CO2 capture from coal-fired power plants based on sodium carbonate slurry; a systems feasibility and sensitivity study

In this work the feasibility of a CO₂ capture system based on sodium carbonate–bicarbonate slurry and its integration with a power plant is studied. The results are compared to monoethanolamine (MEA)-based capture systems. Condensing power plant and combined heat and power plant with CO₂ capture is modelled to study the feasibility of combined heat and power plant for CO₂ capture.Environmental friendly sodium carbonate would be an interesting chemical for CO₂ capture. Sodium carbonate absorbs CO₂ forming sodium bicarbonate. The low solubility of sodium bicarbonate is a weak point for the sodium carbonate based liquid systems since it limits the total concentration of carbonate. In this study the formation of solid bicarbonate is allowed, thus forming slurry, which can increase the capacity of the solvent. With this the energy requirement of stripping of the solvent could potentially be around 3.22 MJ/kg of captured CO₂ which is significantly lower than with MEA based systems which typically have energy consumption around 3.8 MJ/kg of captured CO₂.Combined heat and power plants seem to be attractive for CO₂ capture because of the high total energy efficiency of the plants. In a condensing power plant the CO₂ capture decreases directly the electricity production whereas in a combined heat and power plant the loss can be divided between district heat and electricity according to demand.     

Techno-Economic Study of CO2 Capture from an Existing Cement Plant Using MEA Scrubbing

Carbon dioxide is the major greenhouse gas responsible for global warming. Man-made CO₂ emissions contribute approximately 63% of greenhouse gases and the cement industry is responsible for approximately 5% of CO₂ emissions emitting nearly 900 kg of CO₂ per 1000 kg of cement. CO₂ from a cement plant was captured and purified to 98% using the monoethanolamine (MEA) based absorption process. The capture cost was $51 per tonne of CO₂ captured, representing approximately 90% of total cost. Steam was the main operating cost representing 39% of the total capture cost. Switching from coal to natural gas reduces CO₂ emissions by about 18%. At normal load, about 36 MW of waste heat is available for recovery to satisfy the parasitic heat requirements of MEA process; however, it is very difficult to recover.     

CO2 capture from power plants: Part II. A parametric study of the economical performance based on mono-ethanolamine

While the demand for reduction in CO₂ emission is increasing, the cost of the CO₂ capture processes remains a limiting factor for large-scale application. Reducing the cost of the capture system by improving the process and the solvent used must have a priority in order to apply this technology in the future. In this paper, a definition of the economic baseline for post-combustion CO₂ capture from 600 MW_e bituminous coal-fired power plant is described. The baseline capture process is based on 30% (by weight) aqueous solution of monoethanolamine (MEA). A process model has been developed previously using the Aspen Plus simulation programme where the baseline CO₂-removal has been chosen to be 90%. The results from the process modelling have provided the required input data to the economic modelling. Depending on the baseline technical and economical results, an economical parameter study for a CO₂ capture process based on absorption/desorption with MEA solutions was performed.Major capture cost reductions can be realized by optimizing the lean solvent loading, the amine solvent concentration, as well as the stripper operating pressure. A minimum CO₂ avoided cost of € 33 tonne⁻¹ CO₂ was found for a lean solvent loading of 0.3 mol CO₂/mol MEA, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa. At these conditions 3.0 GJ/tonne CO₂ of thermal energy was used for the solvent regeneration. This translates to a € 22 MWh⁻¹ increase in the cost of electricity, compared to € 31.4 MWh⁻¹ for the power plant without capture.     

