Supercritical Coal-fired Power Plant Research Articles

Life cycle assessment of a cleaner supercritical coal-fired power plant

The energy mix of developing countries is dominated by fossilized energy resources. As such technological improvements for cleaner power generation and better environmental performance are crucial. Power generation by coal also causes many environmental externalities, which requires comprehensive scientific analysis to develop appropriate cleaner production measures for ecological and energy conservations. A cleaner coal-fired power plant at Sahiwal, Pakistan has been recently installed and started electricity generation under a bilateral economic initiative known as the China-Pakistan Economic Corridor (CPEC) project. This study is aimed to analyse the life cycle impacts of process stages (material and coal transportation, and plant operations) of this coal-fired power plant. Functional unit of 1 MWh of electricity generated has been selected to depict the results, which reveal highest impact score in the climate change potential category (7.41E+02 kg CO2 eq.) whereas, least impact was noted in stratospheric ozone depletion category (8.27E-08 kg CFC11 eq.) The operational stage of the plant has been a major impact contributor in all the selected midpoint categories except for human toxicity potential. Overall, this power plant is effectively reducing its eco-footprint because of cleaner supercritical power generation technology, high thermal efficiency, lesser CO2 emissions and modern pollution monitoring and management system. Real-time scientific cleaner energy-management as presented in this study can help in the development of optimal policy framework to steer cleaner coal power generation in developing countries for a greater energy sustainability.

Thermodynamic modeling and performance evaluation of a supercritical coal-fired power plant situated in Western India

ABSTRACT Energy consumption in India is increasing drastically due to the increase in its population every year. In this severe condition, it is highly desirable to focus on the performance of existing and upcoming power plants in India using thermal performance analysis of each plant. The subcritical power plants are going to be replaced by supercritical power plants (SUPP) in the present scenario in the country. The present study deals with the thermal performance analysis of a 660 MW capacity coal-fired SUPP situated in western India. The thermodynamic modeling with empirical relation of each of its components is done and executed in MATLAB programming interface. The pure sliding pressure with variation in plant load is taken for constructing a semi-empirical model. The properties of steam are considered as per the IAPWS IF-97 standard. The results obtained from the simulation model are validated with actual operational data of the plant. The amount of coal consumption, steam mass flow rate, plant overall efficiency with variation in plant load is analyzed and compared with the operational data. The output obtained from the simulated program found to be satisfactory by comparing it with the actual operational plant data under study. The condenser rejects 36.42% of total heat to cooling water. The predicted steam generator efficiency of 86.04% is validated with actual steam generator efficiency. The simulated model of the SUPP will help those technologists and investigators who are putting their effort into improving the performance of coal-fired power plants.

A Modified SQP-based Model Predictive Control Algorithm: Application to Supercritical Coal-fired Power Plant Cycling

In this paper, a modified sequential quadratic programming (SQP)-based model predictive control (MPC) algorithm is developed and implemented for power plant cycling applications. These applications...

Flexible operation of supercritical coal-fired power plant integrated with solvent-based CO2 capture through collaborative predictive control

This paper presents a controller design study for the supercritical coal fired power plant (CFPP) integrated with solvent-based post-combustion CO 2 capture (PCC) system. The focus of the study is on the steam drawn-off from turbine to the re-boiler, which is the key interaction between the CFPP and PCC plants. The simulation study of a 660 MW supercritical CFPP-PCC unit model has shown that the impact of re-boiler steam change on the power generation of CFPP is more than 100 times faster than that on the PCC operation. Considering this finding, a collaborative predictive control strategy is proposed for the CFPP-PCC system where the re-boiler steam flowrate is manipulated for the CFPP load ramping and then gradually set to the required value for CO 2 capture. The PCC is thereby exploited as an energy storage device, which can quickly store/release extra energy for the CFPP in addition to the primary function of carbon emission reduction. The simulation results show that the proposed collaborative predictive controller can effectively improve the load ramping performance of CFPP without much performance degradation on the PCC operation. • Collaborative predictive control strategy for the integrated CFPP-PCC system. • PCC exploited as auxiliary measure for power adjustment in addition to CO 2 capture. • Impact of re-boiler steam change on CFPP is 100 times faster than that on the PCC. • Dynamic control operating simulation of the supercritical CFPP-PCC process. • Performance of different CFPP-PCC control schemes is assessed.

