Thermodynamic analysis and optimization of an oxy-fuel fluidized bed

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Process Systems Engineering

Thermodynamic analysis and optimization of an oxyfuel fluidized bed combustion power plant for CO2 capture Ran Yu, Shiyi Chen, and Wenguo Xiang Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.8b01498 • Publication Date (Web): 18 Oct 2018 Downloaded from http://pubs.acs.org on October 24, 2018

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Industrial & Engineering Chemistry Research

Thermodynamic analysis and optimization of an oxy-fuel fluidized bed combustion power plant for CO2 capture Ran Yu, Shiyi Chen, Wenguo Xiang* Key Laboratory of Energy Thermal Conversion and Control of Ministry of Education, School of Energy and Environment, Southeast University, China

Abstract: In this paper, a 600 MW supercritical oxy-fuel fluidized bed combustion power plant is integrated with an air separation unit (ASU) and a flue gas compression and purification unit (CPU). The plant performance is investigated, and two flue gas recirculation modes (i.e., wet and dry modes) are compared under different operating conditions. In the initial analysis, the drymode plant has a net power efficiency of 31.6%, while the wet-mode plant has a net power efficiency of 31.5%. In the sensitivity analysis, the air ingress has the most significant influence on the net power efficiency of the plant. The furnace combustion temperature also affects the net power efficiency. The plant is optimized by recovering heat from the ASU, CPU, and acid condensers and utilizing the heat to preheat the feedwater. Although the dry-mode plant has a higher efficiency before optimization, the wet-mode plant has a higher efficiency after *

Corresponding author, Email: [email protected]

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Industrial & Engineering Chemistry Research 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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optimization; i.e., the net power efficiency increases by 2.7% for the wet mode compared with 2.3% for the dry mode.

Keywords: Oxy-fuel combustion; Fluidized bed; Heat recovery; Optimization; CO2 capture 1. Introduction Anthropogenic CO2 emissions result in global warming, which has become a major concern in recent years 1. In 2013, global CO2 emissions from fossil fuel combustion totaled 36 billion tons, which was 2.3% higher than that in 2012 and 61% higher than that in 1990 firing power plants makes up the largest portion of CO2 emissions

4,5

2,3

. CO2 from coal

. However, coal firing

power plants will continue to dominate the electricity production sector for a long time due to abundant reserves and the low cost of coal

6-10

. Therefore, it is imperative to implement CO2

capture technology to mitigate CO2 emissions from coal firing power plants. Oxy-fuel combustion is an alternative method for CO2 capture in power plants. In oxy-fuel combustion, oxygen is mixed with recirculated CO2 in the flue gas, and injected into the furnace. The recirculated CO2 controls the adiabatic combustion temperature and creates a N2-lean, CO2rich environment for coal combustion

11-13

. The flue gas stream of oxy-fuel combustion is a

mixture of CO2 and H2O. After water condensation, pure CO2 is separated. Oxy-fuel combustion also alleviates the environmental impacts by decreasing NOx formation in the combustion process 14-16. Skorek-Osikowska et al.

17

found that the decrease in the net power efficiency of oxy-fuel

combustion is less than that of pre-combustion and post-combustion. Buhre et al. 18 analyzed the oxy-fuel combustion heat transfer profiles of boilers. The oxy-fuel combustion heat profiles are similar to those of air-firing boilers with recirculating flue gas. Descamps et al. 19 investigated


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two modes of flue gas recirculation, and their results showed that the dry mode was more efficient than the wet mode. Xiong et al. 20 optimized the parameters of distillation columns in an air separation unit (ASU) to obtain better thermodynamic and economic properties. Soundararajan et al.

21

carried out a pinch analysis and integrated the heat of the CO2 capture

process into the steam cycle. The results indicated that the overall efficiency increased by 1.5%. Gopan et al.

22

suggested that the heat from flue gas condensation as well as ASU compression

can be incorporated within the steam cycle to replace the low-pressure preheaters train. Kotowicz et al. 23 showed that efficiency penalty was reduced to 7.3% after heat recovery from an ASU and flue gas. Espatolero et al.

24

recovered the heat from an ASU and a flue gas compression and

purification unit (CPU), and the net electric efficiency was increased by approximately 3% without operational restrictions. Circulating fluidized bed (CFB) combustion is a clean and advanced technology for coal combustion. CFB is widely applied in industrial fields because of its advantages, including fuel flexibility and thorough gas-solid mixing 25-28. The operating temperature of CFB is 850−950oC, which is much lower than that of pulverized coal combustion and is particularly well suited for 29-32

reducing NOx emissions sulfur sorbent in CFB adopted in a furnace

33

34

pulverized coal furnace

. Low SOx emissions can be achieved by adding limestone as a

. CFB technology is a better solution when high oxygen levels are

because the heat distribution is more even in a CFB furnace than a 35

. The uniform heat distribution eliminates potential material and ash-

related issues. These benefits allow CFB to be a feasible and interesting CO2 capture option in the future. In this paper, a 600 MW oxy-fuel fluidized bed combustion power plant is modeled using Aspen Plus. The heat from the ASU and CPU compression processes and flue gas exhaust is recovered 3 Environment ACS Paragon Plus


and integrated with the steam cycle. Different flue gas recirculation modes are considered. The influences of the flue gas recirculation ratio, fluidized bed temperature, oxygen concentration, and air ingress on the plant performance are evaluated to conduct a comprehensive analysis of an oxy-fuel fluidized bed combustion power plant. 2. Process model development 2.1 Fluidized bed boiler The 600 MW supercritical oxy-fuel fluidized bed combustion power plant consists of a fluidized bed boiler, a steam cycle, an ASU and a CPU. The boiler consists of a CFB furnace, superheaters, reheaters, an economizer, an oxygen preheater and a flue gas electrostatic precipitator (ESP). A portion of the downstream flue gas is recirculated to the furnace. The temperature and moisture content of the recirculated flue gas vary depending on the flue gas recirculation position. There are two flue gas recirculation modes, i.e., the wet mode and the dry mode. In the wet mode, as shown in Figure 1a, a portion of the flue gas after the ESP is recirculated to the furnace. In the dry mode, as shown in Figure 1b, the flue gas after the ESP is cooled below its acid dew point in a preheater and then dehydrated. A portion of the dehydrated flue gas is recirculated to the preheater and is preheated by the flue gas from the ESP. Finally, the dehydrated and preheated flue gas is returned to the furnace. The temperature and the humidity of the flue gas are lower in the dry mode than the wet mode. 2.2 Steam cycle The adopted steam cycle refers to the cycle of a conventional air-firing power plant. The flowsheet of the steam cycle is illustrated in Figure 2. The system consists of a steam turbine,


