Integration of power plants with different capacities with aqueous

Subscriber access provided by Nottingham Trent University

Environmental and Carbon Dioxide Issues

Integration of power plants with different capacities with aqueous ammonia-based CO2 capture Rongrong Zhai, Lingjie Feng, Hai Yu, Yulong Wang, and Yongping Yang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b02226 • Publication Date (Web): 26 Aug 2019 Downloaded from pubs.acs.org on August 29, 2019

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

Page 1 of 46 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

Energy & Fuels

Integration

of

power

plants

with

different

capacities with aqueous ammonia-based CO2 capture Rongrong Zhai1*, Lingjie Feng1, Hai Yu2*, Yulong Wang1, Yongping Yang1 1

School of Energy Power and Mechanical Engineering, North China Electric Power

University, Beijing 102206, China 2

CSIRO Energy, 10 Murray Dwyer Circuit, Mayﬁeld West, NSW 2304, Australia

*Corresponding authors Abstract Integrating coal-fired power plant with NH3-based CO2 capture is a promising technology for CO2 capture. However, the output and efficiency of original coal fired power plant are reduced because the integration requires energy. This work studied three typical coal-fired power plants with the capacities of 330, 660, and 1000 MW and turbine levels of N330-16.67/538/538, N660-24.2/566/566, and N1000-25/600/600,

respectively. The integration of these coal-fired power plants with the same NH3-based post combustion CO2 capture system was established. Heat consumption, energy penalty, and other evaluation indicators were obtained through Ebsilon simulation. Among the three coal-fired power plants, the thermal efficiency of 1000 MW is the highest, whereas that of 330 MW is the lowest. The energy penalty of 660 MW coalfired power plant is the highest, whereas that of 330 MW is the lowest. To fully analyze the integration performance of power plants with different capacities, comprehensive evaluation of grey correlation of integrated system from six aspects based on grey relational degree method. Analysis results show that the correlation coefficient of 1000 MW coal-fired power plant is the highest, whereas that of 330 MW is the lowest. The energy consumption formula that was once proposed for a 660 MW coal-fired power plant is further optimized and a new evaluation system of integrated system combining energy consumption

ACS Paragon Plus Environment

Energy & Fuels 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

formula and grey correlation coefficient is presented. Keyword: NH3-based CO2 capture, coal fired power plant, different capacity

1.Introduction Greenhouse gases increase global temperatures. CO2 is the main greenhouse gas because the current world economy relies on fossil fuels for energy, and its combustion products are emitted into the atmosphere. In 2016, the global CO2 emissions reached 32.31 GtCO2 and increased by approximately 40% since 2000; the largest fraction comes from electricity and thermal power and accounts for 42% of the total emissions [1]. Until 2016, coal was the second energy source (27%) and is the largest source of emissions globally (44%) given its heavy carbon intensity [1]. With the environment requirements and greenhouse effect on climate change, CO2 capture and storage process has been developed to reduce CO2 emissions. CO2 capture can be divided into three catalogues. One is pre-combustion capture, which is the conversion of fossil fuels into a syngas composed of CO and H2 that captures CO2 after converting CO to CO2. Second is oxy-combustion capture, that is, coal-fired power plant separates high-purity oxygen from the air and used it to replace air combustion, which is composed of oxygen combustion, recycled waste gas, and purified CO2 flow, to eliminate incondensable gases. Third is postcombustion capture, which is the most common method to capture CO2. The CO2 in the exhaust gas is captured when the fuel is filled with air combustion [2-3]. Post-combustion capture using chemical absorbers is the most promising method to limit CO2 emissions from existing coal-fired power plant [4]. In the chemical absorption of CO2, the ideal solvent must have a high CO2 absorption capacity and can react rapidly and reversibly with CO2 with minimal heat demand. Amine has been explored as a good absorbent. In numerous amine solvents, the traditional chemical absorber is mainly MEA because of its rapid reaction and rich industrial application. However, MEA has a high regeneration dutyand easily degrades and corrodes [5-6]. The improvement of amine solvent and the development


