Amine-based CO2 Capture Research Articles

Effects of flue gas compositions on nitrosamine and nitramine formation in postcombustion CO2 capture systems.

Amine-based technologies are emerging as the prime contender for postcombustion CO2 capture. However, concerns have arisen over the health impacts of amine-based CO2 capture associated with the release of nitrosamines and nitramines, which are byproducts from the reactions between flue gas NOx and solvent amines. In this study, flue gas compositions were systematically varied to evaluate their effects on the formation of nitrosamines and nitramines in a lab-scale CO2 capture reactor with morpholine as a model solvent amine. The accumulation of N-nitrosomorpholine in both the absorber and washwater increased linearly with both NO and NO2 for concentrations up to ∼20 ppmv. These correlations could be extrapolated to estimate N-nitrosomorpholine accumulation at extremely low NOx levels (0.3 ppmv NO2 and 1.5 ppmv NO). NO played a particularly important role in driving N-nitrosomorpholine formation in the washwater, likely following partial oxidation to NO2 by O2. The accumulation of N-nitromorpholine in both the absorber and washwater positively correlated with flue gas NO2 concentration, but not with NO concentration. Both N-nitrosomorpholine and N-nitromorpholine accumulated fastest in the absence of CO2. Flue gas humidity did not affect nitrosamine accumulation in either the absorber or the washwater unit. These results provide a basis for estimating the effects of flue gas composition on nitrosamine and nitramine accumulation in postcombustion CO2 capture systems.

Solubility of CO2 in Nonaqueous Absorption System of 2-(2-Aminoethylamine)ethanol + Benzyl Alcohol

A mixture of 2-(2-aminoethylamine)ethanol (AEEA) with benzyl alcohol (BP) as absorbent was developed to reduce energy consumption in an amine-based CO2 capture process. The solubility of CO2 in the AEEA + BP solution was compared with AEEA + diethylene glycol (DEG), AEEA + triethylene glycol (TEG), and AEEA + H2O. The CO2 loading (mol CO2/kg amine) at the same CO2 partial pressure was in the order AEEA + H2O > AEEA + BP > AEEA + TEG > AEEA + DEG, and CO2 loading of all these solutions increased with increasing vapor pressure of CO2. Besides, the CO2 loading in AEEA + BP solution significantly decreased with increasing reaction temperature. The desorption rate of AEEA + BP solution was about 1.3 times faster than that of aqueous AEEA solution at the same desorption temperature, and AEEA + BP solution needed 30% time less than AEEA + H2O solution to reach reaction end point. The AEEA + BP solution showed stable repeatability in four cycles of absorption–desorption tests.

An expert system for monitoring and diagnosis of ammonia emissions from the post-combustion carbon dioxide capture process system

The amine-based carbon dioxide (CO2) capture technology has become an important method for ensuring reduction of greenhouse gas emissions from electricity generation plants. While the amine is a comprehensive solvent that has been used in the post-combustion carbon capture process, the amine-based CO2 capture process emits the primary gas of ammonia (NH3). Since ammonia emissions are hazardous to human health and contribute to acidification of air, soil and water, it is critical that the ammonia from the amine-based carbon capture process be closely monitored.The research objective is to investigate monitoring and diagnosis of ammonia emissions from an amine-based carbon capture process system using an automation approach. This paper presents design and construction of an expert system for monitoring and diagnosis of ammonia emissions from a carbon dioxide capture system. The expert system can conduct automated monitoring and diagnosis of ammonia emissions from the post-combustion CO2 capture process system at the International Test Centre for CO2 Capture (ITC) located at the University of Regina in Saskatchewan, Canada. The system is called the Expert System for Monitoring and Diagnosis of AMmonia emissions (ESMDAM), and application of the system in three case scenarios demonstrates validity of the system recommendations.