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regenerative feedwater heating train, deaerator and condenser. The steam turbine is divided into a high-pressure (HP) section, an intermediate-pressure (IP) section and a low-pressure (LP) section. The steam from the boiler is used to spin the steam turbine. The steam that moves through the HP turbine is reheated in the boiler and then enters the IP turbine. The steam exhausted from the LP turbine enters the condenser. The water condensed in the condenser is then pressurized by a condensation pump. To increase the efficiency of a power plant, regenerative heating is adopted in the steam cycle. The regenerative feedwater heating train includes three HP heaters and four LP heaters. Steam is extracted from the steam turbine to heat the feedwater. A deaerator is placed between the HP and LP heaters. 2.3 ASU The oxygen for oxy-fuel combustion is produced from a cryogenic ASU. The ASU consists of a compressor, an expander, a heat exchanger and a distillation column, as illustrated in Figure 3. The inlet air is compressed to 0.6 MPa through the compressor and then cooled to 40oC by circulating water. The compressed air is then split into two streams, which are further cooled by the -190−-180oC product streams from the distillation column. One air stream decreases to a temperature of -172oC and enters the lower distillation column. The temperature of the other air stream decreases to -120oC and this air stream expands in an expander, which further decreases the temperature. After expansion, the air stream is fed to the upper distillation column. The temperature and pressure of the stream in the upper distillation column are lower than those of the stream in the lower distillation column. In the lower distillation column, the N2-rich stream at the top outlet and the O2-rich stream at the bottom outlet enter the upper distillation column through two throttle valves. In the upper distillation column, the oxygen concentration in the O2rich stream increases in stages, and finally, the O2-rich stream with the desired oxygen 5 Environment ACS Paragon Plus


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concentration is discharged from the bottom of the upper distillation column. The other inlet air gases are discharged from the top of the upper distillation column. In this work, the specific power requirement is 0.263 kWh/kg O2. This value is reasonable and in the range of 0.220−0.270 kWh/kg O2 (95 vol. %) based on other literature 36-38. 2.4 CPU In most literature, the typical of CO2 pressure and temperature ranges are 8−20 MPa and 0−50oC, respectively

3,20,24

, and the compression ratio is usually in the range of 1.6−2.4

21,39,40

. In this

work, CO2 is compressed to 15 MPa and is ready for delivery and storage. The compression process includes six stages, as shown in Figure 4. The compression ratio in each stage is kept constant at 2.3 to minimize the compression work. Each stage consists of a compressor, a heat exchanger and a flash. The flue gas is cooled to 40oC by circulating water after compression. The saturation temperature of steam in the flue gas increases as the pressure increases, and it is easier for steam to condense into liquid water. The liquid components are then removed from the flue gas in the flash units. The concentration of CO2 in the flue gas finally increases to 90% after the six-stage compression process and water content removal. 2.5 Assumptions A bituminous coal is adopted in the simulation. The coal analysis is shown in Table 1. For oxyfuel combustion, excess oxygen is needed in the boiler and the excess oxygen ratio is assumed to be 3% to minimize the unburnt carbon loss

41,42

. The operating temperature of the fluidized bed

is set in the range of 850−950oC. The fluidized bed temperature can be controlled by regulating the flue gas recirculation ratio. The inlet air mass flow to the ASU is adjusted to maintain an


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excess oxygen ratio of 3%. Due to the presence of sulfur in the fuel, SO2 and SO3 are present in the flue gas, which may lead to low-temperature corrosion in the flue gas channel. Thus, for conventional metal heat exchangers, it is necessary to maintain the exhaust flue gas temperature above the acid dew point. The acid dew point can be predicted using Eq. (1) 3:

(

)

T = 203.25 + 27.6lg PH2O +10.83lg PSO3 +1.06 lg PSO3 + 8

2.19

(1)

where T is the acid dew point, oC; PH2O and PSO3 are the partial pressures of H2O and SO3 in the flue gas, respectively, bar. In the wet mode, the acid dew point of the exhaust gas is ~209oC. The exhaust temperature of the flue gas here is kept at 255oC to avoid acid corrosion. The property method used is the Peng-Robinson equation of state with Boston-Mathias modifications (PRBM)

20,39,43

. Pure water and steam streams are calculated using ASME 1967 steam table

corrections. The other primary parameters are shown in Table 2. 3. Results and discussion 3.1 Fluidized bed temperature The performance of the plant with variations in the fluidized bed temperature is shown in Figure 5. It is assumed that there is no air ingress in the boiler. Using 900oC as the initial case, the net power output is 600 MW for the wet mode, and 600.6 MW for the dry mode. The flue gas components are shown in Table 3. The net power efficiency is 31.5% for the wet mode and 31.6% for the dry mode. In current large-scale air-firing steam power plants without CO2 capture, the net power efficiency can be 42−45%

35,44

. However, after implementing carbon

capture and compression, the net power efficiency decreases by more than 10%.