Life cycle modelling of fossil fuel power generation with post-combustion CO2 capture

Due to its compatibility with the current energy infrastructures and the potential to reduce CO₂ emissions significantly, CO₂ capture and geological storage is recognised as one of the main options in the portfolio of greenhouse gas mitigation technologies being developed worldwide. The CO₂ capture technologies offer a number of alternatives, which involve different energy consumption rates and subsequent environmental impacts. While the main objective of this technology is to minimise the atmospheric greenhouse gas emissions, it is also important to ensure that CO₂ capture and storage does not aggravate other environmental concerns. This requires a holistic and system-wide environmental assessment rather than focusing on the greenhouse gases only. Life Cycle Assessment meets this criteria as it not only tracks energy and non-energy-related greenhouse gas releases but also tracks various other environmental releases, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of other resources, such as water, minerals and land use. This paper presents the principles of the CO₂ capture and storage LCA model developed at Imperial College and uses the pulverised coal post-combustion capture example to demonstrate the methodology in detail. At first, the LCA models developed for the coal combustion system and the chemical absorption CO₂ capture system are presented together with examples of relevant model applications. Next, the two models are applied to a plant with post-combustion CO₂ capture, in order to compare the life cycle environmental performance of systems with and without CO₂ capture. The LCA results for the alternative post-combustion CO₂ capture methods (including MEA, K⁺/PZ, and KS-1) have shown that, compared to plants without capture, the alternative CO₂ capture methods can achieve approximately 80% reduction in global warming potential without a significant increase in other life cycle impact categories. The results have also shown that, of all the solvent options modelled, KS-1 performed the best in most impact categories.     

Integration of CO2 capture unit using single- and blended-amines into supercritical coal-fired power plants: Implications for emission and energy management

This work provides the essential information and approaches for integration of carbon dioxide (CO₂) capture units into power plants, particularly the supercritical type, so that energy utilization and CO₂ emissions can be well managed in the subject power plants. An in-house model, developed at the University of Regina, Canada, was successfully used for simulating a 500 MW supercritical coal-fired power plant with a post-combustion CO₂ capture unit. The simulations enabled sensitivity and parametric study of the net efficiency of the power plant, the coal consumption rate, and the amounts of CO₂ captured and avoided. The parameters of interest include CO₂ capture efficiency, type of coal, flue gas delivery scheme, type of amine used in the capture unit, and steam pressure supplied to the capture unit for solvent regeneration. The results show that the advancement of MEA-based CO₂ capture units through uses of blended monoethanolamine–methyldiethanolamine (MEA–MDEA) and split flow configuration can potentially make the integration of power plant and CO₂ capture unit less energy intensive. Despite the increase in energy penalty, it may be worth capturing CO₂ at a higher efficiency to achieve greater CO₂ emissions avoided. The flue gas delivery scheme and the steam pressure drawn from the power plant to the CO₂ capture unit should be considered for process integration.     

Corrosion and polarization behavior of carbon steel in MEA-based CO2 capture process

This work reveals levels of corrosion rate and polarization behavior of carbon steel immersed in aqueous solutions of monoethanolamine (MEA) used in the absorption-based carbon dioxide (CO₂) capture process for greenhouse gas reduction from industrial flue gas streams. Such information was obtained from electrochemical-based corrosion experiments under a wide range of the CO₂ capture process conditions. The corrosion of carbon steel was evaluated in respect to process parameters including partial pressure of oxygen (O₂), CO₂ loading in solution, solution velocity, solution temperature, MEA concentration and metal surface condition. Results show that the aqueous MEA solution containing CO₂ provides a favorable condition for the corrosion of carbon steel to proceed. Corrosion rate is increased by all tested process parameters. These parametric effects were explained by the electrochemical kinetic data obtained from polarization curves and by the thermodynamic data obtained from Pourbaix diagram.     

