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We present an approach that uses the huge fluid and thermal storage capacity of the subsurface, together with geologic CO 2 storage, to harvest, store, and dispatch energy from subsurface (geothermal) and surface (solar, nuclear, fossil) thermal resources, as well as energy from electrical grids. Captured CO 2 is injected into saline aquifers to store pressure, generate artesian flow of brine, and provide an additional working fluid for efficient heat extraction and power conversion. Concentric rings of injection and production wells are used to create a hydraulic divide to store pressure, CO 2 , and thermal energy. Such storage can take excess power from the grid and excess/waste thermal energy, and dispatch that energy when it is demanded, enabling increased penetration of variable renewables. Stored CO 2 functions as a cushion gas to provide enormous pressure-storage capacity and displaces large quantities of brine, which can be desalinated and/or treated for a variety of beneficial uses. Geothermal power and energy-storage applications may generate enough revenues to justify CO 2 capture costs.

Equipping power plants with carbon capture technologies increases the (cooling) water demand of these plants. This study explores the potential impact of such increase in water demand on the regional water scarcity in Europe. A database with key characteristics of 458 of the largest European power plants is developed and the water use of these power plants is estimated. The water use of the power plants are spatially linked to current water stress index levels. Several prospective scenarios are developed accounting for variations in the future configuration of Europe's electricity generation and different penetration rates of carbon capture technology. Regional water stress index levels are calculated to compare the potential impact of applying carbon capture technologies on the water stress. Preliminary results indicate that the increase of water use due to carbon capture technology is partly expected to be compensated by the deployment of more efficient energy conversion methods which require less cooling water. As such, no significant increase in water stress is expected in the short term (2030), as the carbon capture penetration level in European power plants is expected to be quite low. However, on the long term (2050), large scale instalment of carbon capture technologies in power plants might significantly increase the water stress throughout Europe., Energy Procedia, 63, ISSN:1876-6102, 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12

This communication explores the carbonation potential of activated serpentine at flue gas conditions. A first series of single-step batch experiments was performed varying the temperature and the slurry density to systematically assess the precipitation regime of the relevant Mg-carbonates and the fate of the Si species in solution. The results suggested that the reaction progress was hindered by a passivating layer of re-precipitated silica, quartz, or carbonates, as well as by equilibrium limitations. Among several strategies that were tested to overcome these limitations, a simple double-step process that is driven by a temperature swing in combination with a low-level CO2 pressure swing is presented. Exploratory experiments are shown that prove the viability of our process, first by applying a discontinuous method, and secondly by implementing a methodology to cycle the liquid phase continuously between a dissolution reactor and a precipitator. In this way, it was possible to produce highly pure Mg-carbonates that may serve various industries., Energy Procedia, 63, ISSN:1876-6102, 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12

Hydrogen production from natural gas, combined with advanced CO2 capture technologies, such as iron-based chemical looping (CL), is considered in the present work. The processes are compared to the conventional base case, i.e. hydrogen production via natural gas steam reforming (SR) without CO2 capture. The processes are simulated using commercial software (ChemCAD) and evaluated from a technical point of view considering important key performance indicators such as hydrogen thermal output, net electric power, carbon capture rate and specific CO2 emissions. The environmental evaluation is performed using Life Cycle Analysis (LCA) with the following system boundaries considered: i) hydrogen production from natural gas coupled to CO2 capture technologies based on CL, ii) upstream processes such as: extraction and processing of natural gas, ilmenite and catalyst production and iii) downstream processes such as: H2 and CO2 compression, transport and storage. The LCA assessment was carried out using the GaBi6 software. Different environmental impact categories, following here the CML 2001 impact assessment method, were calculated and used to determine the most suitable technology. Sensitivity analyses of the CO2 compression, transport and storage stages were performed in order to examine their effect on the environmental impact categories. ISSN:1876-6102