Toward Understanding Amines and Their Degradation Products from Postcombustion CO2 Capture Processes with Aerosol Mass Spectrometry

Amine-based postcombustion CO2 capture (PCCC) is a promising technique for reducing CO2 emissions from fossil fuel burning plants. A concern of the technique, however, is the emission of amines and their degradation byproducts. To assess the environmental risk of this technique, standardized stack sampling and analytical methods are needed. Here we report on the development of an integrated approach that centers on the application of a high-resolution time-of-flight aerosol mass spectrometer (HR-ToF-AMS) for characterizing amines and PCCC-relevant species. Molecular characterization is achieved via ion chromatography (IC) and electrospray ionization high-resolution mass spectrometry (ESI-MS). The method has been optimized, particularly, by decreasing the AMS vaporizer temperature, to gain quantitative information on the elemental composition and major nitrogen-containing species in laboratory-degraded amine solvents commonly tested for PCCC applications, including ethanolamine (MEA), methyldiethanolamine (MDEA), and piperazine (PIP). The AMS-derived nitrogen-to-carbon (N/C) ratios for the degraded solvent and product mixtures agree well with the results from a total organic carbon and total nitrogen (TOC/TN) analyzer. In addition, marker ions identified in the AMS spectra are used to estimate the mass contributions of individual species. Overall, our results indicate that this new approach is suitable for characterizing PCCC-related mixtures as well as organic nitrogen species in other sample types. As an online instrument, AMS can be used for both real-time characterization of emissions from operating PCCC plants and ambient particles in the vicinity of the facilities.

Thermodynamic assessment of amine based CO2 capture technologies in power plants based on European Benchmarking Task Force methodology

Post combustion CO2 capture (PCC) with amine solvents is seen as one of the possible technologies which can be implemented in the near term to significantly reduce CO2 emissions from fossil fuel power plants. One of the major concerns for its implementation at large scale in power plants is the high capital and operating costs of the technology. This paper examines the performance of advanced supercritical (ASC) pulverised coal and natural gas combined cycle (NGCC) power plants with two post-combustion CO2 capture units. The capture units are based on chemical absorption with an advanced amine solvent, CESAR-1, which is an aqueous solution of 2-Amino-2-Methyl-Propanol (AMP) and piperazine (PZ), and the conventional Monoethanolamine (MEA) solvent. The comparison between the mentioned technologies is based on the technical assumptions and method provided by the European Benchmarking Taskforce (EBTF) methodology, which is a first attempt for establishing a common European Standard for comparative studies. The resulting net electric efficiencies for the power plants without capture are 45.25% and 58.3% for the ASC PC and NGCC cases respectively. When CO2 capture is applied, the net electrical efficiencies of the studied plants decreases. In the ASC power plant, the MEA capture unit decreases the efficiency by 11.7 percentage points, while the CESAR-1 capture unit decreases the efficiency by 9.4 percentage points. For the NGCC power plant, the reductions are 8.4 and 7.6 percentage points for the MEA and CESAR-1 capture units respectively. Therefore, the evaluation of CESAR-1 under the EBTF standards shows a reduction on power production penalty of 25% for the coal fired plant and 12% for the gas fired plant compared to conventional MEA.

Amines and amine-related compounds in surface waters: A review of sources, concentrations and aquatic toxicity

This review compiles available information on the concentrations, sources, fate and toxicity of amines and amine-related compounds in surface waters, including rivers, lakes, reservoirs, wetlands and seawater. There is a strong need for this information, especially given the emergence of amine-based post-combustion CO2 capture technologies, which may represent a new and significant source of amines to the environment. We identify a broad range of anthropogenic and natural sources of amines, nitrosamines and nitramines to the aquatic environment, and identify some key fate and degradation pathways of these compounds. There were very few data available on amines in surface waters, with reported concentrations often below detection and only rarely exceeding 10μg/L. Reported concentrations for seawater and reservoirs were below detection or very low, while for lakes and rivers, concentrations spanned several orders of magnitude. The most prevalent and commonly detected amines were methylamine (MA), dimethylamine (DMA), ethylamine (EA), diethylamine (DEA) and monoethanolamine (MEAT). The paucity of data may reflect the analytical challenges posed by determination of amines in complex environmental matrices at ambient levels. We provide an overview of available aquatic toxicological data for amines and conclude that at current environmental concentrations, amines are not likely to be of toxicological concern to the aquatic environment, however, the potential for amines to act as precursors in the formation of nitrosamines and nitramines may represent a risk of contamination of drinking water supplies by these often carcinogenic compounds. More research on the prevalence and toxicity of amines, nitrosamines and nitramines in natural waters is necessary before the environmental impact of new point sources from carbon capture facilities can be adequately quantified.

