MW Supercritical Coal-fired Power Plant Research Articles

Process simulation and techno-economic analysis of CO2 capture by coupling calcium looping with concentrated solar power in coal-fired power plant

The calcium looping (CaL) cycle is an effective high-temperature CO2 capture technology, its primary energy consumption arises from the calcination process, which limits the development of CaL technology. Utilizing concentrated solar power (CSP) instead of combustion for the calcination process in the CaL cycle can significantly reduce the energy penalty associated with CO2 capture of coal-fired power plants. Currently, the application of coupling CaL with concentrated solar power (CaL-CSP) systems in coal-fired power plants is still in its infancy, and there is limited research on its thermal performance and techno-economic analysis. In this study, a process simulation model of a 660 MW supercritical coal-fired power plant is developed as a reference. Subsequently, four different heat transfer routes are integrated into the design of CaL-CSP systems. The results indicate that the coupled power plant achieves a CO2 capture rate of 90 % compared to the reference coal-fired power plant, and reduces annual CO2 emissions by 93 % to only 58.2 g CO2/kWh. The CO2 capture energy penalty is 0.24 MJ/kg CO2. A sensitivity analysis of power generation cost reveals that if the cost of solar concentrator components is halved, the power generation cost will decrease to just 25 % higher than the reference power plant. Given the rapid advancements in CSP technology, this reduction is likely to be realized soon. Moreover, with the increase in carbon taxes and carbon prices, the power generation cost is expected to further decrease.

Economic Assessment of Coal-Fired Power Unit Decarbonization Retrofit with High-Temperature Gas-Cooled Reactors

To mitigate global warming, phasing out coal in the global energy system orderly and rapidly is an important near-term strategy. However, the majority of coal-fired plants in China have operated for less than 15 years. Accelerated coal power plant retirements would lead to substantial asset stranding. Coal-to-nuclear (C2N) technology offers a potential solution by replacing coal boilers in existing coal-fired plants with nuclear reactors. In this study, the G4-ECONS model was used to assess the economics of repowering a 600 MW supercritical coal-fired power plant with two 272 MWe high-temperature gas-cooled reactors. The timeline for the C2N project and the additional cost of dispatching electricity from the grid during retrofitting were discussed. Results showed that the C2N total capitalized costs are 19.4% (baseline estimate, USD 5297.6/kW) and 11.1% (conservative estimate, USD 5847.2/kW) lower than the greenfield project (USD 6576.5/kW), respectively. And C2N projects need to reduce LUEC by at least 20% to become competitive. This study can inform engineering design decisions leading to more precise and cost-effective C2N projects.

Thermal energy storage integration for increased flexibility of a power plant with post-combustion CO2 capture

Flexible operation of thermal power plants will become increasingly relevant in the coming years. This work evaluates the effect of integrating a steam accumulator into a 598 MW supercritical coal-fired power plant with moving bed temperature-swing adsorption CO2 capture. Charging the accumulator with reheat steam from the turbine train can reduce the net power output by up to 1.4 % (8.2 MW) for around 200 min. Small charging flow rates are recommended to maximize the final pressure of the accumulator. Covering the sorbent regeneration duty and meeting the demand of two feedwater heaters were considered as alternatives for discharging of the accumulator. Thermal storage discharging was found to give relative power plant load increases between 1.7 and 11.2 % (10.2–66.9 MW) for up to 37.5 min, which exceeds the requirement for primary reserve. Increases in the electrical energy output of 10.5–11 MWh were achieved. The flexibility modes studied in this work are compatible with high CO2 recovery rates.

Simultaneous parametric optimization for design and operation of solvent-based post-combustion carbon capture using particle swarm optimization

High investment and operating costs are two barriers hindering the commercial deployment of solvent-based post combustion CO2 capture (PCC) technology in power industry. Since upstream power plants are always in flexible operation, conventional approaches which carry out the design based on a fixed condition fail to achieve the best overall performance. To this end, this paper proposes a simultaneous size and operation parameters optimization strategy for the PCC process, in which the flexible operation of the CFPP is taken into account during the design stage. The technique of particle swarm optimization (PSO) is used in a hierarchical manner to find the design and operating conditions of the PCC with minimal total annualized cost. To further explore the optimization potential, the average CO2 capture level in one day is taken as the environmental constraint rather than the conventional instantaneous one. The proposed approach is tested on the PCC design for an existing 660 MW supercritical coal-fired power plant. The optimization results of four different design approaches are compared with the economic, efficiency and environmental (3E) performance being fully assessed. The simulation results show that by using the proposed optimization method, 14.45% reduction in TAC can be attained compared with the conventional approach.