With an increase in the fluidized bed temperature from 850oC to 950oC, the net power output of the plant in the wet mode increases by 3.1 MW, and the net power output of the plant in the dry mode increases by 3.3 MW. The net power efficiency of the wet-mode plant increases from 31.4% to 31.6% and that of the dry-mode plant increases from 31.5% to 31.7%. A portion of the flue gas after dust removal is recirculated to control the temperature in the furnace. The flue gas recirculation ratio refers to the molar ratio of recirculated flue gas to the total flue gas leaving the furnace. The fluidized bed temperature is associated with the inlet oxygen concentration and the heat flux in the furnace. To increase the fluidized bed temperature, the inlet oxygen concentration needs to be increased by decreasing the flue gas recirculation ratio, and thus, the total amount of flue gas flow to the stack decreases. With an increase in the fluidized bed temperature, the flue gas recirculation ratio in the wet mode decreases from 0.69 to 0.63, resulting in an auxiliary power reduction of 24.4% for the circulating fan. Similarly, the flue gas recirculation ratio in the dry mode decreases from 0.72 to 0.69, resulting in an auxiliary power reduction of 17.2% for the circulating fan. The gases entering the furnace include both the O2 stream from the ASU and the recirculated flue gas. The excess oxygen ratio in the furnace is kept constant at 3%, and the decrease in the flue gas recirculation ratio increases the oxygen output from the ASU and the power requirement of the ASU and induced fan. The power of the steam turbine increases, the power required by the ASU and induced fan increases, and the power required by the circulating fan decreases. Finally, the net power output and net power efficiency increase. Compared with the wet mode, the dry mode has an additional heat exchanger and flash unit. The temperature of the flue gas in the dry mode is further reduced by 50oC in the heat exchanger. The


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steam condenses, and the resulting steam content in the dry mode is only 1/10 of that in the wet mode. The specific heat capacity of steam is much higher than that of CO2. At a constant fluidized bed temperature, the recirculated flue gas flow rate needed in the wet mode is more than that needed in the dry mode; thus, the flue gas recirculation ratio is higher in the dry mode, as shown in Figure 5. However, the recirculated flue gas is at a lower temperature in the dry mode than the wet mode, which decreases the power requirement of the circulating fan in the compression process. The overall power output of a plant is related to the power produced by the steam turbine and the total power requirement of all auxiliary components. The power consumed by the ASU and the induced fan in the dry mode is less than that consumed in the wet mode. The net power output and efficiency of the dry mode are therefore higher than those of the wet mode. 3.2 Air ingress In a practical fluidized bed boiler, the furnace operates at a pressure slightly higher than the atmosphere. However, as the flue gas passes through the furnace and downstream channel, the pressure decreases, and air ingress may occur due to opening observation ports and failing seals in the flue gas channel. The air ingress ratio is defined as the molar fraction of air that infiltrates into the boiler to the total flue gas. The combustion temperature of the fluidized bed is 900oC. The amount of flue gas slightly increases with an increase in the air ingress. Thus, the flue gas recirculation ratio necessary to achieve the target temperature decreases. In the wet mode, the flue gas recirculation ratio decreases from 0.66 to 0.64, as shown in Figure 6. Consequently, the power requirement of the circulating fan and induced fan decreases by 3.1%, but the power demanded from the CPU increases by 20.2% due to the presence of more non-condensable impurities in the CO2 stream.



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The reduction in the power requirements of the fans is less than the power increase in the CPU. Therefore, the net power efficiency of the plant decreases by 0.8%. The process of the dry mode is similar to that of the wet mode. Figure 6 shows the flue gas recirculation ratio decreases from 0.72 to 0.68. The power required by the circulating fan and induced fan is reduced by 8.2%, but the power required by the CPU increases by 21.2%. Thus, the net power efficiency of the plant is reduced by 0.7%. 3.3 CO2 purification The flue gas from an oxy-fuel combustion boiler is a CO2-rich stream. The CO2 concentration can be up to 90% after the six-stage compression process and water content removal. The CO2rich stream includes impurities and traces of H2O, N2, O2, SO2, SO3, NO and NO2. In some scenarios, the CO2-rich stream needs to be refined to decrease the impurities to permitted levels for further utilization or geographic storage. For instance, in enhanced oil recovery, impurities in the injected CO2 stream could hinder the ability of the injected fluid to meet the criteria for achieving miscibility. The H2O, O2 and SOx present in the CO2 pipeline transport system must be removed to prevent potential corrosion and other defects in the pipelines. The required concentration of CO2 is above 95%, non-condensable N2 gas in the CO2-rich stream should be less than 4%, and NOx and SOx contents should be less than 100 ppm

45,46

. Low-temperature

physical separation technology can be applied to purify CO2. The purification process can be implemented by retrofitting an existing CPU, as shown in Figure 7. The flue gas stream is compressed to 28.2 bar in the first four stages. The water content of the flue gas is reduced to 1 ppm through molecular sieves. The CO2-rich stream is then precooled by the -70−-30oC outlet streams from the distillation column to -24.5oC and enters the first distillation column (T1) for


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denitrification. The CO2-rich stream is discharged from the bottom of T1, and other gases (N2, O2, NO, and NO2) are discharged from the top of T1. The desulfurization process is similar to denitrification, and it is accomplished in a second distillation column (T2). The dew point of SOx is lower than that of CO2. The refined CO2-rich stream is discharged from the top of T2, and SOx is discharged from the bottom of T2. Finally, the refined CO2-rich stream is compressed from 10 to 150 bar in the last four stages and cooled to 40oC for transportation and storage. The purity of the refined CO2 is increased to 98.4% with a recovery rate of 90.2%. The water, NOx and SOx contents remaining in the CO2-rich stream are merely 1 ppm, 86 ppm and 23 ppm, respectively. 3.4 Heat integration Oxy-fuel combustion needs pure O2, which is produced by the ASU. In the ASU, air is compressed to a high pressure before entering a distillation column. The separated CO2 after oxy-fuel combustion also needs to be compressed before CO2 delivery and storage. Both compression processes have considerable energy penalties. To increase plant efficiency, heat from the compression processes in the ASU and CPU can be recovered and integrated with the steam cycle system by heating the feedwater. Thus, the ASU and CPU can act as heaters, i.e., ASU and CPU heaters. As shown in Figure 8, the dotted heat exchangers in the feedwater train can be substituted with ASU and CPU heaters. Heat recovery can reduce steam extraction from the steam turbine for regenerative heating. The flue gas from oxy-fuel combustion is a mixture of CO2 and steam. The steam fraction is more than 0.10 of the flue gas. The latent heat of the steam in the flue gas is large, and the plant performance can potentially be enhanced by recovering this latent heat through steam condensation. 3.4.1 Air compression in the ASU