Page 2 of 46

Page 3 of 46 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

Energy & Fuels

of new solvents are the main research directions for post-combustion CO2 capture. In addition to MEA, other amine solvents, such as 2-amino-2-methyl-1-propanol (AMP, primary amine), methyl ethanolamine (MMEAsecondary amine), diethanolamine (DEA, secondary amine) and methyl diethanolamine (MDEA, tertiary amine), are similar in structure with CO2 absorption rate slightly lower than that showed by MEA [7-8]. Zhao et al. [9] studied post-combustion CO2 capture and absorption based on MDEA/PZ in a 650 MW coal-fired power plant and found that the reboiler duty was as low as 2.4 GJ/t CO2, and its net efficiency loss is 16.1% lower than that of CO2 capture based on MEA under the same operating conditions. Zhang et al. [10] compared the absorption rate and volume of MEA, MEA+DEA, MEA+TEA, and MEA+AMP and found that 0.1 mol/L MEA+0.4 mol/L AMP had the fastest absorption rate, and its total absorption volume is 40% higher than that of MEA. Liu et al. [11] found that 2-(ethylamino)ethanol (EAE) and 2-(methylamino)ethanol (MAE)are alternative promising absorbents, and the energy efficiency for CO2 capture of 2.5 and 5.0 M EAE solutions are 52.9% and 32.3% higher than those of MEA solution, respectively. Ling et al. [12] experimentally investigated the physical solubility and the mass transfer absorption performance of CO2 into DMEA solution and found that the gas-phase volumetric overall mass-transfer coefficient increases with the amine concentration, liquid feed temperature, and liquid flow rate; decreases with the increasing lean CO2 loading; and slightly changes with the increasing inert gas flow rate and CO2 partial pressure. Except for new amine solvents, NH3 is also a potential substitute for traditional amine solvent because of its low cost, good thermal oxidation stability, large CO2 cycle capacity, and low regeneration energy and degradation resistance [13-15]. Given the high removal efficiency of NH3 for SO2 (> 99%), it can avoid the use of flue gas desulfurization (FGD) and hence greatly reduces the investment cost [16]. The improvement and innovation of CO2 capture is also one of the research focuses to reduce the energy consumption for this process. Li et al. [17] simulated CO2 capture by MEA in the installation of intercooling equipment, and the results revealed that the intercooling of the absorber reduces the regenerative duty from 3.6 MJ/kg CO2 to 3.55 MJ/kg CO2. Stoc et al. [18] injected lean amine instead of solvent discharged from the absorber with intercooling and found that the reboiler duty is reduced by approximately 5%. Yu et al. [19] showed through simulation that when the spilt fraction ratio is 0.05, the total energy load reaches the minimum value of 3.28 MJ/kg CO2


Energy & Fuels 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

and the reboiler and condenser duties are 2.89 and 0.39 MJ/kg CO2, respectively. These values are lower than those without the rich split. Gazzani et al. [20] investigated a second generation CAP by using a crystallizer to form solids and achieved 10% lower energy penalization compared with the total penalty of the standard CAP. Yu et al. [21] realized energy-saving NH3 recovery and the elimination of solid precipitation through process modification. This process can reduce energy requirement for CO2 regeneration and NH3 recovery by approximately 32% compared with that using conventional methods. Given that most CO2 emissions are from coal-fired power plants, the removal of CO2 from coalfired power plant has been extensively studied. CO2 capture system requires energy; hence, the integration of power plant with CO2 capture system reduces the net efficiency of the power plant. Decreasing the regeneration energy consumption and energy penalty and improving the net efficiency of a coal-fired power plant integrated with CO2 capture system have become a popular research topic for the integration of coal-fired power plant with chemical absorption for CO2 capture. In the CO2 capture system, the reboiler must consume heat to separate CO2. Finding the optimal steam extraction point to provide energy for CO2 capture system according to the energy cascade utilization principle is a major research focus to minimize energy loss and improve power plant efficiency after integration. Lucquiaud et al. [22] proposed three integration schemes, namely, (1) clutched low-pressure (LP) turbine, (2) throttled LP turbine, and (3) floating intermediate pressure (IP)/LP crossover pressure. Scheme 1 has the highest efficiency, but neither the extraction rate nor the pressure can be changed with the lowest flexibility. Scheme 2 has the simplest design but lowest efficiency. In this method, throttling loss occurs, the extraction rate can be changed, and the extraction pressure cannot be altered. Scheme 3 has no throttling loss, IP/LP crossover pressure is higher than that in schemes 1 and 2, and the efficiency is greater than that of the other two schemes. SeYoung et al. [23] proposed that adding a back-pressure turbine can also reduce the IP/LP crossover pressure. CO2 capture system produces a large amount of waste heat, the recovery of which is also a hot research focus. Xu et al. [24] used the heat from the CO2 multistage compression intercooler and CO2 condenser to warm the condensed water. With this kind of waste heat recovery, approximately 180 MW of heat was recovered from the CO2 capture system, and the exergy loss was lowered by approximately 67%. Pfaff et al. [25] simulated the integration of an advanced ultra-


Page 4 of 46

Page 5 of 46 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

Energy & Fuels

supercritical power plant with post-combustion CO2 capture system, the preheating part of feed water and/or preheating oxidizing air with waste heat from the products of CCU (CO2 capture and utilization) and desorption tower, and the net efficiency increased by 1.02% relative to the basic situation. In the current research, only the effect of different transformations and innovation processes on the same coal-fired power plant is analyzed, whereas the influence of the integration of different capacity coal-fired power plants with the same CO2 capture system on the performance of each coalfired power plant is hardly compared. We compare the different integration and operation modes of a 660 MW coal-fired power plant integarted with the same CO2 capture system and proposed a general correlation of energy consumption caused by the CO2 capture system [26-27]. When an addition steam turbine is added for the 660 MW coal-fired power plant, the extraction position is moved to the IP/LP crossover pipe, and the condensate returns to the deaerator. The system has the lowest energy penalty. In this condition, the lowest system energy penalty and highest system thermal efficiency are achieved by not changing the output power of the integrated system and CO2 capture rate. However, for coal-fired power plants, the structure is complex, the capacity parameters are different, and the cooling mode may vary, whether the FGD affects the integrated system. Therefore, comprehensively analyzing various factors are necessary to obtain the unified influencing law of the integration of coalfired power plants with CO2 capture. The novelty of this paper lies on the comparison among 330, 660, and 1000 MW power plants with the same NH3-based CO2 capture system and the analysis of the different effects of CO2 capture process on power plants with different capacities from various aspects. The performance of the integrated systems was comprehensively evaluated based on grey correlation analysis by combining the six different indicators, namely, energy penalty, thermal efficiency, effect on output, energy consumption rate, coal consumption rate, and CO2 emission per kWh. In addition, the energy consumption formula was further improved for application. Finally, a new evaluation index for the integrated system by combining grey correlation analysis and improving the energy consumption formula was proposed. The evaluation system is no longer limited to a single factor but jointly analyses the multiple results of the integrated system.


