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Abstract: High- CO2 gas fields serve as important analogues for understanding various processes related to CO2 injection and storage. The chemical signatures, both within the fluids and the solid phases, are especially useful for elucidating preferred gas migration pathways and also for assessing the relative importance of mineral precipitation and/or solution trapping efficiency. In this paper, we present a high resolution study focused on the Gorgon gas field and associated Rankin Trend gases on Australia’s North West Shelf. The gas data we present here display clear trends for CO2 abundance (mole %) and δ13C CO2 both areally and vertically. The strong spatial variation of CO2 content and δ13C and the interrelationship between the two suggests that processes were active to alter the two in tandem. We propose that these variations were driven by the precipitation of a carbonate phase, namely siderite, which is observed as a common late stage mineral. This conclusion is based on Rayleigh distillation modeling together with bulk rock isotopic analyses of core, which indicates that the late stage carbonate cements are related to the CO2 in the natural gases. The results suggest that a certain amount of CO2 may be sequestered in mineral form over short migration distances of the plume. [Copyright &y& Elsevier]

Abstract: In-situ CO2 capture in coal utilization captures CO2 during coal combustion or gasification such as Oxygen fuel combustion or HyPr-RING. coal gasification processes. Regarding Oxufuel combustion, Callide Oxyfuel Project has been being conducted as the world first project to apply the technology to an existing power plant, Callide A Power Station #4 unit (30MWe) with injection of captured CO2 into the underground. This is a Japan-Australia collaboration project and JCOAL participates in it as a supporting collaborator. JCOAL also proposed a novel coal gasification method-,HyPr-RING (Hydrogen Production by Reaction-Integrated Novel Gasification). HyPr-RING method utilizes a chemical looping with the calcium cycle, in which CaO (or Ca(OH)2) captures CO2 during coal gasification completely to form CaCO3 and release heat for gasification to produce near pure hydrogen in one gasifier. This paper introduces the current developing status of the HyPr-RING method, mainly including the experimental examination of the transition of sorbent particle size distribution, ash and sulfur concentration of materials at several locations of gasification and calcination system for the HyPr-RING process. And the plant cold gas efficiency which should be affected by ash separation was also analyzed. As the results, it was found that coal ash and sulfur concentrated highly in the process of calcination after cyclone. If it is possible, separate and remove ash and sulfur by applying devices like filter or/and cyclone separator, the plant coal gas efficiency may raise 2 points than that in the previous study in which a part of recycled sorbent was rejected without separation. One method for reducing CO2, the green house gas emissions is to capture CO2 before it releases into the atmosphere and then sequestrate it. Active lime (main component, CaO) can be used to capture CO2 in the exhaust gas or in the reactor from fossil fuels utilization effectively. That is calcium oxide (CaO) absorbs CO2 to yield calcium carbonate (CaCO3) (Eq.(1)), then the CaCO3 is thermally decomposed to CaO again and release nearly pure CO2 (Eq. (2)) for sequestration. To obtain a nearly pure CO2 stream from CaCO3 decomposition, the heat for decomposing CaCO3 can be supplied by combusting fossil fuels, such as coal and natural gas, in a calciner with oxygen fuel combustion. The oxygen diluted by CO2 (CO2 cycle) or H2O (steam cycle), in order to obtain near pure CO2 stream from CaCO3 decomposition. In our previous studies4−6, it was clarified that calcinations of limestone (main component, CaCO3) in a fluidized bed calciner can be performed in CO2 cycle atmosphere when the bed temperature was raised above 1293 K, whereas with 60% steam cycle in atmosphere, limestone can be decomposed at comparatively lower temperature, such as 1173 K. The decomposition conversions of the limestone were about 95% and 98%, in CO2 cycle and in steam cycle atmospheres, respectively. Reducing the calcinations temperature of limestone was helpful to produce more than 30% active CaO as shown in previous study4−6. In this study, the energy of CaCO3 calcination process by H2O (steam) cycle was analyzed and compared with CaCO3 calcination process by CO2 cycle. For process calculations, the mass and energy flows were calculated iteratively, based on the input and output balances, until err [(input-output)/input] was <0.01. Analysis showed that, although H2O (steam) cycle calcination had calcination energy more about 3.6% than CO2 cycle due to water evaporation latent heat loss, however, the calcination energy per active CaO was lowest for H2O (steam) cycle. [Copyright &y& Elsevier]

Abstract: The capture and the storage of CO2 in deep geological media are proposed to reduce the emission of CO2 to the atmosphere. While the argillaceous formations have been extensively studied since more than two decades as potential host-rocks for nuclear waste disposal, only few studies have dealt with the potential degradation of their containment properties as caprocks induced by a CO2 attack. This paper focuses on the impact of a CO2-enriched fluid on the diffusive transport parameters of indurated argillaceous samples originating from the massif of Tournemire (Aveyron, France). Two through-diffusion experiments were carried out, the first one with a CO2-enriched fluid and the second one with an equilibrated fluid, chemistry of which is very close to that measured in-situ. Non-radioactive (deuterium and bromide) and radioactive tracers (tritium and Cl-36) were successively used. Throughout the duration of the experiments, the evolution of water chemistry was monitored by measuring pH, Ca, Na, Mg, K, Cl, SO4, TOC and alkalinity. The effect of the CO2 stress has been clearly evidenced. On the one hand, the tracer fluxes in the downstream reservoir of the cell having undergone CO2 attack were up to 3 times higher than in the reference cell, indicating a significant increase of the porosity and effective diffusion coefficient values (up to 100% for Cl-36 porosity and up to 300% for Cl-36 effective diffusion coefficient). On the other hand, the chemical monitoring showed that magnesium, calcium and carbonate concentrations in the collection reservoirs increased up to one order of magnitude, suggesting a possible dissolution of some carbonate minerals such as calcite, reacting with the acid fluid. [Copyright &y& Elsevier]

Abstract: The performance of post-combustion CO2 capture processes depends on the applied solvent as well as on the chosen process configuration and the integration concept with the power plant. Siemens bases its development efforts on an amino-acid salt solution as solvent, which has a negligible environmental impact and provides favourable properties for a low-energy capture process. The solvent features a high chemical and thermal stability and is easy to handle. The capture process is characterized by near-zero emissions. As a first step for validation of the determined solvent and process features on an industrial scale, the implementation of the capture process in a pilot plant is required. For this purpose, Siemens has installed a pilot plant at E.ON’s coal-fired power plant Staudinger in Germany and started the operation in August 2009. The measured pilot plant process data are used to validate the computational process model, which refines the model accuracy and improves the reliability in terms of plant performance. The findings from pilot plant operation confirmed that an overall net plant efficiency penalty of less than six percentage points (without CO2 compression) for a state-of-the-art coal-fired steam power plant can be achieved. The paper also presents experiences from pilot plant measuring campaigns with regard to the impact of trace components such as SOx and NOx. Solvent losses due to related degradation effects can be minimized by an intelligent reclaiming concept. Loss due to oxygen degradation can be estimated to be less than one percent of hold-up per year. Suitable construction materials have been qualified. The results of the pilot plant operation will serve as basis for the implementation of a demonstration plant, which will be the final step before a full-scale commercial carbon capture plant project. Siemens has been selected as technology provider for the Meri-Pori Carbon Capture and Storage project in Finland, which is a potential funding candidate of the European Flagship Programme. The Meri-Pori power plant has an installed capacity of 565 MW and the capture demonstration project is supposed to treat half of the power plant’s flue gas and to capture 90% CO2 from the treated flue gas. In addition to the Siemens capture process, the demonstration project will include ship transportation and geological storage. [Copyright &y& Elsevier]