The inlet air temperature required by the distillation column is relatively low, especially that of the upper column. To obtain a low temperature, the air is first compressed to a high pressure. After compression, the air temperature is increased to 267oC, and then cooled to 40oC by circulating water. The compressed air is further cooled by the O2 and N2 streams in the multistream heat exchanger and then sent to the turbine for expansion. After expansion, the lowtemperature air is sent to the distillation column. In a conventional ASU, the compressed air is cooled by environmental water, and heat is wasted. In the optimization, the high-temperature compressed air can be used to heat the low-pressure feedwater after the condensation pump. The heat exchanger L1 in Figure 8 can be substituted by an ASU heater. After the heat exchange, the compressed air continues to be cooled by the distillation column products in the multi-stream heat exchanger. In this way, the L1 steam extraction is completely eliminated, and the amount of steam extracted from the steam turbine for L2 is reduced. For a given coal feeding rate, the ASU air flow rates in the wet and dry modes are slightly different, and the plant in the wet mode requires slightly more air than that in the dry mode. Therefore, the amount of heat recovered in the ASU is different for the two modes. For the wet mode, the low-pressure feedwater after the ASU heater can be heated to 102.8oC, the steam extracted from the steam turbine is reduced by 185.5 t/h, the net power output increases by 21.8 MW, and the net power efficiency increases by 1.2%. For the dry mode, the low-pressure feedwater after the ASU heater can be heated to 103.1oC, the steam extracted from the steam turbine is reduced by 187.6 t/h, the net power output increases by 21.9 MW and the net power efficiency increases by 1.2%. 3.4.2 CO2 compression in the CPU


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In the CPU, the compression process is divided into six stages with water intercooling. The intercooling during compression is necessarily implemented for each stage due to the following benefits: 1) the compression work is proportional to the initial stream temperature, and a cooling step can reduce the compression work; 2) the saturated temperature of steam increases with pressure, and a portion of steam in the CO2-rich stream can condense in the cooling process, which increases the CO2 purity in the resulting CO2-rich stream. The heat from flue gas compression can also be recovered to heat the feedwater by using a multistream heat exchanger. The compressed CO2-rich stream from each stage enters the heat exchanger to heat the low-pressure feedwater. The heater exchangers L1 and L2 in Figure 8 can be substituted by CPU heaters. The low-pressure feedwater can be heated up to 92.4oC. The L1 steam extraction is completely eliminated, and the amount of steam extracted for L2 is reduced. For the wet mode, the net power increases by 18.4 MW, and the net power efficiency increases by 1.0%. For the dry mode, the low-pressure feedwater can be heated to 89.4oC, the net power increases by 12.5 MW, and the net power efficiency increases by 0.7%. The efficiency increase in the dry mode is less than that in the wet mode because the flue gas recirculation ratio is higher in the dry mode and less flue gas is treated in the CPU. In the dry mode, the steam fraction in the compressed CO2-rich stream is lower, and the available latent heat recovered from water condensation is less than that recovered in the wet mode. 3.4.3 Exhaust gas The flue gas from oxy-fuel combustion contains not only CO2 and H2O but also SO2 and SO3. The temperature of the exhaust gas from the boiler is conventionally maintained above the acid dew point (~209oC) to avoid acid corrosion. The exhaust temperature here is 255oC for both the



wet and dry mode. The heat loss from stack gas is large, and the latent heat of the steam is substantial. Therefore, an acid condenser with acid-resistant materials, such as ceramic and plastic

47

, is applied for heat recovery to reduce this heat loss. The arrangement of the acid

condenser in both the wet and dry mode is shown in Figure 9. In the wet mode, the low-pressure feedwater is heated from 34.6oC to 90.5oC. The net power output increases from 600 MW to 609.6 MW, and the net power efficiency increases by 0.5%. In the dry mode, the stack temperature before the gas preheater is 255oC, and the flue gas is cooled in the gas preheater to 128.7oC to preheat the recirculated flue gas. In the optimized layout, the heat of the flue gas before recirculation is recovered by the acid condenser. Although the flow rate of the flue gas in the dry mode is approximately three times that in the wet mode, the moisture content of the flue gas in the dry mode is relatively low. The feedwater temperature increases from 34.6oC to 78.9oC after the acid condenser. Finally, the heat recovered increases the net power output from 600.6 MW to 607.7 MW, and the net power efficiency increases from 31.6% to 31.9%. 3.4.4 Overall integration The heat recovery from the ASU, CPU and acid condenser can be integrated to improve the overall power plant performance. The ASU, CPU, and acid condenser substitute for the lowpressure feedwater heaters L1, L2, and L3, and act as the ASU heater, CPU heater, and acid condenser. The three surrogate heaters provide six arrangements with which to heat the lowpressure feedwater. The flow sequence of the low-pressure feedwater after exiting the condenser is shown in Table 4.