An integrated de-carbonization supercritical coal-fired power plant incorporating a supplementary steam turbine, process heat recovery and a modified boiler structure

Monoethanolamine (MEA) based CO2 capture in coal-fired power plants would consume a huge amount of the steam bleed from the steam turbines for the solvent regeneration. The unmatched steam bleed parameters for the solvent regeneration, as well as the huge amount of the process waste heat within the CO2 capture process, inevitably bringing about a significant efficiency penalty. In this study, a novel de-carbonization supercritical coal-fired power plant, which encompasses a supplementary steam turbine (SST), process heat recovery and a modified boiler heating exchangers configuration was proposed. In the proposed system, the steam bleeds for the reboiler and part of the regenerative heaters are coming from the SST, which is located in the upstream of the reheater (steam side), instead of the high and intermediate-pressure turbines (IPT), making the parameters of the steam bleed more matched with the solvent regeneration and feed water heating. In addition, part of the process heat within the CO2 capture/compression unit was efficiently recovered and beneficially used to heat the ambient air before its entering the air pre-heater. The saved flue gas can then be used to heat the feed/condensed water in the low-temperature economizer (LTE), saving part of the steam bleed from the turbines. The configuration of the superheaters/reheaters, as well as the air preheaters were also modified. The mass and energy balance as well as the system thermodynamic performance were determined by the developed models and process simulation. The economic performance of the proposed system was assessed by the cost of electricity (COE) and the cost of CO2 avoided (COA). Finally, the off-design performance of the proposed system was determined. Results showed that the energy efficiency penalty of the proposed system could decrease by 3.86%-points as compared to the reference system. The COE and COA of the proposed system without considering the CO2 transportation and storage cost were $86.11/MWh and $36.92/ton CO2, respectively, both less than those of the reference plant. The off-design operation analysis indicated that the proposed plant also featured a thermodynamics superiority in a wide range of power load variation.

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.

Energy and Exergy Analyses of Chemical Looping Combustion based 660 MWe Supercritical Coal Fired Power Plant

Coal still remains to be the major resource for power production in many countries. Supercritical (SupC) steam generated coal-fired power plants (CFPPs) are found to be superior to subcritical steam generated plants in terms of the overall plant efficiency. Chemical looping combustion (CLC), which is an indirect combustion between fuel and air, is an innovative, inherent CO2 capture and recent technology for power production. In this study, two cases - conventional SupC CFPP without CO2 capture and CLC-based SupC CFPP for high-ash Indian coal have been simulated. Detailed energy and exergy analyses are conducted for both the cases and compared. The study shows that CLC-based capture technology has less energy penalty with Fe2O3 oxygen carrier and little energy gain with CuO and NiO carriers compared to conventional plant without CO2 capture. This study demonstrates the superiority of CLC-based SupC CFPP for CO2 capture over the conventional plant.

Energy and exergy analyses of chemical looping combustion-based 660 MW<SUB align="right">e supercritical coal-fired power plant

Energy and exergy analyses of chemical looping combustion-based 660 MW<SUB align="right">e supercritical coal-fired power plant