Exergy and exergo-environmental analysis of a 660 MW supercritical coal-fired power plant

This paper presents the exergy and exergo-environmental analysis of the 660 MW supercritical coal-fired unit situated in western India. The study is based upon the SPECO approach, which is followed in the case of exergoeconomic analysis. The proposed research includes evaluating values of exergy of each stream, using F and P principal to find out exergy of fuel, the product of each component, and its exegetic efficiency. It further includes allocation of Eco-indicator 99 assessment grading values to perform life cycle assessment of each component, solving simultaneous equations by suitable solver formed from the environmental impact of components to calculate the exergo-environmental factor of each stream. The exergy efficiency obtained for the supercritical unit is 35.54%. The effect of variation of exergetic efficiency with an inlet pressure of high-pressure turbine for major components is studied. The major components such as steam generator, high-pressure turbine, intermediate-pressure turbine, low-pressure turbine, condensate extraction pump, and boiler feed pump exhibit higher exergetic efficiency at 247 bar. An increase in environmental impact in the exergy flows has been identified for components with having heat, work or fuel at the inlet. The cooling water used in condenser and flues gases exhausted from the supercritical power plant represent the environmental impact rate per unit electricity generated of 2.89 and 3.689 mPts kWh−1. The electricity generated had an environmental impact rate of 39.71 mPts kWh−1. The environmental impact per unit of electricity generated for 660 MW supercritical power plant is evaluated as 46.29 mPts kWh−1. The result obtained from semi-empirical model for environmental impact per unit of electricity is validated by comparing with subcritical and ultra-critical coal-fired power plant. The supercritical coal-fired power plant is proved to be better technology as compared with subcritical coal-fired power plant. The exergo-environmental variable for the steam generator offers high potential to reduce environmental impact by introducing an exhaust gas treatment unit.

Analysis and Treatment Measures of Continuous Emission Monitoring System Fouling in a Coal-Fired Power Plant after Ultra-Low Emission Transformation

Scanning electron microscopy (SEM) micro-morphology analysis, X-ray diffraction (XRD) and energy-dispersive X-ray diffraction (EDX) component analysis were conducted on the fouling of continuous emission monitoring system (CEMS) sampling tube at the outlet of limestone-gypsum wet flue gas desulfurization (WFGD) of unit 1 in a 600 MW supercritical coal-fired power plant in Inner Mongolia Autonomous Region. The results show that the main component of fouling was ammonium dihydrogen phosphate, which was generated by the reaction between phosphoric acid in the phosphoric acid titration device and the NH3 escaping from the selective catalyst reduction (SCR) denitrification system, and corresponding treatment measures were taken. It indicates that the average value of ammonia escape was reduced from 1.79 ppm to 1.54 ppm through the ammonia injection optimization test of the SCR denitrification system (at the load of 410 MW of the unit), which effectively reduced the generation of fouling. This research provides reference for improving the reliability of coal-fired unit operation after ultra-low emission transformation.

Artificial Intelligence-Based Emission Reduction Strategy for Limestone Forced Oxidation Flue Gas Desulfurization System