Energy & Fuels 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 6 of 46

2. System description The system consists of a coal-fired power plant subsystem and a carbon capture subsystem. The parameters and structures of the two subsystems have different effects on the integration and operation processes. Therefore, clarifying the basic operating parameters and structure is necessary.

2.1 Coal-fired power plant Figure 1 shows the diagram of a 330 MW subcritical power plant. The coal-fired power generation subsystem includes a boiler, turbine, generator, condenser, deaerator, and feedwater heaters. The boiler consists of a superheater and a reheater. The turbine is of N330-16.67/538/538 and consists of high-pressure (HP), IP, and LP cylinders. The cylinders are divided from the extraction points to facilitate the analysis. Feedwater heaters include three HP reheaters (HTR4–6), three LP reheaters (HTR–3), and a deaerator (DTR).

1002620 16670 3398.9

786639 808 3138.4

HP

Boiler

923288 5633 3136.5

B

34040 1559 3326.7

76208 3328.0 3016.6 (1) T-271.2 H-1169.9

IP

(2)

T-oC H-kJ/kg

LP

W-kg/h P-kPa H-kJ/kg

LP Generator

24023 808 3138.4

12.4kPa Condenser

Deaerator

(3)

(4) 25050 486.0 3029.6

72383 5460.0 3136.5

(5) (6) 41313 293.0 2927.1

52116 106.0 2729.6

Pump

794085 798 210.8 A

HTR7

HTR6

HTR5

HTR3

T-269.5 T-239.5 T-200.1 H-1182.6 H-1035.3 H-835.1

HTR2

HTR1

T-150.8 T-132.7 T-101.2 H-635.6 H-558.0 H-424.3

Figure 1 Diagram of a 330 MW subcritical power plant Figure 2 shows the diagram of a 660 MW supercritical power plant. The coal-fired power generation subsystem includes a boiler, turbine, generator, condenser, deaerator, and feedwater


Page 7 of 46 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

Energy & Fuels

heaters. The boiler consists of a superheater and a reheater. The turbine is of N660-24.2/566/566 type and consists of HP, IP, and LP cylinders. The cylinders are divided from the extraction points to facilitate the analysis. Feedwater heaters include three HP reheaters (HTR5-7), four LP reheaters (HTR1-4), and a DTR.

1836485 24200 3398.8

1322150 1060 3191.9

HP

Boiler

1547547 4359 2983.1

B

67408 2016 3379.5

162099 4228 2983.1 (1) T-274.7 H-1204.4

HTR7

IP

(2)

LP Generator

178739 1060 3191.9 98367 405.7 2973.4

4.9kPa Condenser

Deaerator

(3)

95328 5768.6 3052.3

HTR6

LP

94772 (4) 1060 3191.9

Feed water turbine

HTR5

T-273.0 T-253.7 T-211.3 H-1200.6 H-1103.6 H-903.4

94772 6.3 2440.0


T-oC H-kJ/kg

(5)

(6) (7) (8) Pump 53197 52813 46311 112.1 47.6 17.2 1419134 2718.7 2585.7 2452.9 1052 137.58 A

HTR4

HTR3

HTR2

T-144.1 T-102.8 T-80.1 H-606.9 H-431.0 H-335.3

HTR1

T-56.8 H-237.8

Figure 2 Diagram of a 660 MW supercritical power plant Figure 3 shows the diagram of a 1000 MW ultra-supercritical power plant. The coal-fired power generation subsystem includes a boiler, turbine, generator, condenser, deaerator, and feedwater heaters. The boiler consists of a superheater and a reheater. The turbine is of N1000-25/600/600 type and consists of HP, IP, and LP cylinders. The cylinders are divided from the extraction points to facilitate the analysis. Feedwater heaters include three high-pressure reheaters (HTR5–7), four LP reheaters (HTR1–4), and a DTR.