Abstract: Many aquifers suitable for CO2 sequestration contain measurable concentration of dissolved non-hydrocarbon species. In this paper, the compositional modelling of the CO2 injection into aquifers that contain dissolved hydrogen sulfide, described here as sour aquifers, is studied. According to the results of this study, when CO2 is injected into such aquifers, exsolution of dissolved components will occur and gaseous H2S will accumulate at the leading edge of the CO2 plume. At any time after the start of CO2 injection, the region swept by the plume consists of two sub-regions. An inner radial sub-region extending from the injection well is characterized by the absence of H2S in both the aqueous (brine) and gaseous (supercritical CO2) phases. The dissolved H2S in this first sub-region is almost completely removed from the brine and released to the migrating gas phase. The second sub-region extends from the outer edge of the first sub-region to the leading edge of the gas plume. In this outer sub-region, the mole fraction of H2S in the CO2 plume gradually increases toward a constant value at the edge (which is defined by the CO2-H2O-H2S phase equilibrium conditions at specific temperature, pressure, and salinity of the brine) and thereafter only the size of this sub-region progressively increases. For dissolved H2S concentrations typically found in the Western Canada Sedimentary Basin, mole fraction of gaseous H2S in the leading edge of the gas plume can be higher than 50%. This may have important implications for assessing the risk of CO2 injection into sour aquifers. Leakage into abandoned wells, for example, might plausibly occur when the gas phase first reaches the wellbore, so initial leakage may contain substantial amounts of H2S even though the average H2S fraction in the stored CO2 is quite small. H2S is highly toxic, with acute short term toxicity at 100 to 1000 times larger than that of CO2. This suggests that one need to account for this phenomenon when establishing risk assessment, monitoring and management strategies at planned CO2 geo-storage sites. [Copyright &y& Elsevier]

Abstract: In 2006, the CO2ReMoVe project funded by the European Commission was launched with the objectives of developing new and common methodologies and technologies to improve site based R&D for the monitoring, measurement and verification of the injection and storage of CO2 at multiple sites. The In Salah Gas Krechba Field Joint Industry Project has been in operation since 2004 when gas from several fields was put on production. To comply with export regulations, the high content of carbon dioxide (CO2), 1–10% in the produced gas is removed and re-injected down dip from the producing gas horizon, through three horizontal injection wells at approximately 1800 m below surface. Within the framework of CO2ReMoVe, this paper discusses the site characterization and the short term system performance for the In Salah Krechba field. Prior to the injection, the reservoir unit and the seals were characterized. The resulting geological (static) model is consistent with the information obtained from the drilling activities in 2004 and 2005 and from the reprocessed 3D seismic done by Compagnie Générale de Géophysique (CGG) in 2006. A fracture study carried out on information obtained from resistivity and acoustic images available on the Krechba field had shown the existence of an open fracture network oriented along the NE-SW direction parallel to the maximum stress direction. Typically, monitoring data serves as a calibration yardstick for the static model. It was therefore valuable information to detect the CO2 breakthrough at KB-5, a suspended well located 1.7 km away from the KB-502 injector well. Tracer analysis confirmed the CO2 detected at KB-5 came from KB-502. A multi-phase, multi-component compositional simulator specially designed for CO2 sequestration (ECLIPSE 1 [1] Mark of Schlumberger. 300 with the CO2SOL option) was used to simulate and predict the properties of the injected carbon dioxide as well as that of the gas in place (mainly methane) and of the saline aquifer. History matching was used to calibrate the dynamic model by iteratively modifying parameters until a satisfactory match between model results and field measurements was obtained. The resulting dynamic model is used for short term predictions of the behaviour of injected CO2. The history matching parameters are the fracture porosity, permeability and matrix permeability (difficult to measure permeability in a fractured medium). In each iteration, the simulated bottomhole pressures, gas (CO2) injection rates were compared against field data as well as the CO2 breakthrough time at KB-5. Iterations were repeated until a good match was obtained. Predictive simulation results indicate that CO2 would reach the northern part of the gas field in 2010 and would spread out over an area including production wells in 2015, both in the northern (KB-502, KB-503) and the eastern part (KB-501) of the gas field. Although a good match has been obtained in the history matching process, some observed discrepancies could still not be explained only by fluid dynamics. Possibly, the application of coupled fluid flow and geomechanical simulations would aid in explaining the remaining discrepancies. [Copyright &y& Elsevier]

Abstract: Experimental studies about supercritical CO2-brine displacement are necessary to understand the detailed flow process of injected supercritical CO2 in deep saline aquifers. This article adopts experimental method to research the supercritical CO2 and water flow in porous media, using MRI as visualization and measurement method. Supercritical CO2 and water are injected into the sintered glass porous media structure by different mixture ratios. The sintered glass porous media structure is designed with the fissure defect. Visualization and analysis results simultaneously demonstrate that supercritical CO2 saturation and distribution vary with different ratios. The CO2 saturation increases with elevation in CO2-water ratio. And the CO2 distribution is significantly influenced by the buoyancy force and the supercritical CO2 will tend to migrate to the top of the test section. This paper also investigates the fissure effect. More supercritical CO2 will migrate to the top when encounters the fissure defect, and therefore the cap rock has to withstand bigger pressure, which will reduce the safety of carbon geological storage. [Copyright &y& Elsevier]

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

Abstract: The Devonian Nisku formation in central Alberta is potentially a suitable aquifer for CO2 sequestration. As with many Devonian aged aquifers in the Western Canada Sedimentary Basin, it contains H2S from thermochemical sulfate reduction. In spite of this, the Devonian Nisku represents a potentially desirable location as it is at the correct depth to ensure that CO2 is in the supercritical phase, it has multiple impermeable and low permeability barriers and there is very little hydrocarbon production in the formation. This paper presents a modeling study of the injection phase of CO2 into a saline aquifer in the Devonian Nisku formation at Wabamum Lake in Central Alberta. The object of the study is to evaluate the differences and problems, if any, between injection into a brine with an ambient amount of dissolved H2S and without dissolved H2S. The simulation covers a CO2 injection period of 50 years at a rate of 1 Mt/year. A one dimensional, radial symmetric model was used with a uniform carbonate composition. The mineral composition was from the Upper Nisku formation and a water composition from a producing water well in the Nisku formation. The model found that injected CO2 was stored as ionically trapped bicarbonate in a region of varying widths, 300 m wide after 1 year of injection to 3000 m wide after 50 years of injection represents from 2% to 3% of injected CO2. Small amounts are also trapped as calcite and dolomite. The H2S in solution does exsolve as gas during injection but this result is inconclusive due to the small amount of dissolved H2S present in the ambient brine. Overall, there were no noticeable differences between the models with and without ambient H2S in the brine. [Copyright &y& Elsevier]

Abstract: E.ON and Electrabel are jointly developing the ROAD (Rotterdam, Opslag en Afvang Demonstratie) CCS project, to demonstrate capture, transport and storage of CO2 at a scale of 250 MW equivalent. The ROAD project has now been under development for one year and several challenges have come up and have been overcome by the project team. Funding for the project has now been secured from different sources including the European Commission and the Dutch Government. This funding enables the project development, and each source set their own requirements for the project, which lead to project challenges. This paper outlines the most important of these challenges. It briefly describes Front End Development theory on project development as used in oil and gas industry and illustrates that the constraints will force the project team to deal differently than preferred in theory. Possibly this might lead to a price to pay for the project, but theory cannot be applied without risk of losing funding. Hopefully this article can contribute as well to the development of other CCS projects. [Copyright &y& Elsevier]