Abstract The emissions from coal power plants have serious implication on the environment protection, and there is an increasing effort around the globe to control these emissions by the flue gas cleaning technologies. This research was carried out on the limestone forced oxidation (LSFO) flue gas desulfurization (FGD) system installed at the 2*660 MW supercritical coal-fired power plant. Nine input variables of the FGD system: pH, inlet sulfur dioxide (SO2), inlet temperature, inlet nitrogen oxide (NOx), inlet O2, oxidation air, absorber slurry density, inlet humidity, and inlet dust were used for the development of effective neural network process models for a comprehensive emission analysis constituting outlet SO2, outlet Hg, outlet NOx, and outlet dust emissions from the LSFO FGD system. Monte Carlo experiments were conducted on the artificial neural network process models to investigate the relationships between the input control variables and output variables. Accordingly, optimum operating ranges of all input control variables were recommended. Operating the LSFO FGD system under optimum conditions, nearly 35% and 24% reduction in SO2 emissions are possible at inlet SO2 values of 1500 mg/m3 and 1800 mg/m3, respectively, as compared to general operating conditions. Similarly, nearly 42% and 28% reduction in Hg emissions are possible at inlet SO2 values of 1500 mg/m3 and 1800 mg/m3, respectively, as compared to general operating conditions. The findings are useful for minimizing the emissions from coal power plants and the development of optimum operating strategies for the LSFO FGD system.

Technical and economic analysis of amine-based carbon capture and sequestration at coal-fired power plants

This study assesses the overall cost of a typical 600 MW supercritical coal-fired power plant using amine adsorption Carbon Capture and Sequestration (CCS), which is a relatively mature CCS technology. Both newly constructed and existing power plants are considered in this analysis. The existing power plants, which are the most representative coal-fired power plants in China, are grouped into three scenarios based on whether they perform desulfurization and their desulfurization rates. An Integrated Environmental Control Model (IECM) is used to conduct the simulation and calculations for the three scenarios. This study reveals that the CO2 capture cost for a newly constructed power plant is 150 yuan/t, whereas, for an existing CCS retrofitted power plant, this cost ranges from 162 to 185 yuan/t. Furthermore, the avoided CO2 cost ranges from 258 to 350 yuan/t for the three scenarios considered in this analysis. The simulation results also reveal that the sulfur concentration in the exhaust gases of a power plant has an especially critical impact on the capture and electricity generation costs. Controlling the sulfur concentration in the exhaust gases is therefore an important measure for reducing the CCS capture cost. As CCS requires large initial capital investments, the influences of some financial parameters are assessed. The uncertainty analysis shows that as depreciation increases from 0.12 to 0.20, the average cost of avoided CO2 increases from 214 yuan/t to 517 yuan/t, which shows that the depreciation rate plays an important role in the economic assessment of carbon costs.

Study of supercritical power plant integration with high temperature thermal energy storage for flexible operation

Abstract The paper presents the recent research in study of the strategies for the power plant flexible operation to serve the requirement of grid frequency control and load balance. The study aims to investigate whether it is feasible to bring the High Temperature Thermal Storage (HTTS) to the thermal power plant steam-water cycle, to identify the suitable thermal charge and discharge locations in the cycle and to test how the HTTS integration can help support grid operation via power plant dynamic mathematical modelling and simulation. The simulation software named SimuEngine is adopted and a 600 MW supercritical coal-fired power plant model is implemented onto the software platform. Three HTTS charging strategies and two HTTS discharging strategies are proposed and tested via the simulation platform. The simulation results show that it is feasible to extract steam from the steam turbine to charge the HTTS, and to discharge the stored thermal energy back to the power generation processes. With the integration of the HTTS charge and discharge processes, the power plant simulation model is also connected to a simplified GB (Great Britain) grid model. Then the study is extended to test the improved capability of the plant flexible operation in supporting the responses to the grid load demand changes. The simulation results demonstrate that the power plant with HTTS integration has faster dynamic responses to the load demand changes and, in turn, faster response to grid frequency services.

Improving operational flexibility by regulating extraction steam of high-pressure heaters on a 660 MW supercritical coal-fired power plant: A dynamic simulation