Atmospheric Chemical Reactions of Monoethanolamine Initiated by OH Radical: Mechanistic and Kinetic Study

Monoethanolamine (MEA) is a benchmark and widely utilized solvent in amine-based postcombustion CO2 capture (PCCC), a leading technology for reducing CO2 emission from fossil fuel power plants. The large-scale implementation of PCCC would lead to inevitable discharges of amines to the atmosphere. Therefore, understanding the kinetics and mechanisms of the transformation of representative amine MEA in the atmosphere is of great significance for risk assessment of the amine-based PCCC. In this study, the H-abstraction reaction of MEA with ·OH, and ensuing reactions of produced MEA-radicals, including isomerization, dissociation, and bimolecular reaction MEA-radicals+O2, were investigated by quantum chemical calculation [M06-2X/aug-cc-pVTZ//M06-2X/6-311++G(d,p)] and kinetic modeling. The calculated overall rate constant [(7.27 × 10(-11)) cm(3) molecule(-1) s(-1)] for H-abstraction is in excellent agreement with the experimental value [(7.02 ± 0.46) × 10(-11) cm(3) molecule(-1) s(-1)]. The results show that the product branching ratio of NH2CH2 · CHOH (MEA-β) (43%) is higher than that of NH2 · CHCH2OH (MEA-α) (39%), clarifying that MEA-α is not an exclusive product. On the basis of the unveiled reaction mechanisms of MEA-radicals + O2, the proton transfer reaction mass spectrometry signal (m/z 60.044), not recognized in the experiment, was identified.

Catalytic Solvent Regeneration Using Hot Water During Amine Based CO2 Capture Process

Experiments for CO2 stripping/amine regeneration were performed using single and blended amines (namely, MEA, MEA– MDEA, MEA–DEAB (4-(diethylamine)-2-butanol)) with and without solid acid catalysts (γ-Al2O3 or HZSM-5) at 90–95∘C. The heat duty to regenerate 5M MEA without catalyst was taken as 100% and as the base line. The results showed that the amine regeneration performance in terms of lowest heat duty followed the order: MEA–DEAB with HZSM-5 (38%) > MEA–DEAB with γ-Al2O3 (40%) > MEA–DEAB with no catalyst (51%) > MEA with HZSM-5 (65%) > MEA with γ-Al2O3 (73%) > MEA– MDEA with γ-Al2O3/no catalyst (74%), all relative to MEA with no catalyst (100%). The results further showed that the addition of MDEA or DEAB (as tertiary amines) in a blended solvent provided R3N and HCO −, which split and thus decreased the free energy gaps in the solvent regeneration pathway. The implication is that the use of blended amines in conjunction with solid acid catalysts could result in stripper size and heat duty reductions during solvent regeneration.

Catalytic Solvent Regeneration Using Hot Water During Amine Based CO2 Capture Process

Experiments for CO2 stripping/amine regeneration were performed using single and blended amines (namely, MEA, MEA–MDEA, MEA–DEAB (4-(diethylamine)-2-butanol)) with and without solid acid catalysts (γ-Al2O3 or HZSM-5) at 90–95∘C. The heat duty to regenerate 5M MEA without catalyst was taken as 100% and as the base line. The results showed that the amine regeneration performance in terms of lowest heat duty followed the order: MEA–DEAB with HZSM-5 (38%) > MEA–DEAB with γ-Al2O3 (40%) > MEA–DEAB with no catalyst (51%) > MEA with HZSM-5 (65%) > MEA with γ-Al2O3 (73%) > MEA–MDEA with γ-Al2O3/no catalyst (74%), all relative to MEA with no catalyst (100%). The results further showed that the addition of MDEA or DEAB (as tertiary amines) in a blended solvent provided R3N and HCO3−, which split and thus decreased the free energy gaps in the solvent regeneration pathway. The implication is that the use of blended amines in conjunction with solid acid catalysts could result in stripper size and heat duty reductions during solvent regeneration.