Abstract: To fulfill the energy demand now and in the next decades, coal-fired power plants will be an essential part of the portfolio of power plants that supply electricity cheaply and in a reliable way. The specific CO2 emissions of these plants can be reduced by increasing the efficiency. For that reason KEMA did optimize the steam water cycle of ultra super critical (USC) coal-fired power plants within the EOS program. The improvements are based on the application of the so-called Master Cycle, and on the application of higher steam temperatures. In the Master Cycle cold reheat steam is used in an extra turbine and with steam extraction of this turbine feed water preheating is realized with reduced exergy losses. The turbine is called a tuning turbine reflecting the improved possibilities to tune and optimize the steam cycle with the new coupling where the regenerative heater train and the re-heaters have been decoupled. The Master Cycle is proposed by Dong Energy . The first approach deals with the USC technology with a steam temperature of 600 °C and reheat temperatures of 620 °C. This technology is available at the moment and is applied in new built coal-fired power plants. The second approach deals with the USC technology with a steam temperature of 700 °C and reheat temperature of 720 °C. The expectation is that this technology can be applied around 2025 with the same availability as the USC units with 600 °C. The thermodynamic analyzes are carried out with KEMA’s flow sheeting package SPENCE®. In all considered cases the thermal input was 2400 MWth. In case of the application of the Master Cycle a second reheat is introduced. Results will be discussed and presented in tables, t-s diagrams and h-p diagrams. Improvement of efficiency of coal fired power station technology can reduce the amount of CO2 emitted significantly. This paper shows that with current available technology and improvements an additional emission reduction of almost 10% can be realised by applying the USC 700 + MC. Compared to the world wide average an emission reduction of 66% can be achieved without CCS. In the continuation of the analysis post combustion technology will be integrated in the concept to analyze possible additional benefits of the master cycle with respect to steam supply for the regeneration of the solvents. [Copyright &y& Elsevier]

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

Abstract: This paper assesses several options for configuring the CO2 transport and storage chain. In the first part, various ways to configure transport infrastructure are compared in a qualitative manner. It is shown that while the large-scale transport options score much better in terms of cost-effectiveness, they are not likely to emerge in nascent CCS initiatives because of the high investments and risk involved. In the second part, it is shown that configuring a cost-effective transportation link is necessary when the most attractive storage fields are not located near the point sources of CO2. In the last section, two broad approaches towards rolling out a CCS infrastructure are outlined: the “push” approach in which infrastructure is oversized in anticipation of future volumes, and the “pull” approach whereby infrastructure is tailored for the assured CO2 flows. [Copyright &y& Elsevier]

Abstract: The most promising process for Post Combustion Carbon Capture (PCC) is reactive absorption. For the design and scale-up of this process, reliable process models are needed. To achieve this, the models need to not only reliably describe the physical and chemical equilibria in the reacting systems but also to account for both mass transfer and reaction kinetics. Consequently, the models are complex and contain a large number of input parameters for describing fluid dynamics and physico-chemical properties. In order to assess the required quality of the input, the sensitivity of the simulation results to the parameters has to be known. This paper presents results from such a sensitivity study for a typical operating point of a PCC pilot plant with 0.3 g/g monoethanolamine (MEA) in water as the solvent. A rate-based model and its input parameters are introduced and describe the pilot plant results well. The most relevant input parameters of the model are systematically varied and the influence of that variation on the simulation results is monitored. Absorber and desorber are considered separately. The results are sensitive to most of the studied parameters. High sensitivities are found for the interfacial area, the Henry’s law constant and the enthalpy of absorption as well as for the parameters describing the equilibrium and kinetics of the carbamate formation and the amine protonation equilibrium. [Copyright &y& Elsevier]

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

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

Abstract: Both field experience and lab data indicate that the corrosion rate of carbon steel in pure dense phase CO2 is near zero if no free water is present. The question is whether this also applies when other contaminants like SO x , NO x , H2S and O2 are present in moderate amounts. In a pipeline network with different types of CO2 sources, the commingling of streams with various impurities can give a very complex mixture, and side reactions like oxidation and decomposition of impurities can be foreseen. An important issue is how the contaminants partition between the various phases during pressure reduction and when free water is present. The corrosion mechanisms under these conditions are not well understood, and it becomes more and more uncertain what will happen when the concentration of contaminants including water increases. The paper addresses these issues and discusses recent corrosion flow loops and autoclaves results obtained in an ongoing sub-sea CO2 transmission pipeline project. [Copyright &y& Elsevier]

Abstract: Local projects on carbon storage that have been started in Germany in recent years have induced positive to neutral reactions as well as strong opposition by the local public. In this paper, a comparative case study of two storage projects is presented: The first case under study is the CO2 Sink research project at Ketzin which has started to inject CO2 in 2008 and has been well accepted by local politicians and the local public. It is compared to a project initiated by Vattenfall at Beeskow where Vattenfall wants to explore whether the region is suitable for large scale commercial on shore storage and has met strong local opposition by several societal stakeholders. Cases are compared regarding project properties, communication strategies and public perception, as well as local context and history in order to identify factors that contributed to the respective positive or negative reaction. [Copyright &y& Elsevier]

Abstract: CO2 capture and storage (CCS) will have a significant impact on the cost of electricity production and costs in other potential applications. Hence, there is a need to identify and structure transportation alternatives in order to fill the gaps in knowledge of the cost of integrated capture, transport, and storage processes. As part of the EU China Cooperation project (COACH), a case of transporting 4,000 tonnes of CO2 per day from GreenGen IGCC Project in Tianjin to Shengli Oilfield at a distance of 300 km in China has been outlined and subjected to parametric studies. The paper reveals the details of these cost analyses and results pertaining to three alternatives: a) pipeline transport, 43.13 RMB/tonne CO2 (4.3 € /tonne CO2), b) shipment, 45.79 RMB/tonne CO2 (4.6 € /tonne CO2), and c) railway tank wagon transport, 77.35 RMB/tonne CO2 (7.7 € /tonne CO2). [Copyright &y& Elsevier]

Abstract: This paper presents a structured qualitative approach to analysing the varied kinds of information from a CO2 storage site, so as to produce scenarios that are amenable to numerical analysis. The approach is illustrated by application to an industrial scale CCS project at Krechba, In Salah, in Algeria. A structured approach is needed to support assessments of the likely performance of CCS systems over operational, monitoring and longer term time-frames. Very varied information concerning such systems’ engineered and environmental components must be obtained and evaluated to attain sufficient confidence that performance will be acceptable. Computer simulations and risk assessment models are needed to help understand the behaviour of CO2 and place plausible bounds on the temporal evolution of all aspects of the system. The outcomes will be uncertain, even if underpinning data sets are of good quality The approach included identification of the important the Features, Events and Processes (FEPs) that together describe the Krechba system and its likely evolution. An ‘expected evolution’ scenario was then identified by systematically evaluating existing knowledge. Scenarios describing potential situations that could involve alternative evolution mechanisms were also identified; these included consideration of mechanisms that could in principal lead to containment failure. These scenarios need to be analysed to show that they are either unlikely to occur and/or will be of limited impact and so do not represent threats to adequate performance. After audit against Quintessa’s freely available generic online CO2 FEP database to ensure and demonstrate comprehensiveness, the site-specific scenarios identified and the associated list of remaining uncertainties, were used to prioritise future (e.g. systems modelling) work. The outcomes of this and other data analysis and modelling programmes will be used to update the FEP and scenario descriptions. [Copyright &y& Elsevier]

