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.     

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO₂ capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO₂ from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO₂ capture and compression integration into an 800 MW_e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO₂ capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh_e/tonne CO₂. The study also addresses the effect of CO₂ capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW_e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO₂ capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.     

Derivation of correlations to evaluate the impact of retrofitted post-combustion CO2 capture processes on steam power plant performance

When integrating a post-combustion CO₂ capture process and CO₂ compression into a steam power plant, the three interface quantities heat, electricity and cooling duty must be satisfied by the power plant, leading to a loss in net efficiency. The heat duty shows to be the largest contributor to the overall net efficiency penalty of the power plant. Additional energy penalty results from the cooling and electric power duty of the capture and compression units.In this work, the dependency of the energy penalty on the quantity and quality of the heat duty is analyzed and quantified for a state-of-the-art hard coal fired power plant. Furthermore, the energy penalty attributed to the additional cooling and power duty is quantified. As a result correlations are provided which enable to predict the impact of the heat, cooling and electricity duty of post-combustion CO₂ capture processes on the net output of a steam power plant in a holistic approach.     

Maintaining a neutral water balance in a 450 MWe NGCC-CCS power system with post-combustion carbon dioxide capture aimed at offshore operation

A post-combustion CO₂ capture process intended for offshore operations has been designed and optimised for integration with a natural gas-fired power plant on board a floating structure developed by the Norway-based company Sevan Marine ASA—designated Sevan GTW (gas-to-wire). The concept is constrained by the structure of the floater carrying a SIEMENS modular power system rated at 450 MW_e, with a capture rate of 90% and CO₂ compression (1.47 Mtpa) for pipeline pressure at 12 MPa. A net efficiency of 45% (based on a lower heating value) is estimated for the system with CO₂ capture, thus suggesting that the post-combustion CO₂ capture system is accountable for a fuel penalty of nine percentage points.The rationale behind the technology selection is the urgency of replacing the dispersed aero-derivative gas turbines which power the offshore oil and gas production units in Norwegian waters with near-zero emission power.As (inherently) fresh water usually constitutes a limiting factor in sea operations, efforts are made to obtain a neutral water balance to obtain an optimal design. This is primarily achieved by controlling the cleaned flue gas temperature at the top of the absorber column.     

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.     

Designing a supercritical steam cycle to integrate the energy requirements of CO2 amine scrubbing

Absorption by chemical solvents combined with CO₂ long-term storage appears to offer interesting and commercial applicable CO₂ capture technology. However one of the main disadvantages is related to the large quantities of heat required to regenerate the amine solvent that means an important power plant efficiency penalty. Different studies have analyzed alternatives to reduce the heat duty on the reboiler and the thermal integration requirements on existing power cycles. In these studies integration principles have been well set up, but there is a lack of information about how to achieve an integrated design and the thermal balances of the modified cycle flowsheet. This paper proposes and provides details about a set of modifications of a supercritical steam cycle to overcome the energy requirements through energetic integration with the aim of reducing the efficiency and power output penalty associated with CO₂ capture process. Modifications include a new designed low-pressure heater flowsheet to take advantage of the CO₂ compression cooling for postcombustion systems and integration of amine reboiler into a steam cycle. It has been carried out several simulations in order to obtain power plant performance depending on sorbent regeneration requirements.     

Optimal Absorbent Evaluation for the CO2 Separating Process by Absorption Loading,Desorption Efficiency,Cost, and Environmental Tolerance

The CO₂ absorption capacities of potassium glycinate, potassium sarcosinate (choline, proline), mono-ethanolamine (MEA), and tri-ethanolamine were evaluated to find the optimal absorbent for separating CO₂ from gaseous products by a CO₂ purification process. The absorption loading, desorption efficiency, cost, and environmental tolerance were assessed to select the optimal absorbent. MEA was found to be the optimum absorbent for separating the CO₂ and H₂ mixture in gaseous product. The maximum absorption loading rate was 0.77 mol CO₂ per mol MEA at temperature of 20°C and absorbent concentration of 2.5 mol/L, whereas desorption efficiency was 90% by heating for 3 h at 130°C. MEA was found to be an optimal absorbent for the purification process of CO₂ during gaseous production.     