CO2 capture from power plants: Part I. A parametric study of the technical performance based on monoethanolamine

Capture and storage of CO₂ from fossil fuel fired power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. An optimization and technical parameter study for a CO₂ capture process from flue gas of a 600 MWe bituminous coal fired power plant, based on absorption/desorption process with MEA solutions, using ASPEN Plus with the RADFRAC subroutine, was performed. This optimization aimed to reduce the energy requirement for solvent regeneration, by investigating the effects of CO₂ removal percentage, MEA concentration, lean solvent loading, stripper operating pressure and lean solvent temperature.Major energy savings can be realized by optimizing the lean solvent loading, the amine solvent concentration as well as the stripper operating pressure. A minimum thermal energy requirement was found at a lean MEA loading of 0.3, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa, resulting in a thermal energy requirement of 3.0 GJ/ton CO₂, which is 23% lower than the base case of 3.9 GJ/ton CO₂. Although the solvent process conditions might not be realisable for MEA due to constraints imposed by corrosion and solvent degradation, the results show that a parametric study will point towards possibilities for process optimisation.     

Ionic liquids for post-combustion CO2 absorption

The present work is a study to evaluate ionic liquids as a potential solvent for post-combustion CO₂ capture. In order to enhance the absorption performance of a CO₂ capture unit, different ionic liquids have been designed and tested. The main goal was to get a comparison between a reference liquid and selected ionic liquids. As the reference, a solution of 30 w% monoethanolamine (MEA) and water was used. A large range of different pure and diluted ionic liquids was tested with a special screening process to gain general information about the CO₂ absorption performance. Based on these results, a 60 w% ionic liquid solution in water was selected and the vapour–liquid equilibrium was measured experimentally between 40 °C and 110 °C. From these curves the enthalpy of absorption for capturing CO₂ into the ionic liquid was determined. With these important parameters one is able to calculate the total energy demand for stripping of CO₂ from the loaded solvent for comparison of the ionic liquid based solvent with the reference MEA solvent. The energy demand of this 60 w% ionic liquid is slightly lower than that of the reference solution, resulting in possible energy savings between 12 and 16%.     

The influence of the precursor and synthesis method on the CO2 capture capacity of carpet waste-based sorbents

Adsorption is one of the most promising technologies for reducing CO₂ emissions and at present several different types of sorbents are being investigated. The use of sorbents obtained from low-cost and abundant precursors (i.e. solid wastes) appears an attractive strategy to adopt because it will contribute to a reduction not only in operational costs but also in the amount of waste that is dumped and burned in landfills every year. Following on from previous studies by the authors, in this work several carbon-based adsorbents were developed from different carpet wastes (pre-consumer and post-consumer wastes) by chemical activation with KOH at various activation temperatures (600–900 °C) and KOH:char impregnation ratios (0.5:1 to 4:1). The prepared materials were characterised by chemical analysis and gas adsorption (N₂, −196 °C; CO₂, 0 °C), and tested for CO₂ adsorption at temperatures of 25 and 100 °C. It was found that both the type of precursor and the conditions of activation (i.e. impregnation ratios, and activation temperatures), had a huge influence on the microporosity of the resultant samples and their CO₂ capture capacities. The carbon-based adsorbent that presented the maximum CO₂ capture capacities at 25 and 100 °C (13.8 wt.% and 3.1 wt.%, respectively), was prepared from a pre-consumer carpet waste and was activated at 700 °C using a KOH:char impregnation ratio of 1:1. This sample showed the highest narrow microporosity volume (0.47 cm³ g⁻¹), thus confirming that only pores of less than 1 nm are effective for CO₂ adsorption at atmospheric pressure.     