Operation strategy optimization of desulfurization system based on data mining

Desulfurization systems in coal-fired power stations often suffer the problem of high operating costs caused by a rule-of-thumb control strategy, which implies great potential for optimization of the operation. Due to the complex desulfurization mechanism, frequently fluctuating unit load, and severe disturbance, it is challenging to determine the optimal operating parameters based on the traditional mechanistic models, and the operating parameters are closely related to the operational efficiency of the flue gas desulfurization system. In this paper, an operation strategy optimization method for the desulfurization process is proposed based on a data mining framework, which is able to determine online the optimal operating parameter settings from a large amount of historical data. First, Principal Component Analysis (PCA) is used to reduce data redundancy by mapping the data into a new vector space. Based on the new vector space, an enhanced fuzzy C-means clustering (Enhanced-FCM) is developed to cluster the historical data into groups sharing similar characteristics. Taking sulfur dioxide emission concentration as a constraint condition, the system is optimized with economic benefits and desulfurization efficiency as the objective function. When performing optimization, the group that current operating conditions belong to is determined first, then the operating parameters of the best performance are searched within the group and provided as the optimization results. The method is validated and tested based on the data from a wet flue gas desulfurization (WFGD) system of a 1000 MWe supercritical coal-fired power plant in China. The results indicate that the proposed operation strategy can appropriately obtain operating parameter settings at different conditions, and effectively reduce the desulfurization cost under the constraint of meeting emission requirements.

Modeling and performance analysis of subcritical and supercritical coal-fired power plants with biomass co-firing and CO2 capture

Coal-fired power plants are the largest source of carbon dioxide (CO2) emissions into the atmosphere, and these emissions can be effectively reduced by improving the efficiency of the plants, co-firing sustainably grown biomass and applying carbon capture and storage technologies. In this study, the energy and environmental performances of both subcritical (SubC) and supercritical (SC) pulverized coal-fired power plants with biomass co-firing and integrated with an advanced amine-based postcombustion CO2 capture system were evaluated and compared. The impact of biomass (hybrid poplar) addition was investigated at different co-firing ratios varying up to 30% on a heat input basis. All plant configurations were modeled and simulated with Aspen Plus process simulation software. The results show that the use of a SC steam cycle has a positive impact on the energy and environmental performance of the investigated plants, improving the efficiency by 2.4% points and reducing the total fuel consumption and CO2 emissions by 6% in comparison to those of the SubC cases. Biomass co-firing has a negative impact on the energy performance of plants while significantly reducing fossil-based carbon emissions. The reduction of net CO2 emissions is almost proportional to the biomass percentage in the feed. At 30% biomass co-firing, the net plant efficiency is reduced by approx. 1% point, while the net CO2 emissions are 28% lower than those in coal-fired only plants. The introduction of CO2 capture has a major impact both on the emissions generated and on the energy efficiency. Depending on the plant type and co-firing ratio used, the net plant efficiencies are 8.7–9.3% points lower than those of non-capture cases. The net CO2 emissions achieve negative values when carbon is captured from the biomass co-firing plants.

Exergy analysis of the regulating measures of operational flexibility in supercritical coal-fired power plants during transient processes

Operational flexibility improvement of coal-fired power plants has become a priority objective with the high penetration of renewable energy sources. The regulating measures applied frequently in improving the operational flexibility indeed affect the exergy efficiency of coal-fired power units during transient processes. In this study, the exergy efficiency evaluation of operational flexibility measures during primary frequency control processes was focused on, and the exergy analysis methods of the thermal system were used on the basis of the second law of thermodynamics to analyze the mechanisms for improving the flexibility at four regulation measures, and the exergy storage conversion efficiency and exergy destruction accumulation were quantitatively compared. It turns out that: among the throttling extraction steam of high-pressure heaters, feedwater bypass of high-pressure heaters, and condensate water decrease of low-pressure heaters measures, the exergy storage conversion efficiency and the exergy destruction accumulation increase with the regulating time of primary frequency control. The measure of throttling extraction steam of high-pressure heaters is the most potential option for improving operational flexibility, with maximum value of the maximal output power increment and maximal exergy storage change rate of 71.11 MW and −89.84 MW, respectively. With respect to the economy, the measure of throttling extraction steam of low-pressure heaters is the best option due to its smallest exergy destruction accumulation among all the measures. This study provides a detailed guidance for the selection of the optimal regulating measures when considering the enhancement of exergy efficiency and flexibility comprehensively under different conditions and periods.