This work describes a promising alternative to conventional thermal processes for absorber/desorber processing of for removal of CO[subscript 2] from flue gas streams at fossil fuel fired power plants. Our electrochemically-mediated amine regeneration (EMAR) process offers the advantages of an electrical system coupled with the desirable high output purities typical of amine sorbents that are difficult to achieve with most electric systems such as pressure-swing sorption, membrane separation, and oxy-fuel combustion. Preliminary experimental results are presented that demonstrate the feasibility of using ethylenediamine as the CO[subscript 2] sorbent and copper electro-cycling to isothermally modulate the amine affinity for CO[subscript 2]. Cupric ions entirely deactivate ethylenediamine at a ratio of 2:1 diamine to copper. Open-circuit potential measurements at 50°C indicate the required energy to desorb CO[subscript 2] and regenerate the ethylenediamine is 18 kJ/mole CO[subscript 2] under open-circuit conditions. Kinetic over-potentials are sufficiently low to ensure acceptable energy losses. Lower energies can be achieved by increasing the temperature or by changing the amine., Siemens Corporation (CKI Research Fund), United States. Advanced Research Projects Agency-Energy (Research Grant DE-AR0000083)

Gasification-based plants with coal-CO[subscript 2] slurry feed are predicted to be more efficient than those with coal-water slurry feed. This is particularly true for high moisture, low rank coal such as lignite. Nevertheless, preparation of the CO[subscript 2] slurry is challenging and the losses associated with this process have not been accounted for in previous analyses. This work introduces the Phase Inversion-based Coal-CO[subscript 2] Slurry (PHICCOS) feeding system, in which coal-CO[subscript 2] slurry is prepared at ambient temperature via coal-water slurry. Steady-state process simulation is used to estimate the performance of the proposed slurry preparation and feeding system for bituminous coal and lignite. An Integrated Gasification Combined Cycle (IGCC) power plant with carbon capture is used here as a potential application, but this concept is applicable to any high-pressure coal feeding process. The economic attractiveness of the PHICCOS feeding system is assessed through calculation of its capital costs and resulting levelized cost of electricity, relative to competing commercial technologies. The findings of this work show that the PHICCOS feeding system offers a good tradeoff between overall process performance and costs. It is the most cost-effective method for feeding lignite and the second most attractive for bituminous coal, for which the competing technology is marginally cheaper. The PHICCOS feeding system is hence the only feeding system which is consistently cost-effective across the entire coal rank spectrum and is increasingly so for high-moisture and high-ash coal., BP (Firm)

This paper presents results from a survey on stakeholder attitudes towards Carbon Capture and Storage (CCS). The survey is the first to make a global comparison across three major regions; USA, Japan, and Europe. The 30-question survey targeted individuals working at stakeholder organizations that seek to shape, and will need to respond to, policy on CCS, including electric utilities, oil & gas companies, CO2-intensive industries and non-governmental organizations (NGOs). The results show generally small differences across the regions and between the different groups of stakeholders. All believed that the challenge of significant reductions in emissions using only current technologies was severe. There is a widespread belief both that renewable technologies such as solar power and CCS will achieve major market entry into the electricity sector within the next 10 to 20 years, whereas there is more skepticism about the role of hydrogen and especially nuclear fusion in the next 50 years. All groups were generally positive towards renewable energy. Yet, there were some notable areas of disagreement in the responses, for example, as expected, NGOs considered the threat of climate change to be more serious than the other groups. North Americans respondents were more likely to downplay the threat compared to those of the other regions. The Japanese were more concerned about the burden that would be placed on industry in the coming decade as a result of emissions constraints and NGOs were more likely to believe that the burden would be light or very light. NGOs believed CCS to be far more attractive than nuclear fusion power but much less than renewables. As expected, the risk for leakage from reservoirs was ranked number one of the risk options given., Alliance for Global Sustainability, National Institute of Advanced Industrial Science and Technology (Japan), Carbon Sequestration Initiative, Alliance for Global Sustainability (AGS project “Pathways to Sustainable European Energy Systems” funding)

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., Research Council of Norway, Statoil ASA