Techno-economic study of CO2 capture from natural gas based hydrogen plants

Canadian oil sands are considered to be the second largest oil reserves in the world. However, the upgrading of bitumen from oil sands to synthetic crude oil (SCO) requires nearly ten times more hydrogen (H₂) than conventional crude oils. The current H₂ demand for oil sands operations is met mostly by steam reforming of natural gas (SMR). The future expansion of oil sands operations is likely to quadruple the demand of H₂ for oil sand operations in the next decade.This paper presents modified process schemes that capture CO₂ at minimum energy penalty in modern SMR plants. The approach is to simulate a base case H₂ plant without CO₂ capture and then look for the best operating conditions that minimize the energy penalty associated with CO₂ capture while maximizing H₂ production. The two CO₂ capture schemes evaluated in this study include a membrane separation process and the monoethanolamine (MEA) absorption process. A low energy penalty is observed when there is lower CO₂ production and higher steam production. The process simulation results show that the H₂ plant with CO₂ capture has to be operated at lower steam to carbon ratio (S/C), higher inlet temperature of the SMR and lower inlet temperatures for the water gas-shift (WGS) converters to attain lowest energy penalty. Also it is observed that both CO₂ capture processes, the membrane process and the MEA absorption process, are comparable in terms of energy penalty and CO₂ avoided when both are operated at conditions where lowest energy penalty exists.     

Modeling CO2 capture with aqueous monoethanolamine

Hilliard completed several thermodynamic models in Aspen Plus^® for modeling CO₂ removal with amine solvents, including MEA–H₂O–CO₂. This solvent was selected to make a system model for CO₂ removal by absorption/stripping. Both the absorber and the stripper used RateSep? to rigorously calculate mass transfer rates. The accuracy of the new model was assessed using a recent pilot plant run with 35 wt.% (9 m) MEA. Absorber loading and removal were predicted within 6%, and the temperature profile was approached within 5 °C. An average 3.8% difference between measured and calculated values was achieved in the stripper. A three-stage flash configuration which efficiently utilizes solar energy was developed. It reduces energy use by 6% relative to a simple stripper. Intercooling was used to reach 90% removal in the absorber at these optimized conditions.     

Post-combustion CO2-capture from coal-fired power plants: Preliminary evaluation of an integrated chemical absorption process with piperazine-promoted potassium carbonate

The simulation tool ASPEN Plus^® is used to model the full CO₂-capture process for chemical absorption of CO₂ by piperazine-promoted potassium carbonate (K₂CO₃/PZ) and the subsequent CO₂-compression train. Sensitivity analysis of lean loading, desorber pressure and CO₂-capture rate are performed for various solvent compositions to evaluate the optimal process parameters. EbsilonProfessional^® is used to model a 600 MW_el (gross) hard coal-fired power plant. Numerical equations for power losses due to steam extraction for solvent regeneration are derived from simulation runs. The results of the simulation campaigns are used to find the process parameters that show the lowest specific power loss. Subsequently, absorber and desorber columns are dimensioned to evaluate investment costs for these main components of the CO₂-capture process. Regeneration heat duty, net efficiency losses and column investment costs are then compared to the reference case of CO₂-capture by monoethanolamine (MEA).CO₂-capture by piperazine-promoted potassium carbonate with subsequent CO₂-compression to 110 bar shows energetic advantages over the reference process which uses MEA. Additionally, investment costs for the main components in the CO₂-capture process (absorber and desorber columns) are lower due to the enhanced reaction kinetics of the investigated K₂CO₃/PZ solvent which leads to smaller component sizes.     

Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture,transport and storage

Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO₂) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer.Results show that the sequestration of 90% CO₂ from the flue gas results in avoiding 70% of CO₂ emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NO_x from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs.The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories.     

Kinetics of sulfur dioxide- and oxygen-induced degradation of aqueous monoethanolamine solution during CO2 absorption from power plant flue gas streams

Studies of the kinetics of sulfur dioxide (SO₂)- and oxygen (O₂)-induced degradation of aqueous monoethanolamine (MEA) during the absorption of carbon dioxide (CO₂) from flue gases derived from coal- or natural gas-fired power plants were conducted as a function of temperature and the liquid phase concentrations of MEA, O₂, SO₂ and CO₂. The kinetic data were based on the initial rate which shows the propensity for amine degradation and obtained under a range of conditions typical of the CO₂ absorption process (3–7 kmol/m³ MEA, 6% O₂, 0–196 ppm SO₂, 0–0.55 CO₂ loading, and 328–393 K temperature). The results showed that an increase in temperature and the concentrations of MEA, O₂ and SO₂ resulted in a higher MEA degradation rate. An increase in CO₂ concentration gave the opposite effect. A semi-empirical model based on the initial rate, ?r_MEA = {6.74 × 10⁹ e^?(29,403/RT)[MEA]^0.02([O]^2.91 + [SO₂]^3.52)}/{1 + 1.18[CO₂]^0.18} was developed to fit the experimental data. With the higher order of reaction, SO₂ has a higher propensity to cause MEA to degrade than O₂. Unlike previous models, this model shows an improvement in that any of the parameters (i.e. O₂, SO₂, and CO₂) can be removed without affecting the usability of the model.     