Energy & Fuels 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

2733434 25000 3493.7

Page 8 of 46

1322150 1060 3191.9

HP

Boiler

IP

2473916 8190 3198.8

B

HTR7

Generator

6kPa Condenser

Deaerator

(2)

HTR6

LP

78907 581 3095.2 (3)

233731 7944 3198.8

T-294.8 H-1302.6

LP

107698 206064 2280 1110 3463.7 3247.8

224684 4494 3064.9 (1)


T-oC H-kJ/kg

128813(4) 1110 3247.8

(5)

Feed water turbine

HTR5

T-294.5 T-257.4 T-216.5 H-1314.4 H-1121.7 H-927.3

(6) (7) (8) Pump 83496 77483 153230 316 148 64 2077001 2953.0 2798.9 2656.4 1100 148.9 A

HTR4

128813 6.0 2457.1

HTR3

HTR2

T-157.6 T-135.3 T-110.9 H-665.0 H-569.2 H-465.4

HTR1

T-87.7 H-367.2

Figure 3 Diagram of a 1000 MW ultra-supercritical power plant The main parameters of 330, 660, 1000 MW power plant are shown in Table 1. Table 1 main parameters of three power plants Coal fired power Parameter

660MW 330MW

1000MW

plant Capacity

MW

330

660

1000

MPa/℃/℃

16.67/538/538

24.2/566/566

25/600/600

t/h

1002.62

1836.49

2733.43

kPa

12.4

4.9

6.0

℃

271.2

274.7

294.75

Parameters of main stream Flow rate of feedwater Pressure of condenser Temperature of


Page 9 of 46

feedwater Heat rate

kJ/kWh

8049

7540

7453.4

Coal consumption

g/kWh

274.7

257.3

251.0

2.2 CO2 capture process The NH3-based CO2 capture process is designed at 85% CO2 removal rate from a coal-fired power plant. For different capacity coal-fired power plant, the structure of the CO2 capture process is the same, but the amount of flue gas captured is different. Figure 4 shows the entire NH3-based CO2 capture process, which integrates the NH3 recycling coal-fired power plant, CO2 capture coal-fired power plant, and CO2 compression section. NH3 recycling

CO2 compressor

CO2 capture Clean gas

Chiller

Wash

Blower 2

H2O makeup

Blower 1

Pump 1

Stage-2

Heater

Pretreatment

Water Separation (Pump 6,Pump7)

CO2 Rich

Condenser

CO2 absorber

CO2 Stripper

Stage-1

flue gas

CO2 Lean

Steam

CO2 Compressor

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

Energy & Fuels

NH3 Lean Pump 2

Pump 3

Pump 5

Reboiler

Figure 4 Schematic of aqueous ammonia-based post-combustion capture plant The NH3-recycling coal-fired power plant combines the functions of flue gas cooling and NH3 recovery and includes a wash column and a pretreatment column. In the former, vaporized NH 3 is recovered by wash water, whereas in the latter, the heat contained in the high-temperature flue gas is used to regenerate NH3 in the wash water and recycle it to the CO2 absorber. The CO2 capture coalfired power plant applies a two-stage absorption with intermediate cooling to significantly reduce the


Energy & Fuels 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 10 of 46

vaporized NH3 levels. The compression process was modeled in six stages with fixed discharge conditions at 110 bar and 40 °C. Three intercoolers are used at stages 1, 3, and 5 in the CO2 compressor to remove gaseous NH3 and moisture from the CO2 product [15]. Table 2 presents the main parameters of the flue gas, absorber, and stripper in the CO2 capture system. The flue gas from the power plant is typically composed of 10.7% CO2, 6.0% H2O, 7.8% O2, and 75.5% N2 with 200 ppmv SO2 (volume basis). Given the massive flue gas flowrate, a single post combustion capture (PCC) train results in a 20 m inner absorber column diameter by using Mellapak 250Y packing material. Modern construction practices, such as the use of ceramic-lined concrete towers, may allow such sizeable columns to be built in the future; however, the recommendation of Chapel was applied in this study, setting the maximum absorber column diameter at 12.8 m. The CO2 capture rate was set at 85%. Thus, four parallel-process trains of CO2 capture with 12 m diameter absorbers were proposed to eliminate construction uncertainties, with each train designed to tackle one-third of the total flue gas of 139.5 t/h CO2 (approximately 1 million tons annually). Table 2 Flue gas, absorber, and stripper parameters Coal Coal fired

Mole

fired

Percent

power

Composition

Mole Composition

power percent plant

plant H2O

6.0

%

O2

7.8

%

CO2

10.7

%

SO2

200

ppmv

N2

75.5

%

Temperature

120

°C

Coal Coal fired fired Absorber

Value

Stripper

Value

power

power plant plant


Page 11 of 46 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

Energy & Fuels

Inlet flue gas temperature

120

℃

25

℃

Inlet lean solvent

10

Bar

10

Bar

Reboiler heat duty

3.27

MJ/kgCO2

CO2 compressor

110

Bar

Condenser

temperature Lean solvent loading

Reboiler pressure

pressure 0.225

/

2.3 Energy analysis of coal-fired power plants with post-combustion capture Considering the effect of the collection process parameters on the whole coal-fired power station is necessary to evaluate the performance of coal-fired power plant after integration with CO2 capture system. The following factors must be considered. ·The steam energy required for the generation of the solvent. ·The output power loss of turbine caused by the steam energy and temperature required for solvent generation. ·The energy required for the CO2 compression process associated with the pressure in the desorber. ·The low-quality heat that can be recovered from CO2 capture system that can be used to preheat the water. ·Auxiliary equipment energy consumption, such as pumps and flue gas, required for solvent circulation. Among them, the most influential operation parameters are the energy and steam temperature required for solvent regeneration and the operating pressure of the desorber. The choice of these parameters depends on the solvent selected for CO2 capture. Therefore, when the CO2 capture system is integrated with the power plant, the energy loss can be divided into three parts: (1) the energy loss