Heat Stable Salt Accumulation and Solvent Degradation in a Pilot-Scale CO2 Capture Process Using Coal Combustion Flue Gas

Solvent degradation is a major factor in the cost associated with carbon capture using aqueous amine solutions. Heat stable salts (HSS) from oxidative amine degradation and acidic flue gas components, including SO2, NOx and HCl can accumulate in amine solvents and lead to corrosion, extra energy requirements and reduced capture efficiency. Accurate and reliable quantitation of HSS concentration is essential to monitor solvent degradation and corrosion potential inside the system. Two separate amine solvents were tested in a 0.1 MWth carbon capture pilot plant. 30% Monoethanolamine (MEA) was used as a baseline solvent and compared to a developed amine solvent, CAER-B2. Six HSS were identified in each solvent and the accumulation rates were determined. The observed HSS build-up was similar in magnitude to other published amine based CO2 capture plant data. The 30% MEA solvent accumulates HSS at a higher rate (48 ppm/hr vs. 22 ppm/hr) as the CAER-B2 which can be attributed to higher input SO2 levels during the solvent test campaign. Corrosion benchmark levels of HSS were exceeded for CAER-B2 and 30% MEA within a few days of normal operation.

Membrane Stripping Technology for CO2 Desorption from CO2-rich Absorbents with Low Energy Consumption

Abstract CO2 membrane stripping is a novel method for CO2 desorption at low temperature (around 348K) for amine-based CO2 capture, which has the potential to reduce regeneration energy requirement. In this work, we investigated CO2 membrane stripping with two different commercial hollow fiber membranes, polypropylene (PP) and Polyvinylidene fluoride (PVDF). CO2 membrane stripping in PVDF membrane showed a faster CO2 desorption rate than in PP membrane, but PP membrane presented a better stability on long-term running. Energy consumption for CO2 membrane stripping with 20 wt% MEA solvent was evaluated. Compared with conventional thermal regeneration, 28% energy can be saved if regeneration pressure of CO2 membrane stripping operated at 20 kPa.

Development of a CO2 Capture Process Based on Ammonia Solvent and a Dedicated Composite Hollow Fibre Membrane Contactor

Abstract CO2 capture is recognized as necessary to achieve significant greenhouse gas emission reduction before 2050. Regarding these technologies, the main issue is the high cost of avoided CO2 related to capture (≈40 €/t). In conventional amine-based CO2 capture process, the four main key parameters driving the cost of avoided CO2 are the regeneration duty, the compression works, the compressor cost and the solvent make-up cost. On the one hand, the use of hollow fibre membrane contactor (HFMC) for CO2 capture is foreseen to be an efficient technology for absorber intensification; but regarding the impact of the absorber cost on the cost of avoided CO2, the use of HFMC for process intensification does not seem relevant. On the other hand, ammonia as solvent for CO2 capture is a cheap solvent with no degradation problem. Moreover, it allows a high pressure regeneration reducing the compression works. The key idea of this work is to find a membrane with high CO2/NH3 selectivity and high permeability in order to use aqueous ammonia as a solvent in a HFMC in order to reduce significantly the ammonia slip in flue gases while maintaining high absorption rate. The work has been divided in three main steps: the screening of available material for the membrane, the laboratory test of the membrane and the modelling of the system for process assessment. For this absorption device a total equivalent work of 240 kWh/tCO2 has been calculated for CO2 capture on a coal-fired power plant.

Dynamic modeling and validation of amine-based CO2 capture plant

It is widely known that, fossil power plants are required to be operated in dynamic scenario due to the timely variation of the grid demand. Flexible operation of post combustion CO2 capture imposes process disturbances and further investigation of dynamic behavior is required. For this purpose, a dynamic mathematical model of CO2 capture process in aqueous solution of 2-amino-2-methyl-1-propanol (AMP) has been developed. The mathematical model of proposed includes mass and heat transfer models, reaction kinetics, vapor–liquid equilibrium, hydrodynamic aspects etc., in order to study the coupled effect of temperature and concentration on the absorption rate. For model validation the pilot plant simulation results were compared to experimental data from literature. Temperature and composition profiles within the columns are predicted successfully by the model, illustrating its predictive capabilities. Dynamic simulations were performed to analyze the capability of the model to predict the effect of the disturbances from the up-stream power plant and the operating conditions of the plant itself, on the plant operation.