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A comparison of the various layout schemes is shown in Figure 10. The performance of the wet mode is different from that of the dry mode. For both the wet and dry modes, Case 4 ‘CPU heater - Acid condenser - ASU heater’ has the highest net power efficiency. The ASU heater is located in the last position in the optimal scheme because the average temperature of the ASU heater is higher than that of the CPU heater and acid condenser. Matching the ASU heater with the higher temperature feedwater reduces the temperature difference and creates close temperature profiles for heat transfer, which increase the heat recovery efficiency. The air after compression in the ASU is at 267oC, which is higher than that of the water after the feedwater pump. Therefore, the air after compression can be applied to heat the high-pressure feedwater. Here, the ASU heater is divided into two parts: one part is used to heat the highpressure feedwater, and the other part is used to heat the low-pressure feedwater. As shown in Figure 8, H1 is partly substituted by the ASU heater, and the ASU heater can also substitute for L1 and L2. There are also six arrangements as shown in Table 5. A comparison of the different layout schemes is shown in Figure 11. The performance variation in each scheme is primarily caused by the temperature differences between the hot and cold streams in the heater exchangers. A lower temperature difference decreases steam extraction from the steam turbine, increasing the net power efficiency. The layout of Case 8 shows the best performance for both wet and dry modes, and the optimal schematic flowsheet is shown in Figure 12. Compared with the basic operating conditions, the net power efficiency in Case 8 increases by 2.7% in the wet mode and 2.3% in the dry mode. This improvement is satisfactory and competitive compared with the efficiency of other oxy-fuel combustion power plants in the literature 21-23.



4 Conclusions An analysis and optimization of a 600 MW oxy-fuel fluidized bed combustion power plant is performed. Two plant configurations are analyzed based on two flue gas recirculation methods: wet mode and dry mode. In the initial case with a fluidized bed temperature of 900oC, the net power efficiency of the plant is 31.5% in the wet mode and 31.6% in the dry mode. The net power efficiency of the wet-mode plant is slightly lower than that of the dry-mode plant due to the higher recirculation power in the wet mode. High fluidized bed temperatures favor the net power efficiency. In the sensitivity analysis, as the fluidized bed temperature increased in the range of 850−950oC, the net power efficiency of the wet-mode plant increases from 31.4% to 31.6% and that of the dry-mode plant increases from 31.5% to 31.7%. With an increase in the air ingress ratio in the range of 0−5%, the net power efficiency of the wet-mode plant decreases by 0.8% and that of the dry-mode plant decreases by 0.7%. Heat recovery within the process of the ASU, CPU and acid condenser increases the net power efficiency. Feedwater heaters can be partly substituted by ASU and CPU heaters and acid condensers. The optimal scheme for the feedwater train is ‘CPU heater - ASU heater II - Acid condenser - ASU heater I’. In the optimal cases, the net power efficiency could be 34.3% in the wet mode, increasing by 2.7% relative to the initial case, and the net power efficiency could be 33.8% in the dry mode, increasing by 2.3% relative to the initial case. Acknowledgements


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The authors wish to express thanks to the support of National Key R&D Program of China (2016YFB0600802) and National Natural Science Foundation of China (51606038) for this work. References (1) Hong, J.; Chaudhry, G.; Brisson, J. G.; Field, R.; Gazzino, M.; Ghoniem, A. F. Analysis of oxy-fuel combustion power cycle utilizing a pressurized coal combustor. Energy 2009, 34, 1332. (2) IEA. CO2 Emissions from Fuel Combustion Highlights. IEA: Paris, France, 2010. (3) Yan, K.; Wu, X.; Hoadley, A.; Xu, X.; Zhang, J.; Zhang, L. Sensitivity analysis of oxy-fuel power plant system. Energy Convers. Manage. 2015, 98, 138. (4) Suriyawong, A.; Gamble, M.; Lee, M.-H.; Axelbaum, R.; Biswas, P. Submicrometer particle formation and mercury speciation under O2-CO2 coal combustion. Energy Fuels 2006, 20, 2357. (5) Chen, S.; Lior, N.; Xiang, W. Coal gasification integration with solid oxide fuel cell and chemical looping combustion for high-efficiency power generation with inherent CO2 capture. Appl. Energy 2015, 146, 298. (6) Zheng, Q.; Zhou, S.; Lail, M.; Amato, K. Oxygen removal from oxy-combustion flue gas for CO2 purification via catalytic methane oxidation. Ind. Eng. Chem. Res. 2018, 57, 1954. (7) Wang, C.; Lei, M.; Liu, H.; Lu, H. Combustion characteristics and nitric oxide release of the pulverized coals under oxy-enrich conditions. Ind. Eng. Chem. Res. 2012, 51, 14355. (8) Scala, F.; Chirone, R. Combustion of single coal char particles under fluidized bed oxyfiring conditions. Ind. Eng. Chem. Res. 2010, 49, 11029. (9) Wall, T. F. Combustion processes for carbon capture. Proc. Combust. Inst. 2007, 31, 31. (10) Chen, L.; Yong, S. Z.; Ghoniem, A. F. Oxy-fuel combustion of pulverized coal: Characterization, fundamentals, stabilization and CFD modeling. Prog. Energy Combust. Sci. 2012, 38, 156. (11) Andersson, K.; Johnsson, F. Process evaluation of an 865MWe lignite fired O2/CO2 power plant. Energy Convers. Manage. 2006, 47, 3487. (12) Khare, S. P.; Wall, T. F.; Farida, A. Z.; Liu, Y.; Moghtaderi, B.; Gupta, R. P. Factors influencing the ignition of flames from air-fired swirl pf burners retrofitted to oxy-fuel. Fuel 2008, 87, 1042. (13) Ying, Z.; Zheng, X.; Cui, G. Pressurized oxy-fuel combustion performance of pulverized coal for CO2 capture. Appl. Therm. Eng. 2016, 99, 411.