Power generation with CO2 capture: Technology for CO2 purification

The goal of this paper is to find methodologies for removing a selection of impurities (H₂O, O₂, Ar, N₂, SO_x and NO_x) from CO₂ present in the flue gas of two oxy-combustion power plants fired with either natural gas (467 MW) or pulverized fuel (596 MW). The resulting purified stream, containing mainly CO₂, is assumed to be stored in an aquifer or utilized for enhanced oil recovery (EOR) purposes. Focus has been given to power cycle efficiency i.e.: work and heat requirements for the purification process, CO₂ purity and recovery factor (kg of CO₂ that is sent to storage per kg of CO₂ in the flue gas). Two different methodologies (here called Case I and Case II) for flue gas purification have been developed, both based on phase separation using simple flash units (Case I) or a distillation column (Case II). In both cases purified flue gas is liquefied and its pressure brought to 110 atm prior to storage.Case I: A simple flue gas separation takes place by means of two flash units integrated in the CO₂ compression process. Heat in the process is removed by evaporating the purified liquid CO₂ streams coming out from both flashes. Case I shows a good performance when dealing with flue gases with low concentration of impurities. CO₂ fraction after purification is over 96% with a CO₂ recovery factor of 96.2% for the NG-fired flue gas and 88.1% for the PF-fired flue gas. Impurities removal together with flue gas compression and liquefaction reduces power plant output of 4.8% for the NG-fired flue gas and 11.6% for the PF-fired flue gas. The total amount of work requirement per kg stored CO₂ is 453 kJ for the NG-fired flue gas and 586 kJ for the PF-fired flue gas.Case II: Impurities are removed from the flue gas in a distillation column. Two refrigeration loops (ethane and propane) have been used in order to partially liquefy the flue gas and for heat removal from a partial condenser. Case II can remove higher amounts of impurities than Case I. CO₂ purity prior to storage is over 99%; CO₂ recovery factor is somewhat lower than in Case I: 95.4% for the NG-fired flue gas and 86.9% for the PF-fired flue gas, reduction in the power plant output is similar to Case I.Due to the lower CO₂ recovery factor the total amount of work per kg stored CO₂ is somewhat higher for Case II: 457 kJ for the NG-fired flue gas and 603 kJ for the PF-fired flue gas.     

Assessment of the different parameters affecting the CO2 purity from coal fired oxyfuel process

The oxyfuel process is one of the most promising options to capture CO₂ from coal fired power plants. The combustion takes place in an atmosphere of almost pure oxygen, delivered from an air separation unit (ASU), and recirculated flue gas. This provides a flue gas containing 80–90 vol% CO₂ on a dry basis. Impurities are caused by the purity of the oxygen from the ASU, the combustion process and air ingress. Via liquefaction a CO₂ stream with purity in the range from 85 to 99.5 vol% can be separated and stored geologically. Impurities like O₂, NO_X, SO_X, and CO may negatively influence the transport infrastructure or the geological storage site by causing geochemical reactions. Therefore the maximum acceptable concentrations of the impurities in the separated CO₂ stream must be defined regarding the requirements from transportation and storage. The main objective of the research project COORAL therefore is to define the required CO₂ purity for capture and storage.     