Development of carbon-based vacuum, temperature and concentration swing adsorption post-combustion CO2 capture processes

Vacuum, temperature and concentration swing adsorption processes, have been designed to capture 85% of the CO2 emitted by an advanced supercritical coal fired power plant of 800 MW taken as reference, and to produce a concentrated product with 95% of CO2 (dry basis) using a sustainable carbon adsorbent inside the tubes of a tube-bundle adsorber. Indirect heat transfer is used to increase productivity and to conserve energy within the process. Two different configurations of the cyclic process have been evaluated at cyclic steady state through dynamic process simulation, using a detailed non-isothermal non-equilibrium fixed bed adsorption model that takes into consideration competitive adsorption between the main flue gas components: N2, CO2 and H2O. Simulation results indicate that the purity and recovery constraints can be met with a specific heat duty of 2.32MJth kg−1 CO2 and a specific electric consumption of 0.66MJekg−1 CO2. The main advantage of this process is that the specific heat duty, which is lower than the benchmark amine absorption technology, could be satisfied using waste heat.

Evaluation of a novel multibed heat-integrated vacuum and temperature swing adsorption post-combustion CO2 capture process

A novel multibed heat-integrated vacuum and temperature swing adsorption process has been designed to capture 85% of the CO2 emitted by an advanced supercritical coal fired power plant of 820 MWe taken as reference, and to produce a concentrated product with 95% of CO2 using a microporous carbon obtained from olive stones. The overall performance of the post-combustion CO2 capture process has been evaluated from the results of the dynamic simulation of the process at cyclic steady state, using a detailed non-isothermal non-equilibrium dynamic fixed-bed adsorption model that takes into consideration competitive adsorption between the main flue gas components: N2, CO2 and H2O. The proposed process operates between 30 °C and 1.05 bar and 80 °C and 0.05 bar. The specific heat duty of the process, 2.41MJth kg−1 CO2, which is lower than the benchmark amine absorption technology, can be satisfied using waste heat. On the other hand, its electricity consumption, 1.15MJekg−1CO2, is higher. Increasing the pressure of the production step reduces significantly the energy demand of the process, but also its capture rate. Substantial improvements in performance can be expected from adsorbent development. Adsorption is an environmentally benign technology with great potential to mitigate CO2 emissions from industrial processes with unused waste heat sources.

Techno-economic analysis of oxy-fuel IGCC power plants using integrated intermittent chemical looping air separation

Three oxy-fuel IGCC power plants using different air separation technologies and carbon compression and compression (CCP) are developed to near-zero CO2 emission power systems. If capturing CO2 is treated as a byproduct, Design 2 by an integration of IGCC and natural gas-fueled integrated intermittent chemical looping air separation (NG-IICLAS) may have a promising economic potential. Through the techno-economic assessment of Design 2, its internal rate of return (IRR) by 17.99% is higher than a chemical looping combustion (CLC)-based IGCC power plant connecting carbon capture and storage (CCS) with IRR = 12.5%, its levelized cost of electricity (LCOE) by 69.92 €/MWh is close to the LCOE of supercritical coal-fired power plant in 2015, and its CO2 production cost by 12.35 €/ton is also close to the market price for CO2 in 2011. It is successfully verified that the investing in Design 2 is superior to other designs.

Fatigue lifetime assessment on a high-pressure heater in supercritical coal-fired power plants during transient processes of operational flexibility regulation

The operational flexibility of coal-fired power plants has become a priority objective; however, the lifetime of main devices is reduced due to thermomechanical fatigue during transient processes. This study focuses on the safety of high-pressure heaters at operational flexibility measures. The dynamic characteristics of thermal parameters in the 1# HP heater were obtained and analyzed based on transient models of a coal-fired power plant. The change trends of pressure/temperature on the steam/feedwater side of the 1# HP heater at three throttling the extraction steam measures were different with that at the feedwater bypass measure. Subsequently, finite element analysis method was used, and the thermomechanical stresses under the four measures were calculated and analyzed. The time to reach the maximum mechanical stresses was shorter than that of thermal stresses. Finally, the fatigue lifetimes of the heater were estimated. The maximum fatigue damage ratio at the per load cycle was 0.0069%, and the minimal allowable number of cycle was 14413 in the upper region of the tube sheet when the extraction steams of #1, #2, and 3# HP heaters are regulated simultaneously. The study could offer data guidance to the safety and maintenance of coal-fired power plants during operational flexibility regulations.