Energy & Fuels 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

resulting from the steam extraction from the reboiler, (2) the energy loss caused by CO2 compression, and (3) the energy loss caused by auxiliary equipment such as pumps. P𝑙𝑜𝑠𝑠 = P𝑠𝑡𝑒𝑎𝑚 + P𝑐𝑜𝑚𝑝 + P𝑎𝑢𝑥 (1) where 𝑃𝑙𝑜𝑠𝑠 is the overall energy consumption caused by the CO2 capture process to the power plant when one ton of CO2 is captured (kWh/t CO2), 𝑃𝑠𝑡𝑒𝑎𝑚 is the energy consumption caused by steam extraction in the power plant (kWh/t CO2), 𝑃𝑐𝑜𝑚𝑝 is the energy consumption caused by compressors (kWh/t CO2), and 𝑃𝑎𝑢𝑥 is the energy consumption caused by other auxiliary equipment (kWh/t CO2). The extraction of steam by reboiler provides thermal energy, whereas CO2 compression and auxiliary equipment consume electricity. The different forms of energy act in different positions in coal-fired power plants, and the effects differ. The effects of the extracted steam required by the reboiler on the original coal-fired power plant are mainly in two places. One is that the extraction of steam from the turbine decreases the output power of the turbine, and the other is the heat recovery of condensate from the extracted steam exchanging heat in the reboiler, affecting feedwater preheaters. Therefore, the energy, temperature, and pressure of the solvent regeneration greatly affect energy reduction caused by extraction. For power plants with different capacities, the steam parameters differ. On the basis of temperature and pressure limit, the extraction position and backwater temperature are determined. CO2 must be compressed to the appropriate pressure for transport and storage, making the compression process of CO2 important. The energy loss of CO2 compression is greatly involved with the pressure of stripper in the capture system and the pressure of transportation. Stripper pressure can also influence the energy consumption for the auxiliary equipment, such as the energy consumption in the pumps. The higher the stripper pressure, the greater the energy required for the pumps.


Page 12 of 46

Page 13 of 46 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

Energy & Fuels

2.4 Grey comprehensive evaluation Grey comprehensive evaluation method is a comprehensive evaluation method guided by grey correlation analysis theory. The basic idea is to determine an ideal optimal sample from the samples, which is used as the reference sequence to calculate the correlation degree between each sample sequence and the reference sequence and to produce a comprehensive comparison of the evaluated object. This method has no strict sample size requirement and does not require any distribution. Given that the results of the integration of coal-fired power plant with CO2 capture system can be evaluated from multiple aspects, grey relational comprehensive evaluation is introduced to comprehensively evaluate multiple evaluation indicators.

3. Case study 3.1 Model validation The 330, 660, and 1000 MW coal-fired power plants were modeled using the Ebsilon software. The output of the models was 330.0006, 660.67, and 1000.652 MW with error of 0.000182%, 0.101%, and 0065% compared with the designed capacity of 330, 660, and 1000 MW, respectively. The other detailed results of the models and the designed working conditions (see Tables 3–5) show good agreement between the model and the design conditions. Table 3 Simulation results compared with the designed working conditions for the 330MW subcritical coal-fired power plant Simulation Designed

Simulation Error

Designed

results

Error results

0.00

Condenser

0182

pressure

%

(kPa)

0

Feedwater

Output 330

330.0006

12.4

12.4

0

271.2

267.50

1.364%

(MW) Main steam

16.67

16.67


Energy & Fuels 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

pressure

Page 14 of 46

temperature

(MPa) Main steam temperature

Steam 538

538

0

(℃)

flowrate

1002.62

1002.62

0

8049

8113.93

0.8067%

(kg/h) Heat

Reheat steam 538

538

0

consumption

temperature (kJ/kWh)

Table 4 Simulation results compared with the designed working conditions for the 660MW supercritical coal-fired power plant Simulation Designed

Simulation Error

Designed

results

Error results

Condenser Output

0.10 660

660.67

pressure

4.9

4.9

0

274.70

274.73

0.001%

1836485

1836485

0

7540.000

7539.11

0.001%

1%

(MW)

(kPa) Main steam pressure

Feedwater 24.2

24.2

0 temperature

(MPa) Steam

Main steam temperature

566

566

0

(℃)

(kg/h)

Reheat steam

Heat 566

temperature

flowrate

566

0 consumption


Page 15 of 46 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

Energy & Fuels

(kJ/kWh)

Table 5 Simulation results compared with the designed working conditions for the 1000MW supercritical coal-fired power plant Simulation Designed

Simulation Error

Designed

results

Error results

Condenser Output

0.06 1000

1000.66

(MW)

pressure

6.0

6.0

0

294.75

294.75

0

2733.43

2733.43

0

7453.4

7348.6

1.41%

5% (kPa)

Main steam Feedwater pressure

25

25

0 temperature

(MPa) Main steam

Steam

temperature

600

600

0

(℃)

flowrate (kg/h) Heat

Reheat steam 600

600

0

consumption

temperature (kJ/kWh)

The results of NH3 loss rate are shown in Table 6. Additional details on test of CO2 capture system are shown in Ref [28].