Abstract: It is believed that a RSAT™ (Regenerable Solvent Absorption Technology) process is the most viable nearterm technology for post-combustion CO2 capture from power plant flue gas. The Babcock & Wilcox Power Generation Group, Inc. (B&W) has deployed a suite of research tools to evaluate and develop the CO2 scrubbing technology, including laboratory, pilot-scale, and simulation modeling capabilities. Since the construction and operation of test facilities require significant resources, it is essential to effectively utilize these research tools by choosing a scale-up approach which provides robust design data for a commercial process while minimizing the amount of experimentation required. The scale-up protocol used for RSAT CO2 scrubbing processes was rigorously developed using rate-based modeling concurrent with acquiring fundamental laboratory and pilot plant data for process validation. These development activities were not conducted in series but rather overlapped to yield an optimized commercial CO2 scrubbing process in a reasonable time frame with a high degree of design confidence . This paper presents the scale-up protocol used in evaluating the RSAT process which encompasses both laboratory and pilot-scale testing as well as rate-based modeling to achieve a commercial-scale RSAT process design. This document demonstrates the qualification of test data from a packed tower scale-up point of view. Solvent screening research activities recently conducted within B&W successfully demonstrate the scale-up protocol used for RSAT process development. The time and cost of process development can be significantly reduced through rigorous rate-based modeling in conjunction with laboratory experiments and pilot plant validation. [Copyright &y& Elsevier]

Abstract: The IEA CCS Roadmap highlights the significance that CCS will play in achieving an atmospheric CO2 stabilisation of 450ppm. In the scenario it is based on, CCS will provide approximately 20% of the total CO2 emissions reductions out to 2050. To achieve this contribution, an ambitious CCS growth path will be required, with around 100 projects needed globally by 2020, and over 3000 by 2050. As a result of the required CCS expansion, a number of regulatory issues associated with protecting public health, safety and the environment, as well as ensuring stewardship for permanent CO2 storage, will need to be addressed. There is also a need to provide flexible, adaptive regulations for the first set of demonstration projects. To address these issues, governments are amending existing resource extraction or environmental impact frameworks to allow the first demonstration projects to move forward, while at the same time developing dedicated legal frameworks to facilitate CCS commercialisation for the longer-term. In some cases, project-specific regulations may also be needed. In recent y ears, the international community has amended a number of legal instruments to advance CCS development. The London Protocol was amended in 2006 to allow for offshore CO2 storage and in 2009 to allow fo r cross -border transport of CO2; in 2007, the OSPAR Convention adopted similar provisions. The UNFCCC does not include a fi rm commitment for parties with regard to CCS; however, in 2006, the IPCC released the revised Guidelines for National Greenhouse Gas Inventories, which are used for calculating and reporting national GHG emissions and removals. Although not yet officially sanctioned for use, these guidelines include a complete methodology for the treatment of CCS under the Kyoto Protocol to the UNFCCC and currently have to be used in Kyoto Protocol Annex 1 countries (industrialised), but not yet by non-Annex 1 countries (developing). In parallel, many countries are developing comprehensive domestic regulatory frameworks for CCS. Dedicated legal frameworks enable CCS activities either through licensing regimes or by providing regulatory support for the fi nancing of demonstration projects. The European Commission’s 2008 CCS Directive establishes a regulatory framework for the geological storage of CO2. Australia has also enacted comprehensive state and national CCS regulatory frameworks for CO2 storage. Additionally, regulations are currently being pursued in the United States, Canada, Norway and Japan. To assist in the rapid deployment of CCS in line with the recent findings of the IEA CCS Roadmap, the IEA, with assistance from Carbon Counts, Reed Smith LLP and UCL CCLP, has developed the IEA CCS Model Regulatory Framework, which is intended to serve as a tool to assist governments around the world in the development o f national regulatory frameworks. The Model Framework draws from current CCS regulatory developments in Europe, Australia, the USA, and elsewhere, to ensure that the work done in these countries can be leveraged around the world. The IEA, through this analysis, provides non-prescriptive assistance in CCS regulatory development to countries looking to develop their own domestic framework. This paper discusses the major features of the IEA CCS Model Regulatory Framework and how it can be best distributed and used to assist in the development of regulatory frameworks in all key regions of the world. [Copyright &y& Elsevier]

Abstract: Mafic continental flood basalts form a globally important, but under-characterized CO2 sequestration target. The Columbia River Basalt Group (CRBG) in the northwestern U.S. is up to 5 km thick and covers over 168,000 km2. In India, flood basalts are 3 km thick and cover greater than 500,000 km2. Laboratory experiments demonstrate that the CRBG and other basalts react with formation water and super critical (sc) CO2 to precipitate carbonates, thus adding a potential mineral trapping mechanism to the standard trapping mechanisms of most other types of CO2 sequestration reservoirs. Brecciated tops of individual basalt flows in the CRBG form regional aquifers that locally have greater than 30% porosity and three Darcies of permeability. Porous flow tops are potential sites for sequestration of gigatons of sc CO2 in areas where the basalts contain unpotable water and are at depths greater than 800 m. In this paper we report on the U.S. DOE Big Sky Regional Carbon Sequestration Partnership surface seismic and borehole geophysical characterization that supports a field test of capacity, integrity, and geochemical reactivity of CRBG reservoirs in eastern Washington, U.S.A. Traditional surface seismic methods have had little success in imaging basalt features in on-shore areas where the basalt is thinly covered by sediment. Processing of the experimental 6.5 km, 5 line 3C seismic swath included constructing an elastic wavefield model, identifying and separating seismic wave modes, and processing the swath as a single 2D line. Important findings include: (1) a wide variety of shear wave energy modes swamp the P-wave seismic records; (2) except at very short geophone offsets, ground roll overprints P-wave signal; and (3) because of extreme velocity contrasts, P-wave events are refracted at incidence angles greater than 7–15 degrees. Subsequent removal of S-wave and other noise during processing resulted in tremendous improvement in image quality. The application of wireline logging to onshore basalts is underexploited. Full waveform sonic logs and resistivity-based image logs acquired in the 1250 m basalt pilot borehole provide powerful tools for evaluating geomechanics and lithofacies. The azimuth of the fast shear wave is parallel to SH and records the changes through geologic time in basalt flow and tectonic stress tensors. Combined with image log data, azimuthal S-wave data provide a borehole technique for assessing basalt emplacement and cooling history that is related to the development of reservoirs and seals, as well as the orientation of tectonic stresses and fracture systems that could affect CO2 transport or containment. Reservoir and seal properties are controlled by basalt lithofacies, and rescaled P- and S-wave slowness curves, integrated with image logs, provide a tool for improved recognition of subsurface lithofacies. [Copyright &y& Elsevier]

Abstract: A unified Recommended Practice (RP) for safe and reliable design, construction, operation and maintenance of steel pipelines for transportation of CO2 has been developed through the CO2 PIPETRANS Joint Industry Project (JIP). Best practice knowledge and relevant experience gathered in the JIP form the basis for the guidance given in the RP. The RP applies to pipelines for large scale transportation of CO2, relevant for Carbon Capture and Storage (CCS), and is intended as a supplement to existing recognized standards for both onshore and submarine pipelines. This paper briefly outlines the key content of the RP. [Copyright &y& Elsevier]

Abstract: This paper describes the elements for a Dutch CCS Master Plan and will give concrete recommendations for countries wishing to devise a national CCS strategy based on the insights learnt from the Dutch experience. It analyzes which elements of a Master Plan are crucial and discusses the main findings from the Dutch study. The main element of the Dutch Master plan was the “fields strategy” in which the storage potential of The Netherlands was matched with CO2 emissions over time. This culminated in a strategy consisting of two possible routes for the two most important CCS regions in The Netherlands. It also showed that if both onshore and offshore storage potential is available, all projected emissions can be accommodated until 2050. Furthermore, the interviews with stakeholders gave very useful insights into the drivers for companies to participate in CCS as well as potential show stoppers. Lastly, the study into the costs of converting offshore oil and gas production platform for re-use as CO2 injection platforms shed light on the cost-effective use of infrastructure and gave an indication on the effects of “mothballing” oil and gas production platforms on the costs of CO2 injection. [Copyright &y& Elsevier]