This paper provides a financial analysis for new supercritical pulverized coal plants with carbon capture and sequestration (CCS) that compares the effects of two relevant climate policies. First, an updated cost estimate is presented for new supercritical pulverized coal plants, both with and without CCS. The capital cost escalation of recent years can be attributed to rising materials, plant supply, and plant contractor constraints. This estimate is then compared with recent estimates from public sources. Second, several current and proposed public policies relevant to CCS are presented. Finally, a financial analysis is performed to evaluate the effectiveness of two likely US carbon regulations on deploying Nth-plant CCS technology. The major conclusion is that the leading US carbon cap-and-trade bills will likely not be sufficient to deploy CCS technology in a manner consistent with a 550 ppm CO[subscript 2] stabilization scenario. A more aggressive carbon policy including CCS research, development, and demonstration must be considered to achieve this goal with significant CCS deployment., Massachusetts Institute of Technology. Carbon Sequestration Initiative, MIT Industrial Performance Center

The focus of this study is the analysis of an integrated reforming combined cycle (IRCC) with natural gas as fuel input. This IRCC consisted of a hydrogen-fired gas turbine (GT) with a single-pressure steam bottoming cycle for power production. The reforming process section consisted of a pre-reformer and an air-blown auto thermal reformer (ATR) followed by water-gas shift reactors. The air to the ATR was discharged from the GT compressor and boosted up to system pressure by an air booster compressor. For the CO[subscript 2] capture sub-system, a chemical absorption setup was modeled. The design case model was modeled in GT PRO by Thermoflow, and in Aspen Plus. The Aspen Plus simulations consisted of two separate models, one that included the reforming process and the water-gas shift reactors. In this model were also numerous heat exchangers including the whole pre-heating section. Air and CO[subscript 2] compression was also incorporated into the model. As a separate flow sheet the chemical absorption process was modeled as a hot potassium carbonate process. The models were linked by Microsoft Excel. For the CO[subscript 2] capture system the model was not directly linked to Excel but instead a simple separator model was included in the reforming flow sheet with inputs such as split ratios, temperatures, and pressures from the absorption model. Outputs from the potassium model also included pump work and reboiler duty. A main focal point of the study was off-design simulations. For these steady-state off-design simulations GT MASTER by Thermoflow in conjunction with Aspen Plus were used. Also, inputs such as heat exchanger areas, compressor design point, etc., were linked in from the Aspen Plus reforming design model. Results indicate a net plant efficiency of 43.2% with approximately a 2%-point drop for an 80% part load case. Another off-design simulation, at 60% load, was simulated with a net plant efficiency around 39%. The CO[subscript 2] capture rate for all cases was about 86%, except for the reference case which had no CO[subscript 2] capture., Research Council of Norway, StatoilHydro

The two major pathways for energy utilization from biomass are conversion to a liquid fuel (i.e., biofuels) or conversion to electricity (i.e., biopower). In the United States (US), biomass policy has focused on biofuels. However, this paper will investigate three options for biopower: low co-firing (co-firing scenarios refer to combusting a given percentage of biomass with coal) (5%–10% biomass), medium co-firing (15%–20% biomass), and dedicated biomass firing (100% biomass). We analyze the economic and greenhouse gas (GHG) emissions impact of each of these options, with and without CO[subscript 2] capture and storage (CCS). Our analysis shows that in the absence of land use change emissions, all biomass co-combustion scenarios result in a decrease in GHG emissions over coal generation alone. The two biggest barriers to biopower are concerns about carbon neutrality of biomass fuels and the high cost compared to today’s electricity prices. This paper recommends two policy actions. First, the need to define sustainability criteria and initiate a certification process so that biomass providers have a fixed set of guidelines to determine whether their feedstocks qualify as renewable energy sources. Second, the need for a consistent, predictable policy that provides the economic incentives to make biopower economically attractive.

