficulties of working in marine environments, and this experience formed the basis for a new system developed for deployment at the Panarea test site within CO2ReMoVe. This second site is located off the coast of Panarea Island, to the north of Sicily, where naturally-produced CO2 leaks from the seabed into the water column. The advantage of this site is that the leaks occur in a relatively near-shore environment (<300 m) and in water that is not too deep (<25 m), thereby allowing for easy access by SCUBA divers for system testing and maintenance. This location allowed the unit to be connected via cable, rather than a buoy, which makes power supply and data transfer simpler. The system developed for this site consists of three monitoring points that are connected to a land-based control unit. Each point, located 100, 200, and 300 m from shore in different CO2 flux regimes, is able to measure dissolved CO2 and CH4, conductivity, pH, and temperature using low cost but sensitive sensors. The complete system consists of flexible solar panels, a central control unit and three monitoring points, and data download is conducted using a GPRS connection and a web server. Difficulties with the initial deployment in early April of 2008 has necessitated further development work, with the second deployment planned for early November. The following paper discussed the experience gained with these stations, and presents data analysis and anomaly recognition from a land-based monitoring station that has been collecting dissolved CO2 data for over 18 months. [Copyright &y& Elsevier]

Abstract: Through the use of analytical solutions derived from a simplified geologic model, this paper investigates the magnitude of pressure transients in permeable zones overlying CO2 storage reservoirs associated with brine migration through the sealing cap rock. A wide range of geologic settings and injection parameters is evaluated from which a generalized correlation is constructed to relate the hydrologic properties of the storage reservoir and seal to the magnitude of expected pressure buildups associated with brine migration across the seal. This correlation, referred to as the detection factor (DF), provides insight into the feasibility and interpretation of pressure changes measured in zones overlying CO2 storage reservoirs as a means of monitoring and leakage detection. [Copyright &y& Elsevier]

Abstract: The development of a methodology for defining safety criteria for CO2 geological storage, realised under the ongoing CRISCO2 project, is depicted in this paper. Generic lists of eleven risk events and nine types of targets are proposed to serve an expert panel for identifying risk scenarios. Assessing the effects of risk events and comparing targets exposure to critical thresholds should lead to setting safety requirements. We focus on simple modelling, such as abacuses, analytical or semi-analytical models. An uncertainty management framework completes this methodology. Further work will concentrate on effectively deducing safety criteria. [Copyright &y& Elsevier]

Abstract: This paper reports the results of an environmental impact assessment (EIA) of a hypothetical 400 MWe IGCC power plant fitted with CO2 capture technology and includes the transportation of CO2 via a high pressure pipeline to a geological formation under the North Sea and subsequent storage. The emphasis has been on assessing environmental impacts from those features which are specific to the Carbon Capture and Storage (CCS) technology and includes an appraisal of the current adequacy of information to enable EIAs for the power plant, transportation and storage components to be undertaken. [Copyright &y& Elsevier]

Abstract: Containment is a key factor of geological CO2 storage: small, localized leaks could have consequences to health and safety (e.g. CO2 accumulation in cellars) and the environment (e.g. drinking water pollution). On the other hand, large leaks could affect wide areas and large populations, and could reduce the overall economic and environmental benefit of the CO2 storage site and of Carbon Capture and Storage (CCS) in general. Containment potential over hundreds of years is affected by unknowns and uncertainties, and it is therefore appropriately dealt with in the framework of risk analysis. One way of estimating containment risk is to use quantitative simulators: if properly calibrated they can predict leakages through potential pathways and, if used properly in a probabilistic framework (e.g. through a Monte Carlo approach), can take into account uncertainties and produce probability distributions of CO2 leaks. This paper will discuss how different methodologies for estimating risk from probability distributions of releases of substances can be reconciled in a consistent, unified approach that can be rigorous or simplified according to the state of knowledge and the degree of detail required in the calculation. [Copyright &y& Elsevier]

Abstract: Uncertainties related with underground CO2 storage play a vital role in risk assessment with respect to Carbon storage and capture projects (CCS). The main purpose of risk assessment is to determine a qualitative and quantitative picture of hazardous processes or events. One makes a comprehensive inventory of risk factors, and stores the results in a FEP (Features, Events and Process) database. The properties of the geological system itself and natural or human -induced processes determine the future system p roperties. The FEP’s may interact. In this paper we propose to describe this interaction of FEPs within the framework of (discrete time) Markov Chains. In such an approach various states are defined. The system can ”jump” from one state to another. The probabilistic evolution of the system can be followed, and conclusions can be drawn as to visit times of the various states. Also, the most likely ultimate fate of a system in dependence of initial state can be determined. This approach offers a comple mentary supporting tool for scenario-thinking, as it takes into account the evolution of all possible follow -ups of relevant physical processes and events quantitatively. It is not about just following a few scenario’s. Without the machinery of Markov Chains this can hardly be done in full. An added bonus of this approach is that questions of policy makers, and of licensing authorities can be answered in a numerical way. [Copyright &y& Elsevier]

Abstract: The main objective of the research reported in this paper was to address the uncertainties associated with coal seam reservoir performance during and after CO2 injection in order to establish a methodology for the design, prediction and risk evaluation of safe and environmentally sound CO2 storage in coal seam reservoirs. Full field scale simulations up to 1,000 years with over 140 permeability realisations and various swelling coefficients and sorption isotherms have shown that controlling the injection well bottomhole pressure ensures no overpressuring of the coalbeds or the caprock. Long-term leakage simulations with high cement deterioration and CO2 leakage rates have shown that the likelihood of a leakage of 1% of the total volume of CO2 stored over 1,000 years is low, and can be mitigated against through careful operational planning and reservoir management during CO2-ECBM and CO2 storage. [Copyright &y& Elsevier]

Abstract: Carbon dioxide capture and storage (CCS) can contribute to stabilizing atmospheric content of carbon dioxide (CO2) provided that it can deliver long-term storage containment. Satisfying this condition requires understanding and representing uncertainty in the underground. One of the major containment failures is due to opening of new or existing fractures or faults, or ingress through the cap rock barrier. In this study semi-analytical methods (e.g. first- and second-order reliability methods) are used to analyze and understand this isolated containment failure mode. This paper gives a brief introduction and description of the mathematics of the reliability method and how it can be applied to analyze the failure probability of CO2 geologic storage using commercially available software. [Copyright &y& Elsevier]

Abstract: This paper proposes an alternative theoretical methodology to evaluate the risks of CO2 leakage from reservoirs using a stochastic approach. The methodology suggested here makes use of three main concepts: [–] Features, Events and Processes (FEPs) [–] Interaction Matrix, IM [–] Stochastic Representation Both, FEPs and Interaction Matrix have been introduced by other researchers but for different objectives. The methodology that is proposed here modifies the original concept of Interaction Matrix in such a way that it may produce probabilistic results as outcome. A practical example is given at the end of this paper. [Copyright &y& Elsevier]