Abstract: The Kyoto Protocol signed by Poland obliges our country to reduce greenhouse gases emission in the period of 2008 to 2012 by about 6 below the 1990 level. One of the methods of reduction of CO2 emission is its binding via mineral carbonation. The paper presents the methodology of researches and findings on CO2 absorption by cement slurries prepared with the use of most commonly applied cement types. [Copyright &y& Elsevier]

Abstract: This paper discusses the energy penalty of solvent based post combustion capture for three different power stations and includes a comparison of shockwave CO2 compression versus conventional turbo machinery on the energy penalty associated with carbon capture and storage. This study uses pinch analysis to determine targets for the energy penalty of three different power stations that include a brown coal power plant with no reheat stage, a more efficient brown coal power station and a black coal power station. Heat integration can be used to reduce the energy penalty of all power stations combined with CCS. It is also found that when heat integration is considered, the heat that can be recovered in shockwave compressor inter/after-coolers reduces the amount of steam that needs to be extracted from the steam turbine. Hence, the net power output from the power station will be higher when shockwave compressors are used for CO2 compression compared to conventional turbo-machinery. [Copyright &y& Elsevier]

Abstract: This paper explores the impact of the temporally dynamic demand for CO2 for CCS-coupled EOR by evaluating the variable demand for new (i.e., non-recycled) anthropogenic CO2 within EOR projects and the extent to which EOR-coupled CCS is compatible with the need for baseload CO2 storage options for large anthropogenic point sources. A profile of CO2 demand over an assumed EOR project lifetime is applied across two different storage scenarios to illustrate the differences in cost associated with different EOR-coupled CCS configurations. The first scenario pairs a single EOR field with a DSF used to store any CO2 that is not used to increase oil recovery in the EOR field; the second scenario is designed to minimize storage in the DSF and maximize lower-cost EOR-based storage by bringing multiple EOR projects online over time as the previous project’s CO2 demand declines, making the source’s CO2 available for a subsequent project. Each scenario is evaluated for two facilities, emitting 3 and 6 MtCO2/y. Annual and lifetime average CO2 transport and storage costs are presented, and the impact of added capture and compression costs on overall project economics is examined. The research reported here suggests that the cost of implementing a CCS-coupled EOR project will be more than is typically assumed; in many cases a positive price on CO2 emitted to the atmosphere will be required to motivate deployment of these CO2-based EOR projects, except in the most idealized cases. The reasons for this conclusion are twofold. First, the costs of capitalizing, operating and monitoring a secondary DSF to provide backup storage for CO2 not demanded by the EOR operation can cut sharply into EOR revenues. Second, except in cases where a single firm figures both the CO2 source emissions and the associated EOR recovery on the same balance sheet, the oil production company is not likely to share a significant portion of revenues from the EOR field with the CO2 source. Thus, while EOR-coupled CCS may offer attractive early opportunities, these opportunities are likely only available to a small fraction of the CO2 source fleet in the U.S. [Copyright &y& Elsevier]

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

Abstract: Geopolymer concrete is being proposed as a potential construction material in carbon capture and storage facilities, in particular the harsh chemical environments found in post-combustion capture solvent columns. Geopolymer concrete is synthesised by reacting industrial wastes (coal fly ash and/or metallurgical slags), with an alkali source to form the binder, blended with aggregates (sand and rocks). In addition to environmental benefits, and utilisation of currently-landfilled fly ashes (landfilled at the rate of several million tonnes p.a. in Australia alone, and hundreds of millions of tonnes p.a. worldwide), geopolymer concrete can provide some significant performance advantages over existing technologies. In particular, the chemical resistance of the geopolymer binder has been highlighted in laboratory testing over a number of years . This paper examines a series of metakaolin, fly ash and ground granulated blast furnace slag binders. Durability studies, which include leaching and strength retained on exposure to solvents (monoethanolamine, potassium carbonate and distilled water), show high resistance to ethanolamine. Potassium carbonate resistance depends greatly on the formulation used. Porosity is a key factor in overall strength and chemical resistance. [Copyright &y& Elsevier]

Abstract: The construction of the process plant required for carbon capture in power generation and also other industrial processes is expected to be among the most significant capital investments of the next 20–30 years. The correct choice of materials for piping, vessels and all types of equipment will be vital in ensuring the long-term performance, safety and high operational availability of the capture plants through their lifetime. Controlling capital and operating costs related to materials will help enable a wider and faster roll-out of carbon capture systems. It is apparent that there is a need to investigate the potential materials degradation and corrosion risks in the carbon capture processes and the related material selection issues. The International Energy Agency Greenhouse Gas (IEA GHG) Research and Development Programme has sponsored a study of corrosion issues and materials selection in carbon capture, transport and storage. This paper summarises some of the outcomes of that study relating to the carbon capture systems. The focus is on materials degradation risks from the process streams and materials issues specific to the carbon capture processes. An overview is provided of corrosion and materials issues related to the three main carbon capture processes (Post-combustion, Pre-combustion (IGCC) and Oxy-fuel). Some specific corrosion issues and problems are discussed. Areas where potential problems exist or where further studies are required are highlighted. [Copyright &y& Elsevier]

Abstract: Consistent with other published studies, the modelling presented here reveals that baseload power plants are the first aspects of the electricity sector to decarbonize and are essentially decarbonized once CO2 permit prices exceed a certain threshold ($90/ton CO2 in this study). The decarbonization of baseload electricity is met by significant expansions of nuclear power and renewable energy generation technologies as well as the application of carbon dioxide capture and storage (CCS) technologies applied to both coal and natural gas fired power plants. Relatively little attention has been paid thus far to whether intermediate and peaking units would respond the same way to a climate policy given the very different operational and economic context that these kinds of electricity generation units operate under. In this paper, the authors discuss key aspects of the load segmentation methodology used to imbed a varying electricity demand within the GCAM (a state-of-the-art Integrated Assessment Model) energy and economic modelling framework and present key results on the role CCS technologies could play in decarbonizng subpeak and peak generation (encompassing only the top 10% of the load) and under what conditions. To do this, the authors have modelled two hypothetical climate policies that require 50% and 80% reductions in US emissions from business as usual by the middle of this century. Intermediate electricity generation is virtually decarbonized once carbon prices exceed approximately $150/ton CO2. When CO2 permit prices exceed $160/ton CO2, natural gas power plants with CCS have roughly the same marketshare as conventional gas plants in serving subpeak loads. The penetration of CCS into peak load (upper 6% here) is minimal under the scenarios modeled here suggesting that CO2 emissions from this aspect of the U.S. electricity sector would persist well into the future even with stringent CO2 emission control policies in place. [Copyright &y& Elsevier]

Abstract: The United States and China are the two largest emitters of greenhouse gases in the world and their projected continued growth and reliance on fossil fuels–especially coal–make them strong candidates for the large-scale deployment of carbon dioxide capture and storage (CCS) systems in a greenhouse gas constrained world. Previous work has revealed that both nations have over 1600 large electric utility and other industrial point CO2 sources as well as very large CO2 storage resources on the order of 2000 billion metric tons (Gt) of onshore storage capacity. In each case, the vast majority of this capacity is found in deep saline formations. In both the USA and China, candidate storage reservoirs are likely to be widely accessible with over 80% of these large industrial CO2 sources having a CO2 storage option within just 80 km. This suggests a strong potential for CCS to help bring about meaningful, sustained CO2 emissions reductions for these large, vibrant economies. However, while the USA and China possess many similarities with regards to the potential value that CCS might provide, including the range of costs at which CCS may be available to most large CO2 sources in each nation, there are a number of more subtle differences that may help us to understand the ways in which CCS deployment may differ as the the two nations work together–and in step with the rest of the world–to most efficiently reduce greenhouse gas emissions. This paper details the first ever analysis of CCS deployment costs in these two countries based on methodologically comparable CO2 source and sink inventories, economic analysis, geospatial source-sink matching and cost curve modeling. This type of analysis provides valuable insight into the degree to which early and sustained opportunities for climate change mitigation via commercial-scale CCS are available to the two countries, and could facilitate greater collaboration in areas where those opportunities overlap. [Copyright &y& Elsevier]