Cost-effective, large-scale carbon dioxide capture is a critical technology for mitigating greenhouse gas emissions, and current capture technologies are energy intensive and difficult to deploy in existing power plants. We have previously introduced a novel electrochemically-mediated process for amine regeneration, and demonstrated its feasibility with a proof-of-concept system that can efficiently modulate amine affinity to carbon dioxide under the effect of redox-responsive molecules. The electrochemical process is simple to install, obviating the need for expensive retrofits. In addition, due to its targeted nature, the process has the potential for lower energy consumption as compared with the thermal amine capture process. In this work, we analyze the energy consumption of the electrochemical process, building from thermodynamic lower bounds, and addressing electrochemical kinetics, transport requirements as well compression and pumping energy. The analysis suggests that the electrochemical process can generate carbon dioxide at the conditions required for transportation with an electrical energy consumption of less than 50 kJ per mole of carbon dioxide captured and compressed. The electrochemical process efficiency can be further improved by optimizing flow design and utilizing additives to reduce activation overpotentials., United States. Dept. of Energy

International audience; We summarize recent modeling studies of injection-induced fault reactivation, seismicity, and its potential impact on surface structures and nuisance to the local human population. We used coupled multiphase fluid flow and geomechanical numerical modeling, dynamic wave propagation modeling, seismology theories, and empirical vibration criteria from mining and construction industries. We first simulated injection-induced fault reactivation, including dynamic fault slip, seismic source, wave propagation, and ground vibrations. From co-seismic average shear displacement and rupture area, we determined the moment magnitude to about Mw = 3 for an injection-induced fault reactivation at a depth of about 1000 m. We then analyzed the ground vibration results in terms of peak ground acceleration (PGA), peak ground velocity (PGV), and frequency content, with comparison to the U.S. Bureau of Mines’ vibration criteria for cosmetic damage to buildings, as well as human-perception vibration limits. For the considered synthetic Mw = 3 event, our analysis showed that the short duration, high frequency ground motion may not cause any significant damage to surface structures, and would not cause, in this particular case, upward CO2 leakage, but would certainly be felt by the local population.

CO2-Plume Geothermal (CPG) technology involves injecting CO2 into natural, highly permeable geologic units to extract energy. The subsurface CO2 absorbs heat from the reservoir, buoyantly rises to the surface, and drives a power generation system. The CO2 is then cooled and reinjected underground. Here, we analyze the effects of multi-layered geologic reservoirs on CPG system performance by examining the CO2 mass fraction in the produced fluid, pore-fluid pressure buildup during operation, and heat energy extraction rates. The produced CO2 mass fraction depends on the stratigraphic positions of highly permeable layers which also affect the pore-fluid pressure drop across the reservoir. ISSN:1876-6102

This communication gives an overview of our study on the dissolution kinetics of thermally activated serpentine (dehydroxylated serpentine). Firstly, we had studied the far-from-equilibrium dissolution kinetics of 75% dehydroxylated lizardite particles in a liquid and gas flow-through reactor at moderate temperatures (30 °C < T < 120 °C) and low CO2 partial pressures (0.1 bar < pCO2 < 2 bar). Over 80% of the Mg was leached from the dehydroxylated lizardite particles. We then followed it up by developing a non-steady state dissolution kinetics model. The model uses surface complexation mechanisms to describe the specific dissolution rates. The model was able to describe the evolution of the non-stoichiometric aqueous concentration profiles of magnesium and silica accurately, taking into account the dynamic evolution of the reactor pH at non-steady state dissolution conditions. The kinetic parameters could be used to compare the dissolution performances of differently activated minerals in their application as potential feed materials for an ex situ mineral carbonation process., Energy Procedia, 63, ISSN:1876-6102, 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12

Post-combustion chemical absorption is regarded as the state-of-the-art commercially-available CO2 capture process. The adoption of aqueous ammonia as solvent, leading to the so-called Chilled Ammonia capture Process (CAP), has long been considered one of the most promising alternatives to amine-based for post-combustion carbon capture. This work investigates the development of a second generation CAP where the capture efficiency is improved by making use of a crystallizer to form solids in the process. The reference standard CAP and the advanced crystallizer-based CAP are simulated in Aspen using the Extended UNIQUAC thermodynamic model. The two CAP solutions are compared in term of the different energy penalties introduced applying the capture process to a conventional Ultra Super Critical (USC) power plant. Thanks to the solid formation, the CAP with the crystallizer features a lower energy penalization with a decrease of about 10% compared to the total penalty of the standard CAP., Energy Procedia, 63, ISSN:1876-6102, 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12