The operational flexibility of a thermal power plant has played an essential and promising role in accommodating the increment of variability in the supply and demand sides in China. The rapid activation of thermal storage in entire coal-fired power plant lies at the heart for the strategy. Understanding the thermodynamic characteristics of the power unit in the transient process quantitatively remains a challenge. In this study, dynamic simulations of an entire 660 MW supercritical coal-fired power plant were conducted via GSE software, and the models were validated in the steady state and transient processes. Then, five different measures were introduced to regulate the extraction steam of high-pressure heaters for operational flexibility. The dynamic characteristics of the main thermodynamic parameters and output power were described and compared. Moreover, the operational flexibility of these measures was discussed. It turns out that: among the five measures, the change degrees of pressure, flowrate, and temperature in main devices increase with the increment in the number of throttled valves and/or the degree of feedwater bypass. The feedwater temperature at steady state reduces by 94.6 °C at most, and the maximum temperature change rate of metal slabs in HP heaters is −44.6 °C min−1. The dynamic process for output power under different measures has two different ramp stages, namely, a rapid stage and a slow stage. Furthermore, compared with other measures, 100% throttling extraction steam of #1, #2, and #3 HP heaters has the best operational flexibility, that is, the maximum average power ramp rate in a minute, power capacity, and energy capacity are 6.19% of rate power per minute, 48.40 MW, 5.58 MW h, respectively. The average power ramp rate, power capacity and energy capacity increase with the increment in the number of throttled valves and/or the degree of feedwater bypass. This work is expected to provide a detailed reference on the use of turbine thermal storage to improve the operational flexibility of coal-fired power plants.

Dynamic Modeling and Evaluation of an Industrial-Scale CO2 Capture Plant Using Monoethanolamine Absorption Processes

This paper presents a step-by-step method to scale-up an MEA (monoethanolamine) absorption plant for CO2 capture from a 750 MW supercritical coal-fired power plant. This CO2 capture plant consists of three absorbers (each 11.8 m in diameter and with 34 m of height) and two strippers (each 10.4 m in diameter with 16 m of height); the plant has been designed to achieve 87% CO2 recovery at 95% CO2 purity. A dynamic mechanistic model of a commercial-scale CO2 capture plant with a control scheme was developed in gPROMS and evaluated under several scenarios. The analysis revealed that this plant is able to reject various disturbances and switch between different operating points displaying prompt responses in the key controlled variables. Also, this study highlights that poor wetting in strippers can be avoided if the CO2 capture removal set point is scheduled based on the periodic operation of the power plant.

Dynamic Modelling and Controllability Studies of a Commercial-scale MEA Absorption Processes for CO2 Capture from Coal-fired Power Plants

Abstract This paper presents a mechanistic dynamic model of an industrial-scale carbon dioxide (CO 2 ) capture plant using Monoethanolamine (MEA) as an absorbent. In order to remove 87% of CO 2 from the flue gas stream generated from a 750 MW supercritical coal-fired power plant and produce a CO 2 concentration of 95% in the CO 2 product stream, a post-combustion CO 2 capture plant with three absorbers and two strippers are needed,. A decentralized control structure composed of 11 proportional- integral (PI) controllers was proposed to maintain the dynamic operability of this commercial-scale CO 2 capture plant. The evaluation of the plant's performance in closed-loop were conducted using multiple scenarios, i.e., the loss of CO 2 recovery (%CC) control loop during variation of flue gas flow rate, a positive ramp change in the flue gas flow rate under a maximum withdrawal constraint on the reboilers’ heat duty, and the disturbance in the flue gas composition resulting from the variation in coal composition and air flow rate. The controllability analysis performed on the proposed industrial-scale MEA absorption plant using the control system designed in this study shows that the plant is able to recover fast from most of the disturbances considered in the analysis. The insight provided from the present study can then be used to address the integration of the present CO 2 capture plant to a coal-based power plant and evaluate the dynamic feasibility of this integration under various scenarios.

Integration of CO 2 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 (CO 2) capture units into power plants, particularly the supercritical type, so that energy utilization and CO 2 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 CO 2 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 CO 2 captured and avoided. The parameters of interest include CO 2 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 CO 2 capture units through uses of blended monoethanolamine–methyldiethanolamine (MEA–MDEA) and split flow configuration can potentially make the integration of power plant and CO 2 capture unit less energy intensive. Despite the increase in energy penalty, it may be worth capturing CO 2 at a higher efficiency to achieve greater CO 2 emissions avoided. The flue gas delivery scheme and the steam pressure drawn from the power plant to the CO 2 capture unit should be considered for process integration.