Table 6 The results of NH3 loss rate

teat ID 30

test NH3 loss rate simu. NH3 loss rate kg/h kg/h 7.1

7


relative error 1.4%

Energy & Fuels 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 16 of 46

31

6.1

6.81

11.6%

31R

10.08

9.23

8.4%

31B

3.93

3.79

3.6%

32

5.68

6.21

9.3%

32A

4.46

3.9

12.6%

32B

5.58

5

10.4%

33

5.39

4.46

17.3%

34

3.88

3.89

0.3%

34R1

5.31

4.45

16.2%

34R2

4.08

4.14

1.5%

36

2.48

2.1

15.3%

35B

3.74

4.78

27.8%

35

3.77

4.11

9.0%

39

4.99

4.41

11.6%

38

1.91

2.03

6.3%

3.2 Integration of power plant with CO2 capture process For power plants with different capacities, given the different steam parameters, the position of steam extraction and condensate is different when integrated with CO2 capture system. According to Ref. [24], the best heat transfer efficiency occurs at 5 K temperature difference. Therefore, the saturated temperature of the extracted steam is selected to be 5 K higher than the temperature of the reboiler. The return location of condensate depends on the temperature of condensate. On the basis of the temperature of LP heaters, the condensate returned to the LP heater with the nearest temperature. Integration method is good for obtaining steam that conforms to the parameters of CO2 desorption through external steam turbine or re-drilling in the LP cylinder. In this study, for the 330, 660, and 1000 MW coal-fired power plant, the extraction point is between LP2 and LP3, LP1 and LP2, and LP2 and LP3, and the condensate returns to the HTR2, deaerator, and HTR2, respectively. The three integration methods are shown in Figures 5 and 6.


Page 17 of 46 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

Energy & Fuels

LP

IP

HP

Generator

Boiler

Condenser

330MW

Reboiler

Figure 5 The integration method of 330MW coal fired power palnt

660MW

HP

IP

LP

Turbine Generator

Boiler

Condenser 1000MW

Reboiler

Reboiler Case 3

Case 2

Figure 6 The integration method of 660MW coal fired power plant and 1000MW coal fired power plant The classification of LP turbine is based on the extracted location of steam, which is sent to the LP heaters. For the 330 MW coal-fired power plant, LP turbine can be divided into five grades. LP1 is the part from input of LP turbine to the extracted plot of HTR3; LP2 is the part from the extracted plot of


Energy & Fuels 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

HTR3 to the extracted plot, wherein the steam is sent to the reboiler; LP3 is the part from the extracted plot, wherein the steam is sent to the reboiler to the extracted plot of HTR2; LP4 is the part from the extracted plot of HTR2 to the extracted plot of HTR1; and LP5 is the part from the extracted plot of HTR1 to the output of LP turbine. For the 660 MW coal-fired power plant, LP turbine can be divided into six grades. LP1 is the part from input of LP turbine to the extracted plot, wherein the steam is sent to the reboiler; LP2 is the part from the extracted plot, wherein the steam is sent to the reboiler to the extracted plot of HTR4; LP3 is the part from the extracted plot of HTR4 to the extracted plot of HTR3; LP4 is the part from the extracted plot of HTR3 to the extracted plot of HTR2; LP5 is the part from the extracted plot of HTR2 to the extracted plot of HTR1; and LP6 is the part from the extracted plot of HTR1 to the output of LP turbine. For the 1000 MW coal-fired power plant, LP turbine can be divided into six grades. LP1 is the part from input of LP turbine to the extracted plot of HTR4; LP2 is the part from the extracted plot of HTR4 to the extracted plot, wherein the steam is sent to the reboiler; LP3 is the part from the extracted plot, wherein the steam is sent to the reboiler to the extracted plot of HTR3; LP4 is the part from the extracted plot of HTR3 to the extracted plot of HTR2; LP5 is the part from the extracted plot of HTR2 to the extracted plot of HTR1; and LP6 is the part from the extracted plot of HTR1 to the output of LP turbine.