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

Abstract: Climate change is one of the most important public policy issues of our time. Reconciling the world’s ongoing reliance on fossil fuels with the need to reduce greenhouse gas (GHG) emissions is one of our greatest challenges. Canada is taking this challenge seriously with climate change policies that include enhancing our global leadership in advancing one of the most promising technologies for reducing GHG emissions from fossil fuel use: carbon capture and storage (CCS). Federal and provincial governments in Canada are making substantial investments in CCS, committing upwards of CAD 3 billion in public funding towards seven large-scale fully-integrated CCS demonstration projects. The federal ecoENERGY Technology Initiative announced $151 million for the initial engineering and/or pilot stages of seven potential demonstration projects in 2008. The 2009 federal budget created Clean Energy Fund, which included $610 million for CCS demonstrations. The Provinces of Alberta, Saskatchewan, and British Columbia have also committed funding for demonstrations, in particular $2 billion by Alberta. This public funding will leverage additional investment from industry, for projects that will each capture and store on the order of 1 million tonnes of CO2 per year, coming on-line starting in 2015 or sooner. In order to generate early benefits from these investments, Government of Canada intends to create a knowledge sharing framework for CCS demonstration projects in Canada. The learnings from this first wave of demonstration projects should be disseminated in order to reduce challenges for the next generation of CCS projects and to build competitive advantage. This work will also support and provide input to the knowledge sharing and best practice guidelines being currently developed by Global Carbon Capture and Storage Institute (GCCSI). Given that this level of information has not been shared in the past, establishing such a framework will pose several challenges such as concerns regarding the protection of the intellectual property (IP) and commercially sensitive information. Knowledge sharing will also support public engagement and capacity building programs, and it will provide an opportunity to assess the effectiveness and impact of the public investment. This paper will provide an overview and progress to date on the development of knowledge sharing and best practice guidelines in Canada. [Copyright &y& Elsevier]

Abstract: Commissioned in 2009, the CO2CRC/H3 Capture Project is demonstrating post-combustion carbon capture (PCC) on a lignite fired power plant in the Latrobe Valley, Victoria, Australia. The facility is located within International Power’s Hazelwood Power Plant and uses three different CO2 capture technologies — solvent, adsorption and membrane processes. This project, addressing the PCC issues specific for Victorian brown coal fired power stations, was initiated in July 2007 as a three year research project by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) under the Victorian State Government’s Energy Technology Innovation Strategy (ETIS) program. The project is part of the Latrobe Valley Post Combustion Capture (LVPCC) Project — a multi site, multi scale, multi technology PCC trial. The integrated research and development program includes an evaluation of these technologies for commercial scale application. This paper describes the technologies used, how they have progressed from laboratory to pilot demonstration, the main outcomes, and plans for future developments. [Copyright &y& Elsevier]

Abstract: Despite a long history of detailed study, the extensive Jurassic sandstone outcrops of the Colorado Plateau in Southeast Utah, USA continue to provide opportunities to examine reservoir-scale processes. There are a number of large-scale CO2 accumulations in these reservoirs and locally also natural and man-induced CO2-rich springs and geysers, often producing or associated with travertine deposits. These rocks have therefore been exposed to CO2 and/or CO2-rich waters over a substantial period of time, and as such may provide information on resulting geochemical and geomechanical processes. Salt Wash Graben is a WNW-ESE trending structure that cuts across a northerly plunging anticline to the south of Green River, Utah. The Salt Wash Graben lies to the south of the well-studied ’Crystal Geyser’, and itself contains several CO2-rich springs and abundant travertine deposits. Rocks of the Slick Rock and Earthy members of the Jurassic Entrada Sandstone outcrop in the core of the anticline immediately to the north of the graben. These are locally extensively bleached, the bleaching being most pronounced towards the base of the stratigraphically lowest exposed strata, forming a light coloured area in aerial photos. Field investigations of the nature of this bleaching and its relationship to faults and fractures, travertines and CO2 springs, have been supported by detailed analysis of aerial photographs and other satellite-based remote sensing data. The remote sensing data provides a geological context that serves to highlight the different structural and stratigraphic controls which were observed between the regionally extensive bleaching and the bleaching in the Salt Wash Graben. Diagenetic analyses have identified the geochemical processes responsible for bleaching (loss of iron-staining) and other fluid-rock interactions, notably increased porosity in bleached sandstones and differences in carbonate cementation. Simple laboratory experiments have also attempted to replicate these processes by reacting samples of unbleached Entrada Sandstone with CO2-rich formation waters. In this paper, we present a preliminary hypothesis that attempts to link the features described in the Salt Wash Graben, which suggest that CO2-rich fluids may have produced the observed features. If this hypothesis is proved correct, the Salt Wash Graben offers considerable potential to study in detail the flow-constrained geochemical processes at reservoir scale. [Copyright &y& Elsevier]

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

Abstract: The COACH project (Cooperation Action Within CCS China-EU 1 [1] EC/FP6 Contract #038966, co-ordinated by F. Kalaydjian, IFP Energies nouvelles, France. ) was launched on November 1st 2006 for a period of 3 years, as part of the 6th framework programme of the European Commission 2 [2] The French Agency for Development (AFD) is gratefully acknowledged for its financial support to the dissemination, knowledge sharing and capacity building activities developed in COACH. . Gathering 20 partners comprising 8 Chinese partners and 12 European partners, the COACH project was conceived as contributing to the first phase of the Near Zero Emission Coal fired power plants (NZEC) programme, a 3-phase programme developed between the European Union and China, aiming at combating climate change by enabling the deployment in China of thermal power plants equipped with capture and storage (CCS) facilities. The objective of the COACH project was to establish the basis for the large-scale use of coal for polygeneration in China with pre-combustion capture, transport and geological storage of CO2. Main efforts were place on a future CCS demonstration operated on an Integrated Gasification Combined Cycle (IGCC) thermal power plant fully equipped for converting and splitting the produced syngas into a hydrogen-rich fuel gas and CO2, and with a subsequent storage of CO2 in either mature hydrocarbon reservoirs (Dagang or Shengli oil provinces), deep saline formations or unmineable coal seams. Focus was made on the emission sources and storage sites located in the part of the Bohai Basin in the Shandong Province. The paper will present the main outcomes of the project as follows : [•] Structuring the China-EU COACH venture: In order to enabling the sharing of knowledge between European and Chinese COACH partners and building capacity a survey of CCS activities was performed, workshops were organised in EU and China, a cooperative website was created and two one-week long CCS schools were organised in China gathering more than 100 students 2/3 thereof coming from China and the remaining from Europe; [•] Technical actions and challenges relating to CCS, gasification and polygeneration: A generic IGCC concept implemented with CO2 capture was defined and compared against a plain IGCC based on the GreenGen Phase I system without CO2 capture. A detailed analysis of technologies needed for implementing an option for CO2 capture in an IGCC process with provision for production of electricity and methanol was carried out as well as a cost analysis of both CO2 capture and transport; [•] Geological assessment and storage sites mapping: A quantitative assessment of the potential storage sites (the Dagang and Shengli oil provinces, the deep saline aquifers nearby and the Kailuan coal mining area) was performed along with a mapping of the possible transport infrastructure (by pipelines or ships) that could be developed to connect CO2 sources to CO2 sites; with regards to storage capacity, the main capacity was found to reside in the deep saline aquifers (several giga tonnes) but would require further geological investigation for delivering definite values. The storage potential in oil fields was found to be much smaller (less than one giga tonne) but could provide opportunities for enhanced oil recovery. Finally, the coals of Kailuan mining area exhibit a high ability to adsorb CO2 and provide enhanced coalbed methane recovery, but their injectivity remains to be verified. [•] Case studies and recommendations for CCS demonstration in China: By integrating results obtained in the previous tasks dealing with CO2 capture and CO2 storage, two scenarios (one small scale–from 0.1 to 1 million tonnes of CO2 per year, one large scale–2 to 3 million tonnes of CO2 per year) were designed to screen options for a possible CCS demonstration project. These alternative CO2 streams are both considered captured from the GreenGen IGCC power plant in Tianjin and transported to one or more geological formations in the Bohai Bay geological basin for permanent disposal. Storage for the smaller scale scenario could be accommodated in the Dagang or Shengli oilfields. Storage for the larger scale scenario (2–3 million tonnes a year) could be accommodated in the Shengli oilfield province (in a number of fields) or potentially in the saline formations that can be found in the Huimin sub-basin area. For each of these options, a preliminary risk assessment was performed. A thorough cost analysis was performed. Policy and regulation issues pertaining to a shift towards CCS in China. The 3-year targeted cooperative actions under the COACH project have mobilised capacities in China and Europe and paved the ground for subsequent CCS demonstrations in China. The next phase of the China-EU NZEC programme should start in 2010 and deliver FEED studies which should allow starting operating a CCS demonstration in China by 2015. [Copyright &y& Elsevier]