A model for the CO2 capture potential

Global warming is a result of increasing anthropogenic CO₂ emissions, and the consequences will be dramatic climate changes if no action is taken. One of the main global challenges in the years to come is therefore to reduce the CO₂ emissions.Increasing energy efficiency and a transition to renewable energy as the major energy source can reduce CO₂ emissions, but such measures can only lead to significant emission reductions in the long-term. Carbon capture and storage (CCS) is a promising technological option for reducing CO₂ emissions on a shorter time scale.A model to calculate the CO₂ capture potential has been developed, and it is estimated that 25 billion tonnes CO₂ can be captured and stored within the EU by 2050. Globally, 236 billion tonnes CO₂ can be captured and stored by 2050. The calculations indicate that wide implementation of CCS can reduce CO₂ emissions by 54% in the EU and 33% globally in 2050 compared to emission levels today.Such a reduction in emissions is not sufficient to stabilize the climate. Therefore, the strategy to achieve the necessary CO₂ emissions reductions must be a combination of (1) increasing energy efficiency, (2) switching from fossil fuel to renewable energy sources, and (3) wide implementation of CCS.     

Exergy analysis as a tool for the integration of very complex energy systems: The case of carbonation/calcination CO2 systems in existing coal power plants

A common characteristic of carbon capture and storage systems is the important energy consumption associated with the CO₂ capture process. This important drawback can be solved with the analysis, synthesis and optimization of this type of energy systems. The second law of thermodynamics has proved to be an essential tool in power and chemical plant optimization. The exergy analysis method has demonstrated good results in the synthesis of complex systems and efficiency improvements in energy applications.In this paper, a synthesis of pinch analysis and second law analysis is used to show the optimum window design of the integration of a calcium looping cycle into an existing coal power plant for CO₂ capture. Results demonstrate that exergy analysis is an essential aid to reduce energy penalties in CO₂ capture energy systems. In particular, for the case of carbonation/calcination CO₂ systems integrated in existing coal power plants, almost 40% of the additional exergy consumption is available in the form of heat. Accordingly, the efficiency of the capture cycle depends strongly on the possibility of using this heat to produce extra steam (live, reheat and medium pressure) to generate extra power at steam turbine. The synthesis of pinch and second law analysis could reduce the additional coal consumption due to CO₂ capture 2.5 times, from 217 to 85 MW.     

Viscosities, thermal conductivities and diffusion coefficients of CO2 mixtures: Review of experimental data and theoretical models

Accurate experimental data on the thermo-physical properties of CO₂-mixtures are pre-requisites for development of more accurate models and hence, more precise design of CO₂ capture and storage (CCS) processes. A literature survey was conducted on both the available experimental data and the theoretical models associated with the transport properties of CO₂-mixtures within the operation windows of CCS. Gaps were identified between the available knowledge and requirements of the system design and operation. For the experimental gas-phase measurements, there are no available data about any transport properties of CO₂/H₂S, CO₂/COS and CO₂/NH₃; and except for CO₂/H₂O(/NaCl) and CO₂/amine/H₂O mixtures, there are no available measurements regarding the transport properties of any liquid-phase mixtures. In the prediction of gas-phase viscosities using Chapman–Enskog theory, deviations are typically <2% at atmospheric pressure and moderate temperatures. The deviations increase with increasing temperatures and pressures. Using both the Rigorous Kinetic Theory (RKT) and empirical models in the prediction of gas-phase thermal conductivities, typical deviations are 2.2–9%. Comparison of popular empirical models for estimation of gas-phase diffusion coefficients with newer experimental data for CO₂/H₂O shows deviations of up to 20%. For many mixtures relevant for CCS, the diffusion coefficient models based on the RKT show predictions within the experimental uncertainty. Typical reported deviations of the CO₂/H₂O system using empirical models are below 3% for the viscosity and the thermal conductivity and between 5 and 20% for the diffusion coefficients. The research community knows little about the effect of other impurities in liquid CO₂ than water, and this is an important area to focus in future work.