Separation processes based on adsorption show potential in the field of carbon dioxide capture and utilization or storage. Model- based process design is a powerful tool to fully exploit this potential. In order to get an accurate description of the behavior of the processes in a fixed bed, a reliable description of the equilibrium adsorption is necessary. In this work the potential of two types of zeolites, 13X and ZSM-5, is investigated in regards to their use in a temperature swing adsorption process for a post- combustion capture application. To this end, the single component adsorption equilibrium of CO2, N2, and H2O vapor is presented along with appropriate isotherms describing the data. This allows for a comparison of the two sorbents with respect to their cyclic CO2 adsorption capacity and selectivity for CO2. Additionally, the competition for adsorption sites between CO2 and N2 is investigated by applying the ideal adsorbed solution theory (IAST) to predict the binary adsorption equilibrium on both sorbents. These predictions indicate a very high selectivity of 13X for CO2, making this a very promising sorbent for temperature swing adsorption in a post-combustion capture environment, with the caveat that it also strongly adsorbs water vapor. This strong affinity for water vapor may imply that a flue gas stream would have to be dried before it enters the adsorption unit., Energy Procedia, 63, ISSN:1876-6102, 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12

Coal--CO[subscript 2] slurry feed has been suggested as an attractive alternative to coal–water slurry feed for single-stage, entrained-flow gasifiers. Previous work demonstrated the system-level advantages of gasification-based plants equipped with CO[subscript 2] capture and CO[subscript 2] slurry feed, under the assumption that carbon conversion remains unchanged. However, gasification in carbon dioxide has been observed to be slower than that in steam. In view of this, the impact of CO[subscript 2] slurry feeding on gasification kinetics and ultimately on carbon conversion and oxygen consumption in a pressurized, single-stage entrained-flow gasifier processing bituminous coal is studied here using a 1-D reduced order model. Results show that the CO[subscript 2] gasification reaction plays a dominant role in char conversion when the feeding system is CO[subscript 2] slurry, increasing the CO content in the products by up to a factor of two. CO inhibition of the gasification reaction and a higher degree of internal mass transport limitations lead to an up to 60% slower gasification rate, when compared to a system based on coal-water slurry. Accordingly, a gasifier with CO[subscript 2] slurry feed has 15% less oxygen consumption but a 7%-point lower carbon conversion for a given reactor outlet temperature. The gasifier outlet temperature must be raised by 90 K in order to achieve the same conversion as in a water slurry-fed reactor; the peak reactor temperature increases by 220 K as a result. Net oxygen savings of 8% are estimated for a system with a CO[subscript 2] slurry-fed gasifier relative to one with water slurry and the same level of conversion., BP (Firm)

Carbon capture technology has been proposed as an effective approach for the mitigation of anthropogenic CO[subscript 2] emissions. Thermal-swing separation technologies based on wet chemical scrubbing show potential for facilitating CO[subscript 2] capture at industrial-scale carbon emitters; however, the total operational and capital costs resulting from the high energy consumption are prohibitive for their implementation. Electrochemically mediated processes are proposed to be the next generation of CO[subscript 2] separation technology that can enable carbon capture to be a more viable option for carbon mitigation in the near future. This technology utilizes electrochemically active sorbents that undergo significant changes in their molecular affinity for CO[subscript 2] molecules as they progress through an electrochemical cycle. This nearly isothermal separation process consumes electrical energy to facilitate effective CO[subscript 2] capture and regeneration processes under more benign conditions of sorption and desorption than in traditional continuous wet-scrubber operations. This electrically driven separation process has the potential to significantly reduce the difficulty of retrofitting CO[subscript 2] capture units to existing fossil fuel-fired power generators. The ease of installing an electrically driven separation system would also allow its application to other industrial carbon emitters. The design of such a system, however, requires careful consideration since it involves both heterogeneous electrochemical activation/deactivation of sorbents and homogeneous complexation of the activated sorbents with CO[subscript 2] molecules. Optimization of the energy efficiency requires minimizing the irreversibility associated with these processes. In this study, we use a general exergy analysis to evaluate the minimum thermodynamic work based on the system design and the electrochemical parameters of quinodal redox-active molecules. Using this thermodynamic framework, our results suggest that the proposed technology could capture CO[subscript 2] from a dilute post-combustion flue gas and regenerate CO[subscript 2] at 1 bar with high efficiency, if a two-stage design is effectively implemented., Siemens Corporation (Massachusetts Institute of Technology. Center of Knowledge Interchange Project Fund)