(14) Li, D.; Liu, X.; Feng, Y.; Wang, C. a.; Lv, Q.; Zha, Q.; Zhong, J.; Che, D. Effects of oxidant distribution mode and burner configuration on oxy-fuel combustion characteristics in a 600MWe utility boiler. Appl. Therm. Eng. 2017, 124, 781. (15) Fan, W.; Li, Y.; Guo, Q.; Chen, C.; Wang, Y. Coal-nitrogen release and NOx evolution in the oxidant-staged combustion of coal. Energy 2017, 125, 417. (16) Jin, B.; Zhao, H.; Zheng, C. Optimization and control for CO2 compression and purification unit in oxy-combustion power plants. Energy 2015, 83, 416. (17) Skorek-Osikowska, A.; Bartela, L.; Kotowicz, J.; Job, M. Thermodynamic and economic analysis of the different variants of a coal-fired, 460MW power plant using oxy-combustion technology. Energy Convers. Manage. 2013, 76, 109. (18) Buhre, B. J. P.; Elliott, L. K.; Sheng, C. D.; Gupta, R. P.; Wall, T. F. Oxy-fuel combustion technology for coal-fired power generation. Prog. Energy Combust. Sci. 2005, 31, 283. (19) Descamps, C.; Bouallou, C.; Kanniche, M. Efficiency of an Integrated Gasification Combined Cycle (IGCC) power plant including CO2 removal. Energy 2008, 33, 874. (20) Xiong, J.; Zhao, H.; Chen, M.; Zheng, C. Simulation Study of an 800MWe Oxy-combustion Pulverized-Coal-Fired Power Plant. Energy Fuels 2011, 25, 2405. (21) Soundararajan, R.; Anantharaman, R.; Gundersen, T. Design of Steam Cycles for Oxycombustion Coal based Power Plants with Emphasis on Heat Integration. Energy Procedia 2014, 51, 119. (22) Gopan, A.; Kumfer, B. M.; Phillips, J.; Thimsen, D.; Smith, R.; Axelbaum, R. L. Process design and performance analysis of a Staged, Pressurized Oxy-Combustion (SPOC) power plant for carbon capture. Appl. Energy 2014, 125, 179. (23) Kotowicz, J.; Balicki, A. Enhancing the overall efficiency of a lignite-fired oxyfuel power plant with CFB boiler and membrane-based air separation unit. Energy Convers. Manage. 2014, 80, 20. (24) Espatolero, S.; Romeo, L. M.; Escudero, A. I.; Kuivalainen, R. An operational approach for the designing of an energy integrated oxy-fuel CFB power plant. Int. J. Greenh. Gas Control 2017, 64, 204. (25) Leckner, B.; Gómez-Barea, A. Oxy-fuel combustion in circulating fluidized bed boilers. Appl. Energy 2014, 125, 308. (26) Hnydiuk-Stefan, A.; Składzień, J. Analysis of supercritical coal fired oxy combustion power plant with cryogenic oxygen unit and turbo-compressor. Energy 2017, 128, 271. (27) Selvakumaran, P.; Lawerence, A.; Bakthavatsalam, A. K. Effect of additives on sintering of lignites during CFB combustion. Appl. Therm. Eng. 2014, 67, 480.


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(28) Arias, B.; Criado, Y. A.; Sanchez-Biezma, A.; Abanades, J. C. Oxy-fired fluidized bed combustors with a flexible power output using circulating solids for thermal energy storage. Appl. Energy 2014, 132, 127. (29) Li, S.; Li, H.; Li, W.; Xu, M.; Eddings, E. G.; Ren, Q.; Lu, Q. Coal combustion emission and ash formation characteristics at high oxygen concentration in a 1MWth pilot-scale oxy-fuel circulating fluidized bed. Appl. Energy 2017, 197, 203. (30) Li, Q.; Xu, H.; Li, F.; Li, P.; Shen, L.; Zhai, J. Synthesis of geopolymer composites from blends of CFBC fly and bottom ashes. Fuel 2012, 97, 366. (31) Chindaprasirt, P.; Rattanasak, U. Utilization of blended fluidized bed combustion (FBC) ash and pulverized coal combustion (PCC) fly ash in geopolymer. Waste Manage. 2010, 30, 667. (32) Li, F.; Zhai, J.; Fu, X.; Sheng, G. Characterization of Fly Ashes from Circulating Fluidized Bed Combustion (CFBC) Boilers Cofiring Coal and Petroleum Coke. Energy Fuels 2006, 20, 1411. (33) Stanger, R.; Wall, T.; Spörl, R.; Paneru, M.; Grathwohl, S.; Weidmann, M.; Scheffknecht, G.; McDonald, D.; Myöhänen, K.; Ritvanen, J.; Rahiala, S.; Hyppänen, T.; Mletzko, J.; Kather, A.; Santos, S. Oxyfuel combustion for CO2 capture in power plants. Int. J. Greenh. Gas Control 2015, 40, 55. (34) de Diego, L. F.; de las Obras-Loscertales, M.; Rufas, A.; García-Labiano, F.; Gayán, P.; Abad, A.; Adánez, J. Pollutant emissions in a bubbling fluidized bed combustor working in oxyfuel operating conditions. Effect of flue gas recirculation. Appl. Energy 2013, 12, 860. (35) Escudero, A. I.; Espatolero, S.; Romeo, L. M.; Lara, Y.; Paufique, C.; Lesort, A.-L.; Liszka, M. Minimization of CO2 capture energy penalty in second generation oxy-fuel power plants. Appl. Therm. Eng. 2016, 103, 274. (36) Allam, R.; White, V.; Ivens, N.; Simmonds, M. The oxyfuel baseline: revamping heaters and boilers to oxyfiring by cryogenic air separation and flue gas recycle. Elsevier 2005, 1, 451. (37) Deng, Z.; Jin, B.; Zhao, Y.; Gao, H.; Huang, Y.; Luo, X.; Liang, Z. Process simulation and thermodynamic evaluation for chemical looping air separation using fluidized bed reactors. Energy Convers. Manage. 2018, 160, 289. (38) Zhou, C.; Shah, K.; Song, H.; Zanganeh, J.; Doroodchi, E.; Moghtaderi, B. Integration options and economic analysis of an integrated chemical looping air separation process for oxyfuel combustion. Energy Fuels 2015, 30, 1741. (39) Soundararajan, R.; Gundersen, T. Coal based power plants using oxy-combustion for CO2 capture: Pressurized coal combustion to reduce capture penalty. Appl. Therm. Eng. 2013, 61, 115. (40) Toftegaard, M. B.; Brix, J.; Jensen, P. A.; Glarborg, P.; Jensen, A. D. Oxy-fuel combustion of solid fuels. Prog. Energy Combust. Sci. 2010, 36, 581.