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.

Impact of Coal Quality on Post-Combustion CO2 Capture in Indian Coal Power Plants

Coal is an abundantly available source for power generation in India, contributing about 77% in the total electricity generation in the country. India has substantial reserves of low sulphur, low grade (high ash) coal which is expected to continue to be a major energy source for the next few decades. But the coal-based thermal power industry is responsible for significant share of emissions of the industrial sector in India. Combustion of coal leads to emission of carbon dioxide (CO2), a prominent greenhouse gas (GHG) responsible for climate change. Various CO2 mitigation techniques including Carbon Capture and Sequestration (CCS) may be required in future to stabilize the greenhouse gas level in the atmosphere. The quality of coal used for power generation plays a critical role in deciding the need for appropriate emission control technologies, and affects the performance of the plant (plant efficiency, net electricity generation and CO2 emissions) and cost of electricity generation. It would also affect the overall performance and cost of CCS. This study investigates the impact of coal quality while implementing post-combustion carbon capture system and oxy-fuel carbon capture system in the new supercritical coal fired power plants in India. Pre-combustion CO2 capture in IGCC plant using the Indian coal is a challenge, and hence not included as an option in this analysis. This study focuses on post-combustion CO2 capture and oxy-fuel carbon capture system which seems a promising option in Indian context, considering the large existing pulverized coal (PC) fleet that is available in the country and the ease with which it can be retrofitted. Also, there have been large scale post combustion CCS based demonstration projects in Canada and U.S. with more upcoming projects planned globally. The scope of this work however, is limited till CO2 capture and compression and does not take into account technical and economic viability of transportation and long-term storage (T&S) of the captured CO2, due to the lack of reliable data and cost estimates. The Integrated Environmental Control Model (IECM) is used to simulate 500 MWe supercritical pulverized coal (PC) base plant, with and without CO2 capture system (post-combustion capture and oxy-fuel combustion). The performance of these plants is simulated using coals from different parts of the country, each with different composition, calorific value and pricing. In addition to the domestic coal, plants using imported coal are also simulated. Through this study, we wish to investigate the suitability of Indian coal for implementation of CCS in the country while providing a viable roadmap. Finally, we would also carry out uncertainty analysis to discuss how technical, economic and policy parameters would affect the relevance of CCS in India.

China baseline coal-fired power plant with post-combustion CO2 capture: 2. Techno-economics

Global efforts to advance CO2 capture technologies have produced a strong base of field experience and modeling capability to inform efforts to deploy this technology. In China, there are some important features of power plant construction, operation, and financing that lead to lower costs of CO2 capture relative to the United States and the most of the rest of the world. Moreover, unique aspects of the policy landscape in China, such as an openness to partial capture solutions in the near-term, allow for flexibility in deployment strategy. In this study, we define a set of “China baseline” reference cases and use them to analyze the costs of retrofit post-combustion CO2 capture at supercritical coal-fired power plants in China. We find the cost of post-combustion CO2 capture from power plants in China ranges from about 260 to 280 RMB/tCO2 (40–43 USD/tCO2) captured and 390 to 480 RMB/tCO2 (60–74 USD/ tCO2) avoided. This is at the higher end of the range of published literature estimates for China, but significantly lower than the corresponding ranges in the US for nominally the same technological approach. Lower costs in China have been primarily ascribed to lower capital costs, but a clear analysis of the full set of drivers for cost differences has not yet been published. Our analysis confirms the importance of capital savings, identifies the contributions from other significant factors such as fuel costs and power plant utilization, and explores several strategic implications for how these cost drivers might impact the deployment of CCS in China.

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.