Energy Procedia, 1 (1), ISSN:1876-6102, Greenhouse Gas Control Technologies 9

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., Energy Procedia, 1 (1), ISSN:1876-6102, Greenhouse Gas Control Technologies 9

Electrochemically mediated amine regeneration is a new post-combustion capture technology with the potential to exploit the excellent removal efficiencies of thermal amine scrubbers while reducing parasitic energy losses and capital costs. The improvements result from the use of an electrochemical stripping cycle, in lieu of the traditional thermal swing, to facilitate CO[subscript 2] desorption and amine regeneration; metal cations generated at an anode react with the amines, displacing the CO[subscript 2], which is then flashed off, and the amines are regenerated by subsequent reduction of the metal cations in a cathode cell. The advantages of such a process include higher CO[subscript 2] desorption pressures, smaller absorbers, and lower energy demands. Several example chemistries using different polyamines and copper are presented. Experimental results indicate an open-circuit efficiency of 54% (15 kJ per mole CO[subscript 2]) is achievable at the tested conditions and models predict that 69% efficiency is possible at higher temperatures and pressures. A bench scale system produced 1.6 mL min[superscript −1] CO[subscript 2] while operating at 0.4 volts and 42% Faradaic efficiency; this corresponds to a work of less than 100 kJ per mole., United States. Advanced Research Projects Agency-Energy (Grant DE-AR0000083)

Adding post-combustion capture technology to existing coal-fired power plants is being considered as a near-term option for mitigating CO[subscript 2] emissions. To supply the thermal energy needed for CO[subscript 2] capture, much of the literature proposes thermal integration of the existing coal plant’s steam cycle with the capture process’ stripper reboiler. This paper examines the option of using an auxiliary natural gas turbine plant to meet the energetic demands of carbon capture and compression. Three different auxiliary plant technologies were compared to integration for 90% capture from an existing, 500 MW supercritical coal plant. CO[subscript 2] capture (via a monoethylamine (MEA) absorption process) and compression is simulated using Aspen Plus. Thermoflow software is used to simulate three gas plant technologies. In some circumstances, it is found that using an auxiliary natural gas turbine may make retrofits more attractive compared to using thermal integration. The most important factors affecting desirability of the auxiliary plant retrofit are the cost of natural gas, the full cost of integration, and the potential for sale of excess electricity., Research Council of Norway (Statoil (Firm: Norway), Massachusetts Institute of Technology. Carbon Sequestration Initiative

The Chilled Ammonia Process is a mature post-combustion CO2 capture process. The formation of solids in the process at high CO2 and NH3 concentrations was already described in the original patent, but is relatively poorly understood and difficult to explore experimentally. Thermodynamic properties that complicate the experimental investigation, such as the high vapor pressures of CO2 and NH3 and the resulting incongruent solubility as well as the fast decomposition of the solids, are discussed in this work. Preliminary results for the metastable zone width and for nucleation kinetics in the ammonium bicarbonate/water system are presented. The solubility of ammonium bicarbonate derived from dissolution experiments is close to the historical literature values and an explanation for the slight deviation is discussed., Energy Procedia, 63, ISSN:1876-6102, 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12