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.     

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.     

Conceptual design of a three fluidised beds combustion system capturing CO2 with CaO

In this work, the Aspen Hysys conceptual design of a new process for energy generation at large scale with implicit CO₂ capture is presented. This process makes use of the CaO capability for CO₂ capture at high temperature and the possibility of regenerating this sorbent working in interconnected fluidised bed reactors operating at different temperatures. The proposed process has the advantage of producing power with minimum CO₂ emissions and very low energy penalties compared with similar air-based combustion power plants. In this system, five main parts can be distinguished: the combustor where coal is burnt with air, the calciner where the fresh and the recycled CaCO₃ is calcined, the carbonator where the CO₂ produced in the combustor is captured, the supercritical steam cycle and the CO₂ compression system. In this arrangement, the three fluidised bed reactors are interconnected in such a way that it is possible to perform the CaCO₃ calcination at a temperature of 950 °C with the energy transported by a hot solid stream produced in the circulating fluidised bed combustor operating at 1030 °C. The stream rich in CaO produced in the calciner is split into three parts. One of them is transported to the carbonator operating at 650 °C where most of the CO₂ in the flue gas produced in the combustor is captured. The second one is sent to the combustor, where it is heated up and used as energy carrier. The third solid stream that leaves the calciner is a purge in order to maintain the capture system activity and to avoid inert material accumulation. Because of the high temperatures involved in all the system, it is possible to recover most of the energy in the fuel and to produce power in a supercritical steam cycle. A case study is presented and it is demonstrated that under these operating conditions, 90% CO₂ capture efficiency can be achieved with no energy penalty further than the one originated in the CO₂ compression system.     

Calcium oxide for CO2 capture: Operational window and efficiency penalty in sorption-enhanced steam methane reforming

Calcium oxide (CaO) is a material that is being widely investigated in the context of CO₂ capture. One such application is as a CO₂ sorbent in the sorption-enhanced steam methane reforming processes (SERP). CO₂ is captured in an adsorption mode, where the conversion of CH₄ to H₂ is also enhanced, and released later in a separate desorption mode. This work presents an analysis of the relation between different process conditions and parameters during both adsorption and desorption modes. The interrelation between these conditions and the sorbent properties as well as the targeted carbon capture ratio is analysed. Conditions relevant for capturing 85% of carbon in the feed on CaO are determined and interlinked. A steam-to-carbon ratio of 4.2 has been determined to be relevant under 600 °C and 17 bar adsorption conditions. Similarly, process conditions relevant for regenerating the sorbent are determined and interlinked. For purge steam-to-CO₂ ratio of 1.8 at a desorption pressure of 1 bar, relevant desorption temperature has been calculated to be 820 °C. System simulations under these adsorption and desorption conditions resulted in a system efficiency of 50.8%. Effect of tuning process operating conditions on system efficiency as well as the efficiency penalty associated with the regeneration of the sorbent are investigated by process simulations using Aspen Plus^®. Possible system heat integration routes to reduce the efficiency penalty are proposed and the results of the process simulations are presented.     

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.     

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.     

Numerical parametric study on CO2 capture by indirect thermal swing adsorption

Post-combustion CO₂ capture remains one of the most-challenging issue to lower CO₂ emissions of existing power plants or heavy industry installations because of strong economy and energy efficiency aspects. The major issue comes from CO₂ dilution (4% for NGCC and 14% for PC) and the high flow rates to be treated. Furthermore, CO₂ purity has to be higher than 95% with recovery at 90%, to match the transportation/injection requirements.The MEA absorption process remains the reference today but its energy consumption (about 3 MJ/kg_CO2) and the amine consumption are still challenging drawbacks.The interest of CO₂ capture by indirect TSA (Temperature Swing Adsorption) was demonstrated experimentally in a previous work. The aim of this paper is to present the results of a numerical parametric study. Two main parameters are explored: the desorption temperature (100–200 °C) and the purge flow rate (0.1–0.5 Ndm³ min⁻¹). Four performance indicators are evaluated: CO₂ purity, recovery, productivity and specific energy consumption.Results show that purity above 95% can be achieved. Keeping the 95% target, it is possible to achieve recovery at 81% with productivity at 57.7 g_CO2/kg_ads h and a specific energy consumption of 3.23 MJ/kg_CO2, which is less than for the reference MEA process.Comparison with other adsorption processes exhibits that this process has good potential especially since some improvements are still expected from further research.     