3.3 Results The influence of the extracted steam required for CO2 capture process on the system performance is only considered. Assuming all of the other conditions are consistent, the changes in the performance of the plant is shown in Table 7 when integrated with the same CO2 capture process in three different capacity coal-fired power plants. The table shows that the energy penalty of the 660, 1000, and 330 MW coal-fired power plant is 7.84%, 8.01%, and as high as 9.87%, respectively. The main reason is that the steam parameters of different capacity systems differ, so the position of


Page 18 of 46

Page 19 of 46 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

Energy & Fuels

extraction and condensate are different. However, the thermal efficiency of the integrated 1000MW coal fired power plant is the highest, which is 40.98%, and the thermal efficiency of the 330MW coal fired power plant is the lowest 34.49%. The main reason for this is because in the 1000MW coal-fired power plant, the parameters and thermal efficiency are high, the coal consumption rate is low, and the plant is less affected by the same unit energy consumption. Thermal efficiency is defined as

ƞ=

𝑔𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑝𝑜𝑤𝑒𝑟 𝑜𝑓 𝑔𝑒𝑛𝑒𝑟𝑎𝑡𝑜𝑟 𝑖𝑛𝑝𝑢𝑡 ℎ𝑒𝑎𝑡 𝑜𝑓 𝑏𝑜𝑖𝑙𝑒𝑟

energy penalty is defined as η𝑝𝑒𝑛𝑎𝑙𝑡𝑦 = η𝑝𝑜𝑤𝑒𝑟 𝑝𝑙𝑎𝑛𝑡 − η𝑖𝑛𝑡𝑒𝑔𝑟𝑎𝑡𝑒𝑑 When the thermal efficiency of systems is calculated, the boiler efficiency and auxiliary power ratio are not included. At 90% boiler efficiency, the thermal efficiency of 330, 660, and 1000 MW integrated systems is 31.04%, 35.87%, and 36.88%, whereas energy penalty is 8.89%, 7.05%, and 7.21%, respectively. Table 7 The change of system performance after the integration of different capacity power plant with CO2 capture process. original

integration

original

integration

original

Integration

330MW

330MW

660MW

660MW

1000MW

1000MW

300.99

300.99

560

560

826.58

826.58

330000

275864.74

660000

553440.88

1000000

840900.49

743791

743791

1383852

1383568

2042610

2042610

CO2 flow rate (t/h) Output power (kW) Heat consumption of boiler


Energy & Fuels 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 20 of 46

(kJ/s) Heat consumption 8114.08

10436.65

7548.28

9032.42

7353.40

8785.35

44.37

34.49

47.69

40.00

48.99

40.98

-

9.88

-

7.69

-

8.01

-

3.27

-

3.27

-

3.27

-

287.05

-

228.07

-

231.99

276.93

356.19

257.62

308.27

250.96

299.84

-

278.78

-

267.79

-

284.27

-

4.83

-

4.82

-

4.83

rate (kJ/kWh) Thermal efficiency (%) Energy penalty (%) Heat duty per kilogram CO2 (MJ/kgCO2) Electricity consumption per ton CO2 (kWh/t CO2) Coal consumption rate (g/kWh) Temperature of extracted steam (℃) Pressure of extracted steam (bar)


Page 21 of 46 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

Energy & Fuels

Enthalpy of extracted -

3021.25

-

2998.57

-

3032.58

-

97.36

-

182.88

-

266.12

steam (kJ/kg) Flow rate of extracted steam (kg/s) the second

the second

low-

low-

Return -

pressure

-

Deaerator

-

pressure

location feedwater

feedwater

heater

heater

The integration between power plant and CO2 capture process mainly occurs in the reboiler. A portion of the steam extracted from the steam cycle is sent to the reboiler for heat exchange, and the condensate returned to the steam cycle of the power plant. The greatest influence of the extraction on the system components is the LP turbine, LP feedwater preheater, and deaerator. The effect of which is shown in Figures 7 and 8. As shown in Figure 7, the power generation of the steam turbine at all levels has greatly changed. For the 330 MW coal-fired power plant, the steam extraction point of the turbine is between the second and third stages of the LP turbine, and the extraction volume is 48.4% of the main steam volume. The return position of the condensate is the second stage of LP feedwater heater, and the extraction volume required for the second stage LP feedwater heater decreases by 89.3%. Given that the condensate returns to the feedwater preheater, the feedwater flow that forms the condenser drops, and the required bleed off for the third and fourth stage pressure feedwater preheaters drops by 45.68% and 47.04%. For the 660 MW coal-fired power plant, the steam extraction point of the turbine is between the first and second stages of the LP turbine, and the extraction volume is 35.85% of the main steam volume. The condensate returns to the deaerator, and


Energy & Fuels

the extraction volume required for the deaerator is reduced by 45.70%. For the 1000 MW coal-fired power plant, the steam extraction point of the turbine is between the second and third stages of the LP turbine, and the extraction volume is 35.05% of the main steam volume. The return position of the condensate is the second stage of LP feedwater heater, and the extraction volume required for the second stage LP feedwater heater decreases by 47.03%. Original-330MW Integration-330MW Original-660MW Integration-660MW Original-1000MW Integration-1000MW

160000 140000 120000

kW

100000 80000 60000 40000 20000 0 1

2

3

4

5

6

Turbine

Fig 7 The impact of extracted steam on LP turbine

Original-330MW Integration-330MW Original-660MW Integration-660MW Original-1000MW Integration-1000MW

100000

80000

kW

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 22 of 46

60000

40000

20000

0 Heater1

Heater2

Heater3

Heater4

Deaerator

Fig 8 The impact of extracted steam on LP preheaters and deaerator During NH3-based CO2 capture system, auxiliary equipment, such as pump and fan, which consumes energy, are required. Table 8 lists the energy consumption of the NH3-based CO2 capture process. For power plants with different capacities, the CO2 capture volume is different, and the