Abstract: Storage of CO2 in saline aquifers would be made at supercritical pressure and temperature conditions, but CO2 leaking from a geologic storage reservoir and migrating towards the land surface (through faults, fractures, or improperly abandoned wells) would reach sub-critical conditions above 500-750 m depth for typical temperature and pressure conditions in terrestrial crust. At shallower horizons, subcritical CO2 can form two-phase mixtures of liquid and gaseous CO2, with significant latent heat effects during boiling and condensation processes. Additional strong non-isothermal effects can arise from decompression of gas-like subcritical CO2, the so-called Joule-Thomson effect. Evaluation of leakage scenarios requires a capability to model nonisothermal flows of brine and CO2 at conditions that range from supercritical to subcritical, including three-phase flow of aqueous phase, and liquid and gaseous CO2. In this paper we describe the development of comprehensive simulation capabilities that can cope with all possible phase conditions in brine- CO2 systems. Our model formulation includes [•] an accurate description of phase properties as function of temperature, pressure, and composition, including the mutual dissolution of CO2 and H2O in aqueous and CO2-rich phases; [•] transitions between super- and sub-critical conditions, including phase change between liquid and gaseous CO2; [•] one-, two-, and three-phase flow of brine- CO2 mixtures, including heat flow; [•] non-isothermal effects associated with phase change, mutual dissolution of CO2 and water, and (de-) compression effects; [•] effects of dissolved NaCl, and the possibility of precipitating solid halite, with associated porosity and permeability change. Applications to specific leakage scenarios demonstrate that the peculiar thermophysical properties of CO2 provide a potential for positive as well as negative feedbacks on leakage rates. The interplay of self-enhancing and self-limiting effects on different space and time scales can induce non-monotonic behavior of CO2 flow rates. Such behavior may facilitate monitoring of CO2 storage systems, as it may provide signals that may be more easily distinguished from background noise. [Copyright &y& Elsevier]

Abstract: Carbon capture and storage systems require handling large volumes of high pressure CO2. Having thorough knowledge of the related hazards is essential, as is knowing how to prevent, detect, control and mitigate accidents. This paper gives a short description of CO2 Boiling Liquid Expanding Vapour Explosions (BLEVEs) and presents results from preliminary, small scale experiments with CO2 BLEVEs. The mechanism of superheated liquid CO2 boiling is not fully understood. Analogies can be made between gas explosions and rapid phase transitions occurring in BLEVEs. The experiments indicate that violent boiling may occur before the spinodal point is reached. Shock waves in the experiments were generated by the decompression of the vapour in the vessel before rupture. However, our recent theoretical models show that boiling also will contribute to shock strength. We observed fragment velocities up to approximately 100 m/s. Such fragments are a serious hazard. Large scale tests and laboratory tests are needed for validation of equation of state models and for the development of computational fluid dynamic codes for use in risk analysis. [Copyright &y& Elsevier]

Abstract: This paper explores the resource intensity and major cost elements of direct air capture of carbon dioxide. The levelized cost of carbon removal is calculated as the sum of costs resulting from interdependent capture devices, energy supplies, water supplies and sequestration resources. The analysis considers “generic” air capture technology characterized only by its energy use, capture footprint, and water use. Capital costs dominate the analysis, followed by energy efficiency. Four dedicated energy resources are considered: Wind, enhanced geothermal, natural gas combined cycle (NGCC), and NGCC with 90% carbon capture. Nearly carbon-free energy is critical to keeping overall cost of carbon mitigation low. The analysis shows that high second law capture efficiencies (on the order of 10%) and relatively inexpensive capture devices (on the order $0.5 M for an individual device capturing one tonne CO2/day) must be achieved if the cost of air capture is to approach $300/tonne- CO2. Reaching those goals is likely to require substantial research into the kinetics and thermodynamics of capture chemistry which, respectively, keep the capital and energy costs as low as possible. [Copyright &y& Elsevier]

Abstract: The use of carbon dioxide (CO2) for enhanced oil recovery (EOR) is being tested for oil fields in the Illinois Basin, USA. While this technology has shown promise for improving oil production, it has raised some issues about the safety of CO2 injection and storage. The Midwest Geological Sequestration Consortium (MGSC) organized a Monitoring, Verification, and Accounting (MVA) team to develop and deploy monitoring programs at three EOR sites in Illinois, Indiana, and Kentucky, USA. MVA goals include establishing baseline conditions to evaluate potential impacts from CO2 injection, demonstrating that project activities are protective of human health and the environment, and providing an accurate accounting of stored CO2. This paper focuses on the use of MVA techniques in monitoring a small CO2 leak from a supply line at an EOR facility under real-world conditions. The ability of shallow monitoring techniques to detect and quantify a CO2 leak under real-world conditions has been largely unproven. In July of 2009, a leak in the pipe supplying pressurized CO2 to an injection well was observed at an MGSC EOR site located in west-central Kentucky. Carbon dioxide was escaping from the supply pipe located approximately 1 m underground. The leak was discovered visually by site personnel and injection was halted immediately. At its largest extent, the hole created by the leak was approximately 1.9 m long by 1.7 m wide and 0.7 m deep in the land surface. This circumstance provided an excellent opportunity to evaluate the performance of several monitoring techniques including soil CO2 flux measurements, portable infrared gas analysis, thermal infrared imagery, and aerial hyperspectral imagery. Valuable experience was gained during this effort. Lessons learned included determining (1) hyperspectral imagery was not effective in detecting this relatively small, short-term CO2 leak, (2) even though injection was halted, the leak remained dynamic and presented a safety risk concern during monitoring activities and, (3) the atmospheric and soil monitoring techniques used were relatively cost-effective, easily and rapidly deployable, and required minimal manpower to set up and maintain for short-term assessments. However, characterization of CO2 distribution near the land surface resulting from a dynamic leak with widely variable concentrations and fluxes was challenging. [Copyright &y& Elsevier]