(41) Normann, F.; Andersson, K.; Johnsson, F.; Leckner, B. Reburning in Oxy-fuel combustion: A parametric study of the combustion chemistry. Ind. Eng. Chem. Res. 2010, 49, 9088. (42) Arias, B.; An analysis of the operation of a flexible oxy-fired CFB power plant integrated with a thermal energy storage system. Int. J. Greenh. Gas Control 2016, 45, 172. (43) Gopan, A.; Kumfer, B. M.; Axelbaum, R. L. Effect of operating pressure and fuel moisture on net plant efficiency of a staged, pressurized oxy-combustion power plant. Int. J. Greenh. Gas Control 2015, 39, 390. (44) Zhaia, R.; Yub, H.; Chena, Y.; Lib, K.; Yang,Y. Integration of the 660 MW supercritical steam cycle with the NH3-based CO2 capture process: System integration mechanism and general correlation of energy penalty. Int. J. Greenh. Gas Control 2018, 72, 117. (45) Radgen, P.; Kutter, S.; Kruhl, J. The legal and political framework for CCS and its implications for a European Utility. Energy Procedia 2009, 1, 4601. (46) Besong, M. T.; Maroto-Valer, M. M.; Finn, A. J. Study of design parameters affecting the performance of CO2 purification units in oxy-fuel combustion. Int. J. Greenh. Gas Control 2013, 12, 441. (47) Koornneef, J.; Junginger, M.; Faaij, A. Development of fluidized bed combustion—An overview of trends, performance and cost. Prog. Energy Combust. Sci. 2007, 33, 19.


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Table 1. Proximate and ultimate properties of coal Proximate analysis (wt. %)

Ultimate analysis (wt. %)

Moisture

6.10

C

62.50

Fixed carbon

48.87

H

3.97

Volatile matter

28.28

O

8.84

Ash

16.75

N

0.70

LHV (kJ/kg)

24200

S

1.14



Table 2. Parameters of 600 MW oxy-fuel fluidized bed combustion power plant Item

Value

Fuel input (t/h)

283.3

Feedwater (t/h)

2394

Feedwater temperature (oC)

298

Fluidized bed temperature (oC)

850−950

Excess oxygen ratio

3%

Stack temperature (oC)

255

Main steam (oC/MPa)

600/26

Reheated steam (oC/MPa)

600/4.95

Condenser pressure (kPa)

4.72

Steam turbine efficiency (HP/IP/LP)

0.91/0.93/0.895

Pump efficiency

0.82

Compressor and blower efficiency

0.80

Ambient temperature (oC)

25


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Table 3. Flue gas components at the boiler stack in wet mode Flue gas components

Value

CO2 (vol. %)

62.0

O2 (vol. %)

3.4

N2 (vol. %)

4.9

H2O (vol. %)

29.3

NO (mg/m3)

330.3

NO2 (mg/m3)

0.5

SO2 (mg/m3)

6409.7

SO3 (mg/m3)

247.7



Table 4. Layout of the ASU heater, CPU heater and acid condenser Case

Sequence

Case 1

ASU heater - CPU heater - Acid condenser

Case 2

ASU heater - Acid condenser - CPU heater

Case 3

CPU heater - ASU heater - Acid condenser

Case 4

CPU heater - Acid condenser - ASU heater

Case 5

Acid condenser - CPU heater - ASU heater

Case 6

Acid condenser - ASU heater - CPU heater


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Table 5. Layout of the ASU heater (two parts), CPU heater and acid condenser Case

Sequence

Case 7

CPU heater - Acid condenser - ASU heater II - ASU heater I

Case 8

CPU heater - ASU heater II - Acid condenser - ASU heater I

Case 9

ASU heater II - CPU heater - Acid condenser - ASU heater I

Case 10

ASU heater II -Acid condenser - CPU heater - ASU heater I

Case 11

Acid condenser - ASU heater II - CPU heater - ASU heater I

Case 12

Acid condenser - CPU heater - ASU heater II - ASU heater I



Page 26 of 55

(a)

LSH HSH HRH Cyclone

LRH Econ.

To IP

Coal Oxygen preheater ASU

Air

Forced fan

Boiler

CPU ESP HP Fuel Gas Water Circulating fan (b)

LSH HSH HRH Cyclone To IP

LRH Econ.

Coal Oxygen preheater ASU

Air

Forced fan Boiler

Dehydration ESP

CPU

Gas preheater

HP Fuel Gas Water Circulating fan

Figure 1. Oxy-fuel fluidized bed combustion boiler (a) wet mode, and (b) dry mode


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Superheat steam

HP1

Superheat steam

HP2

Reheat steam

IP1

IP2

LP1

LP2

LP3

LP4

LP5

Condenser

H3

H2

H1

Feedwater pump

Deaerator

L4

L3

Figure 2. Steam cycle of the plant


L2

L1

Condenser pump


Page 28 of 55

Upper distillation column

Air

Turbine 1# Valve

Coolant water

2# Valve Compressor Lower distillation column ASU heater

Multi-stream heat exchanger O2

N2

To the boiler

Figure 3. Schematic flowsheet of the ASU


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Flue gas CO 2

C1

F1

1# Water

C2

F2

2# Water

C3

F3

3# Water

C4

F4

C5

4# Water

F5

5# Water

C6

F6

6# Water CPU heater

Coolant water

Figure 4. Schematic flowsheet of the CPU



31.7

Net power efficency in wet mode Net power efficency in dry mode Net power output in wet mode Net power output in dry mode