Impact of Flue Gas Contaminants on Monoethanolamine Thermal Degradation

The buildup of flue gas contaminants in amine-based postcombustion CO2 capture processes is an important concern due to its potential impact on solvent degradation and reclaiming. In this research, in order to explore the impact of flue gas contaminants on solvent thermal degradation, sodium nitrite, fly ash, sodium sulfate, and sodium thiosulfate were each added into carbon-loaded 5.0 M monoethanolamine (MEA) solution and the solutions were exposed to high-temperature degradation conditions. MEA degrades significantly more in the presence of nitrite (5000 ppm) than MEA alone at the same amine mole concentration. The MEA degradation activation energy of MEA–nitrite solution is calculated and found to be approximately one-seventh of that of MEA solution without nitrite. Addition of nitrite not only enhanced generation of several MEA thermal degradation products but also induced formation of diethanolamine (DEA) and N-(2-hydroxyethyl)piperazin-3-one (HEPO), which have been known to form during MEA oxidative...

Hollow Fiber Membrane Contactors for CO2Capture: Modeling and Up-Scaling to CO2Capture for an 800 MWeCoal Power Station

A techno-economic analysis was completed to compare the use of Hollow Fiber Membrane Modules (HFMM) with the more conventional structured packing columns as the absorber in amine-based CO2capture systems for power plants. In order to simulate the operation of industrial scale HFMMsystems, a two-dimensional model was developed and validated based on results of a laboratory scale HFMM. After successful experiments and validation of the model, a pilot scaleHFMMwas constructed and simulated with the same model. The results of the simulations, from both sizes of HFMM, were used to assess the feasibility of further up-scaling to a HFMM system to capture the CO2from an 800 MWe power plant. The system requirements – membrane fiber length, total contact surface area, and module volume – were determined from simulations and used for an economic comparison with structured packing columns. Results showed that a significant cost reduction of at least 50% is required to make HFMM competitive with structured packing columns. Several factors for the design of industrial scale HFMMrequire further investigation, such as the optimal aspect ratio (module length/diameter), membrane lifetime, and casing material and shape, in addition to the need to reduce the overall cost. However,HFMMwere also shown to have the advantages of having a higher contact surface area per unit volume and modular scale-up, key factors for applications requiring limited footprints or flexibility in configuration.

Influence of Amine Structural Characteristics on N-Nitrosamine Formation Potential Relevant to Postcombustion CO2 Capture Systems

Concerns have arisen for the possible contamination of air or drinking water supplies downwind of amine-based CO2 capture facilities by potentially carcinogenic N-nitrosamines formed from reactions between flue gas NOx and amine solvents. This study evaluated the influence of amine structure on the potential to form total N-nitrosamines within the absorber and washwater units of a laboratory-scale CO2 capture reactor, and in the solvent after a pressure-cooker treatment as a mimic of desorber conditions. Among 16 amines representing 3 amine classes (alkanolamines, straight-chain and cyclic diamines, and amino acids), the order of the amine was the primary determinant of total N-nitrosamine formation in the absorber unit, with total N-nitrosamine formation in the order: secondary amines ≈ tertiary amines ≫ primary amines. Similar results were observed upon pressure-cooker treatment, due to reactions between nitrite and amines at high temperature. For secondary and tertiary amines, total N-nitrosamine formation under these desorber-like conditions appeared to be more important than in the absorber, but for primary amines, significant formation of total N-nitrosamines was only observed in the absorber. For diamines and amino acids, total N-nitrosamine accumulation rates in washwaters were lowest for primary amines. For alkanolamines, however, total N-nitrosamine accumulation in the washwater was similar regardless of alkanolamine order, due to the combined effects of amine reactivity toward nitrosation and amine volatility. While total N-nitrosamine accumulation rates in washwaters were generally 1-2 orders of magnitude lower than in the absorber, they were comparable to absorber rates for several primary amines. Decarboxylation of the amino acid sarcosine resulted in the accumulation of significant concentrations of N-nitrosodimethylamine and N-nitrodimethylamine in the washwater.