Abstract: The European project NearCO2 is investigating European public perceptions of CCS via case studies (both CCS and analogous energy infrastructure), surveys, and focus groups. (The NearCO2 project is funded under the FP7 Programme of DG Research at the European Commission. It was launched in April of 2009 and will terminate in March 2011.) The overall aim of the project is to investigate communication strategies that are designed to convey to stakeholders and to the public the advantages and risks of CO2 capture and storage. These same strategies may also be used to involve these parties in local decision-making on CCS projects. This paper describes the results of the first phase of investigation of the NearCO2 project, which focuses on lessons learned from consultation related to CCS project implementation and analogous developments in recent years. Eight case studies have been reviewed to help determine the nature of the communications and consultation strategies used by project developers as part of energy project approval processes. The chosen range of case studies represents a number of different regulatory environments throughout the European Union and a number of different technologies. The consideration of a number of different contextual factors as part of a multi-case study approach has helped to identify factors that underpin the relationship between communications and project outcomes, as a means of informing consultation exercises for future carbon capture and storage (CCS) projects. [Copyright &y& Elsevier]

Abstract: The aim of the paper is to investigate plant flexibility for a pre-combustion cycle. That is, answering the question: how flexible is the plant to changes in operating conditions? Steady-state off-design simulations was the key component of the plant flexibility analysis. Specifically, part load behavior and dual-fuel operation of the integrated reforming combined cycle (IRCC) were studied. The idea of the plant was to use hydrogen-rich decarbonized fuel as the primary fuel and natural gas as back-up fuel. If a problem would occur in the reforming, water-gas shift, or CO2 capture processes there might be a need to switch to a natural gas feed for the gas turbine. This led to design challenges for the heat recovery steam generator (HRSG). The design of the HRSG for the IRCC process was different from an HRSG design in a natural gas combined cycle (NGCC) plant because of the significant amount of steam production from the heat generated in the reforming process. In addition, preheating (within the HRSG) of some of the process streams could add to the complexity in HRSG design. For the concepts studied it was of importance to maintain a high net plant efficiency on both fuels. Therefore the HRSG design had to be a compromise between NGCC and IRCC operation modes. In the analysis performed, part load behavior was good with efficiency reductions from base load operation comparable to that of the reference combined cycle plant. Based on the analysis performed in the present work, it was possible to operate a complex plant like an IRCC at loads down to 60 gas turbine load while capturing 85% of the CO2. During start-up and operation at lower loads, CO2 would not be captured. The investigation was done by using process simulation tools Aspen Plus by AspenTech and GT PRO/GT MASTER by Thermoflow. [Copyright &y& Elsevier]

Abstract: This paper examines cost, challenges and possibilities for the development of an integrated CCS transport infrastructure for the power, cement, refinery and steel and iron sectors in six EU member states: Belgium, Czech Republic, Germany, Netherlands, Poland and Slovakia. Input for ramp-up of CCS within the power sector has been provided by Chalmers Electricity Investment model (ELIN) while ramp-up of CCS in the three industry sectors is based on general assumptions. For each country, three types of CCS infrastructure systems have been assessed; for the power sector only, integrated for the power sector and the three industry sectors and finally, for the three industry sectors only. Transport cost has been calculated to range between € 1.0 and € 4.1 per ton CO2 in the power sector and to between € 1.6 and € 15.9 per ton in the industry sector. The low cost systems indicate a favorable distribution of sources and sinks while high cost systems are a result of low volumes and offshore transport requirements. Transport cost in the integrated system ranged from € 1.2 to € 4.5 per ton implying that there seems to be little to gain for the power sector by integrating transport networks with the industry in the countries investigated, simply due to the location of sources and sinks and the fact that captured volumes from the industry sources are usually considerably smaller than captured volumes from power plants. The results reveal that the development of a CCS infrastructure to a large extent will depend on the phase-in of actual capture plants over time. The ownership concentration within the power sector in most of the countries investigated in this report may facilitate the build-up of a large centralized transport infrastructure. [Copyright &y& Elsevier]

Abstract: “Communication about prospects and limitations of simulation results for policy makers (COPLOS)” is a research project focusing on the exchange between simulation experts and simulation users in the field of Carbon Capture and Storage (CCS). One of the key questions is the applicability of simulation results for policy making. CCS-simulations are carried out for a great variety of applications, for instance, energy system analysis, technology process optimization for capture strategies and pipeline infrastructure or technology assessment studies for CO2-underground storage. This paper analyses the policy relevance of CCS-computer simulations applying the analytical framework “Policy Impact Matrix of Simulations (PIMS)” which allows identifying different simulation clusters and specifying their potential policy impact. [Copyright &y& Elsevier]

Abstract: In situ mineral carbonation is facilitated by aqueous-phase chemical reactions with dissolved CO2. Evidence from the laboratory and the field shows that the limiting factors for in situ mineral carbonation are the dissolution rate of CO2 into the aqueous phase and the release rate of divalent cations from basic silicate minerals. Up to now, pilot CO2 storage projects and commercial operations have focused on the injection and storage of anthropogenic CO2 as a supercritical phase in depleted oil and gas reservoirs or deep saline aquifers with limited potential for CO2 mineralization. The CarbFix Pilot Project will test the feasibility of in situ mineral carbonation in basaltic rocks as a way to permanently and safely store CO2. The test includes the capture of CO2 flue gas from the Hellisheidi geothermal power plant and the injection of 2200 tons of CO2 per year, fully dissolved in water, at the CarbFix pilot injection site in SW Iceland. This paper describes the design of the CO2 injection test and the novel approach for monitoring and verification of CO2 mineralization in the subsurface by tagging the injected CO2 with radiocarbon (14C), and using SF5CF3 and amidorhodamine G as conservative tracers to monitor the transport of the injected CO2 charged water. [Copyright &y& Elsevier]

Abstract: In the near future large quantities of CO2 will be transported over a large distance from Carbon dioxide Capture plants to on-shore and off-shore underground Storage (CCS) sites. The risk assessments for the existing CO2 pipelines show distances to harmful threshold concentrations from 1 to 7.2 km. Such large differences in safety distances are not acceptable. For the design, construction and operation of new high pressure CO2 pipelines through populated areas it will be necessary to have a validated risk assessment model. This paper describes the applied models for the outflow and dispersion and the causes of the uncertainties in the outflow and dispersion of CO2 after an accidental release from a high pressure pipeline. [Copyright &y& Elsevier]

Abstract: The Copenhagen Accord recognizes the scientific view that the increase in global temperature should be below 2 degrees Celsius, and deep cuts in global emissions are required. According to the Fourth Assessment Report of IPCC, the global emissions in 2050 should be reduced by 50% at least compared to the 2000 level in order to achieve below around 2 degrees Celsius and 450 ppmv- CO2eq.. However, the future improvement over 4% p.a. will be needed to achieve halving global emissions within a few percent of GDP losses, while the historical carbon intensity was improved by 1.2% p.a, There are large gaps between historical trends and the required efforts for such a challenging target. In addition, historical trends indicate that it is very difficult to achieve reductions in primary energy consumptions. Therefore, decarbonization of the energy, i.e., carbon intensity improvement, is indispensable for deep emission cuts. Although the developed countries had some trends of the decarbonization, it is also far from such targets of large emission reductions. De-carbonization technologies of nuclear power, renewable energies and Carbon Dioxide Capture and Storage (CCS) are significant. Most emission reduction scenarios including the Intergovernmental Panel on Climate Change (IPCC) report and the International Energy Agency (IEA) show increase in carbon price to advance carbon emissions for the future under the assumptions on sustainable global cooperation for emission reductions. However, It is difficult to sustain global cooperative intention to tackle global warming over 100 years in a real world. The carbon price rather should be decreased in the long-run for sustainable development and sustainable global actions for emission reductions. In addition, historical and currently planed carbon prices of emission trading schemes in many countries are low in the real world, and high carbon prices, particularly explicit prices, are unacceptable politically. CCS development and deployment has risks of intermittent carbon price in near- and mid-term and of carbon price converging zero in long-term. This paper discusses this gap between proposed scenarios assuming ideal world including continuous increase in carbon price and politically acceptable carbon prices in the real world, and outlook of plausible CCS deployment considering the gap. [Copyright &y& Elsevier]