31.6

603

31.5

600 31.4

597 840

860

880

900

920

940

Net power efficiency (%)

Net power output (MW)

(a) 606

31.3 960


0.76

Recirculation ratio in wet mode Recirculation ratio in dry mode O2 concentration in wet mode O2 concentration in dry mode

0.72

31.5

30.0

28.5

0.68

27.0

0.64

25.5

O2 concentration (vol.%)

(b) 0.80

Recirculation ratio

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 30 of 55

24.0

0.60 850 860 870 880 890 900 910 920 930 940 950


Figure 5. Plant performance with the variation of the fluidized bed temperature (a) the net power output and efficiency, and (b) the recirculation ratio and O2 concentration into the furnace


620

Net power output Net power efficency Recirculation ratio


610 600

33

0.70

32

0.69

31

590 30 580 570

29

560

28

0.68 0.67 0.66 0.65

Recirculation ratio

(a)

0.64

550 27 -1

0

1

2

3

4

5

0.63

6

Air ingress (%) 32.0

610

Net power output Net powerefficiency 31.5 Recirculation ratio

600

31.0

590 30.5 580 570

30.0

560

29.5

0.74 0.73 0.72 0.71 0.70 0.69

Recirculation ratio

620


(b)


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60



Page 31 of 55

0.68

550 29.0 -1

0

1

2

3

4

5

0.67

6

Air ingress (%)

Figure 6. Plant performance with the variation of air ingress (a) wet mode, and (b) dry mode



Page 32 of 55

CO 2-rich stream

M1 F1

C1

F2

C2

F4

C4

3# Water

2# Water

1# Water

E1

F3

C3

E2

E3

4# Water

E4 Coolant water

C8

C7

C6

C5

T2 E10

E9

E8

E7

T1 E6

CO 2

Figure 7. Retrofitted CO2 compression and purification unit


E5

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H3

H2

H1

Feedwater pump

Deaerator

L4

L3

L2

Figure 8. Substitution of feedwater heaters


L1

Condenser pump


Page 34 of 55

(b)

(a)

Coal

Boiler

Coal

Boiler

ASU Oxygen preheater

Air

ASU Air

Forced fan

Oxygen preheater

Coolant water

Forced fan ESP

Coolant water ESP

Gas preheater Feeding water Acid condenser

Feeding water Acid condenser

CPU

Dehydration

CPU

Figure 9. Layout of the boiler system after adopting an acid condenser (a) wet mode, and (b) dry mode


Page 35 of 55

655 650


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Wet mode Dry mode

645 640 635 630 625 620

Case 1

Case 2

Case 3

Case 4

Case 5

Case 6

Figure 10. Plant performance from Case 1 to Case 6



655

Wet mode Dry mode 650


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 36 of 55

645

640

635

630

Case 7

Case 8

Case 9

Case 10

Case 11

Case 12

Figure 11. Plant performance from Case 7 to Case 12


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Superheat Superheat steam steam HP1

HP2

Reheat steam IP1

IP2

LP1

LP2

LP3

LP4

LP5

Condenser

H3

H2

H1

ASU heater I

Feedwater pump

Deaerator

L4

L3

Acid ASU heater II CPU heater Condenser condenser pump

Figure 12. Optimal scheme for the oxy-fuel fluidized bed combustion power plant



Table of Content (TOC)


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Figure 1. Oxy-fuel fluidized bed combustion boiler (a) wet mode, and (b) dry mode 288x260mm (200 x 200 DPI)

ACS Paragon Plus Environment


Figure 1. Oxy-fuel fluidized bed combustion boiler (a) wet mode, and (b) dry mode 386x288mm (200 x 200 DPI)


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Figure 2. Steam cycle of the plant 385x176mm (200 x 200 DPI)



Figure 3. Schematic flowsheet of the ASU 245x165mm (200 x 200 DPI)


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Figure 4. Schematic flowsheet of the CPU 382x130mm (200 x 200 DPI)



Figure 5. Plant performance with the variation of the fluidized bed temperature (a) the net power output and efficiency, and (b) the recirculation ratio and O2 concentration into the furnace 271x184mm (300 x 300 DPI)


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Figure 5. Plant performance with the variation of the fluidized bed temperature (a) the net power output and efficiency, and (b) the recirculation ratio and O2 concentration into the furnace 271x184mm (300 x 300 DPI)



Figure 6. Plant performance with the variation of air ingress (a) wet mode, and (b) dry mode 271x184mm (300 x 300 DPI)


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Figure 6. Plant performance with the variation of air ingress (a) wet mode, and (b) dry mode 271x184mm (300 x 300 DPI)



Figure 7. Retrofitted CO2 compression and purification unit 315x220mm (200 x 200 DPI)


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Figure 8. Substitution of feedwater heaters 351x51mm (200 x 200 DPI)



Figure 9. Layout of the boiler system after adopting an acid condenser (a) wet mode, and (b) dry mode 201x365mm (200 x 200 DPI)


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Figure 9. Layout of the boiler system after adopting an acid condenser (a) wet mode, and (b) dry mode 206x377mm (200 x 200 DPI)



Figure 10. Plant performance from Case 1 to Case 6 287x201mm (300 x 300 DPI)


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Figure 11. Plant performance from Case 7 to Case 12 287x201mm (300 x 300 DPI)



Figure 12. Optimal scheme for the oxy-fuel fluidized bed combustion power plant 409x156mm (200 x 200 DPI)


Page 54 of 55

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Table of Content (TOC) 57x40mm (600 x 600 DPI)


Thermodynamic analysis and optimization of an oxy-fuel fluidized bed

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