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.     

SE-SMR process performance in CFB reactors: Simulation of the CO2 adsorption/desorption processes with CaO based sorbents

A 3D numerical model for gas–solid flow was developed and used to study the sorption enhanced steam methane reforming (SE-SMR) and the sorbent regeneration processes with CaO based sorbent in fluidized bed reactors. The SE-SMR process (i.e., SMR and adsorption of CO₂) was carried out in a bubbling fluidized bed. The effects of pressure and steam-to-carbon ratio on the reactions are studied. High pressure and low steam-to-carbon ratio will decrease the conversion of methane. But the high pressure makes the adsorption of CO₂ faster. The methane conversion and heat utility are enhanced by CO₂ adsorption. The produced CO₂ in SMR process is adsorbed almost totally in a relative long period of time in the bubbling fluidized bed. It means that the adsorption rate of CO₂ is fast enough compared with the SMR rate. The process of sorbent regeneration was carried out in a riser. An unfeasible residence time is required to complete the regeneration process. Higher temperature makes the release of CO₂ faster, but the rate is severely restrained by the increased CO₂ concentration in gas phase. The temperature distribution is uniform over the whole reactor. Regeneration rate and capacity of sorbents are important factors in selecting the type of reactors for SE-SMR process.     

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%.     

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.     

Evaluation of different CHP options for refinery integration in the context of a low carbon future

This study presents a comparison of different concepts for delivering combined heat and power (CHP) to a refinery in Norway. A reference case of producing high pressure steam from natural gas in boilers and electricity in a combined cycle power plant, is compared to a: (1) natural gas fueled CHP without any CO₂ capture; (2) hydrogen fueled CHP with hydrogen produced from steam methane reforming (SMR); (3) hydrogen fueled CHP with hydrogen produced from autothermal reforming (ATR); and finally (4) natural gas fueled CHP with postcombustion CO₂ removal. The options are compared on the basis of first law efficiency, emissions of CO₂ and a simplified cash flow evaluation. Results show that in terms of efficiency the standard natural gas fueled CHP performs better than the reference case as well as the options with carbon capture. The low carbon options in turn offer lower emissions of greenhouse gases while maintaining the same efficiency as the reference case. The cash flow analysis shows that for any option, a certain mix of prices is required to produce a positive cash flow. As expected, the relationship between natural gas price and electricity price affects all options. Also the value of heat and CO₂ emissions plays an important role.     

Life cycle assessment of carbon dioxide capture and storage from lignite power plants

In this article, we present a life cycle assessment (LCA) of CO₂ capture and storage (CCS) for several lignite power plant technologies. The LCA includes post-combustion, pre-combustion and oxyfuel capture processes as well as subsequent pipeline transport and storage of the separated CO₂ in a depleted gas field.The results show an increase in cumulative energy demand and a substantial decrease in greenhouse gas (GHG) emissions for all CO₂ capture approaches in comparison with power plants without CCS, assuming negligible leakage within the time horizon under consideration. Leakage will, however, not be zero. Due to the energy penalty, CCS leads to additional production of CO₂. However, the CO₂ emissions occur at a much lower rate and are significantly delayed, thus leading to different, and most likely smaller, impacts compared to the no-sequestration case. In addition, a certain share of the CO₂ will be captured permanently due to chemical reactions and physical trapping.For other environmental impact categories, the results depend strongly on the chosen technology and the details of the process. The post-combustion approach, which is closest to commercial application, leads to sharp increases in many categories of impacts, with the impacts in only one category, acidification, reduced. In comparison with a conventional power plant, the pre-combustion approach results in decreased impact in all categories. This is mainly due to the different power generation process (IGCC) which is coupled with the pre-combustion technology.In the case of the oxyfuel approach, the outcome of the LCA depends highly on two uncertain parameters: the energy demand for air separation and the feasibility of co-capture of pollutants other than CO₂. If co-capture were possible, oxyfuel could lead to a near-zero emission power plant.