Cost and energy sensitivity analysis of absorber design in CO2 capture with MEA

Amine-based CO2 capture processes appear to be the near-term technology for post-combustion CO2 removal from fossil fuel power plants. However, there is no experience with large-scale application of CO2 capture on power plants. A good absorber design is necessary to handle the large volumes of dilute flue gas with high performance, low cost and energy requirement of the plant. In the present work, multi-scale simulations of the absorber were investigated using Aspen RateSep, and a cost estimation model was developed based on mass and energy balances produced by the Aspen Plus simulations, and data from Turton et al. (2012) were applied for cost estimation. Investment costs (CAPEX) and energy requirements of the lean amine circulation pump and absorber blower for variations in the absorber design were compared for two cases: CO2 absorption from a coal-fired power plant, and CO2 absorption from a gas-fired power plant both with a net power output of 400MWe. The flue gas flow rate in the gas-fired power plant case is higher than for the coal-fired power plant, over the same net power output. In the gas-fired power plant case the absorber needs to be designed to process high volumes of flue gas and the pressure drop will often be higher than for a coal-fired power plant due to higher gas velocity. This results in higher capital and operatingcosts. Possible re-design of the absorber is studied and the results show that large electrical energy savings in the feed gas blower can be obtained when a design is chosen giving reduced absorber pressure drop. This can be achieved if the column cross sectional area is increased. This is offset by extra capital cost by a need for slightly more volume of packing. The operational design flexibility in a CO2 capture plant for a gas-fired power plant is higher than for a coal-fired power plant.

Thermal degradation of amino acid salts in CO2 capture

The resistance of amine-based CO2 capture solutions to thermal degradation is a critical characteristic that helps to determine their potential for use as a post-combustion CO2 capture solvent. In this research, sodium salts of glycine, sarcosine, alanine and β-alanine were thermally degraded at 125°C, 135°C and 145°C, respectively, to discover the structural reasons for their thermal stability. These four amino acids have enhanced thermal degradation rates compared to reference monoethanolamine (MEA) solvent. The stability order for amino acid salts tested to date is: sarcosinate>alaninate>β-alaninate. Steric hindrance at the amine group plays a positive role in protecting the amino acid against degradation. Calculated activation energies for the degradation processes are lower than that of MEA. β-Alaninate (β-Ala) thermal degradation generates β-Ala dimer (major degradation product), β-Ala dimer carbamate and tetrahydro-1,3-oxazin-6-one. The relative yields of these three β-alanine degradation routes are discussed.

Evaluation of Post-Combustion CO<sub>2</sub> Capture Technologies

This paper evaluates the results of two recent studies of advanced amine-based, post-combustion CO2 capture plant designs. The first study was conducted by the IEA Greenhouse Gas R&D Programme (IEA GHG), while the second study was conducted by Parsons for the US DOEs National Energy Technology Laboratory (NETL). Fluors improved monoethanolamine (MEA) process, known as the Econamine FG PlusSM technology, is utilised for both studies. Cost and performance estimates for both pulverized coal and natural gas-fired combined cycle plants are summarized. Differences between the design bases and assumptions for the two studies are discussed. The Econamine FG PlusSM technology, as an improved process in amine-based post-combustion CO2 capture described in this paper is leading to lower increases in the cost of electricity (COE). Both the DOE/Parsons and IEA GHG studies show that the increase is now down to 42 to 43% from as high as 60 to 70% indicated from previous studies for PC plants with CO2 capture.

Optimization of CO2 Capture Process with Aqueous Amines—A Comparison of Two Simulation–Optimization Approaches

Aqueous amine is a solvent considered for carbon dioxide (CO2) recovery from the flue gas of a refinery gas turbine by chemical absorption/desorption process. The performance and the economics of this process depend on the choice of the amine absorbent, the concentration of the amine absorbent, the number of stages in the absorber and stripper columns, and the operating conditions. We used response surface methodology (RSM)—a simulation–optimization technique, which uses local searches to estimate an appropriate direction to reduce the objective function—to optimize the amine-based CO2 capture process in a previous work [Nuchitprasittichai and Cremaschi Comput. Chem. Eng. 2011, 35, 1521–1531]. However, RSM does not provide any information about the quality of the obtained solution. In this paper, the RSM results are compared to those obtained by optimizing a global surrogate model of the system over the whole decision space with a global solver. We used an artificial neural network (ANN) as the global sur...