Page 23 of 46 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

Energy & Fuels

consumption of auxiliary energy consumption and the proportion of each part of the energy consumption also differ. The results are shown in Figure 9. For the power plants with different capacities, the largest part of the system energy loss is caused by the extraction of reboiler, which is more than half of the total energy consumption, and the second is from compressors, which is between 10% and 15%. Compared with power plants with different capacities, 660 MW power plant energy consumption caused by extraction accounts for the minimum, accounting for 66.75%, followed by 1000 MW, and at finally, the 330MW. This result is because the return position of the condensate of the 660 MW power plant is the deaerator, which slightly influences the power plant. The position of the backwater of the 1000 and 330 MW power plants is the LP feedwater preheater, which greatly influences the power plants. For the 1000 MW power plant, the steam parameter is high, and the performance of the system is superior. Therefore, the performance of the integrated coal-fired power plant is still better than that of the 330 MW coal-fired power plant. Table 8 Energy consumption of CO2 capture Other energy (kJ/kg CO2) consumption NH3 recycling

CO2 capture

Chiller

52.0

Pump 1

0.5

Pump 2

0.7

Blower 1

39.6

Pump 3

11.0

Pump 4

49.6

Pump 5

8.2

Blower 2

32.6


Energy & Fuels 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

Water separation

Page 24 of 46

Pump 6

0.02

Pump 7

0.02

Compressor

164.0 Pumps for

Auxiliary

8.3 cooling water Others

42.5

Total energy 409.0 penalty

Steam Pumps and blowers Chillers Compressors Others


10.44% 3.61%

12.24% 4.23% 13.33%

11.37% 71.64%

3.46%

66.75%

2.95%

(a) 330MW

(b) 660MW


12.1% 4.18% 13.18%

67.13%

3.42%

(c)1000MW


Page 25 of 46 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

Energy & Fuels

Fig 9 The energy consumption of different capacity power plant In consideration of the energy consumption of auxiliary equipment, the performance of three different power plants with CO2 capture process is shown in the Table 9. Table 9 shows that in consideration of the energy consumption of auxiliary equipment, the energy penalty of 660, 1000, and 330 MW is the lowest at 11.75%, 11.89%, and reaches 13.78% with the same integration, respectively. However, from the thermal efficiency of the system, the thermal efficiency of the integrated 1000 and 330 MW power plant is the highest and lowest at 37.07% and 30.59%, respectively. The trend of the results is the similar to that of the unconsidered auxiliary equipment because the energy form consumed by the auxiliary equipment is electric energy, which is directly on the output power. The effects of the integration of power plant with CO2 capture are analyzed from different angles, and the results are different. The results are one-sided to evaluate the performance of CO2 capture system separately from energy penalty angle. Table 9 Performances of integration systems when considering auxiliary consumption Capacity of power plant

330MW

660MW

1000MW

Output power (kW)

227494.3

497359.5

757180.9

Thermal efficiency (%)

30.59

35.92

37.07

Energy penalty (%)

13.78

11.75

11.89

CO2 (kWh/t CO2)

400.67

341.68

345.61

Coal consumption rate (g/kWh)

401.70

341.79

331.45

Electricity consumption per kilogram

Therefore, we use grey comprehensive evaluation to evaluate the performance of the integrated system. The comprehensive evaluation indicator is proposed on the basis of grey relational analysis and includes six different indicators: energy penalty, thermal efficiency, effect on output, energy consumption rate, coal consumption rate, and CO2 emission per kWh. The steps of the grey relational analysis method are as follows:


Energy & Fuels 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 26 of 46

a. The construction of evaluation matrix, xij is the value of i object for the j attribute.

X =(x ij )mn

(2)

b. The standardization of evaluation indexes:

a ij =

xij − min  xij  j

max  xij  − min  xij  j

j

a ij =

(3)

max  xij  − xij j

max  xij  − min  xij  j

j

(4)

Thermal efficiency is standardized in accordance with Equation (3), and other indexes are standardized in accordance with Equation (4). c. Calculation of the correlation coefficient:

i (k ) =

 min +  max i (k ) +  max

(5)

There

 min = min min | x0 (k ) − xi (k ) |= 0 i

k

,

 max = max max | x0 (k ) − xi (k ) |= 1 i

k

,

i (k) =| x0 (k ) − xi (k ) | ,  =0.5 d. The comprehensive evaluation coefficient of grey correlation analysis: 𝐸𝑖 = ∑𝑚 𝑘=1 ℎ𝑘 𝜉𝑖 (𝑘) ∗ 100% where in,h𝑘 is weighting coefficient, each weighting coefficient is similar, is 1/6。 The results of the grey relational analysis method are shown in Table 10.


(6)

Page 27 of 46 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

Energy & Fuels

Table 10 The comprehensive evaluation coefficient is proposed based on grey relational analysis (without/with considering auxiliary consumption) (a) 330MW(without)

660MW(without)

1000MW(without)

Energy penalty (%)

9.88

7.84

8.01


34.49

39.86

40.98

Effect on output (%)

0.22

0.16

0.16

287.05

228.07

231.99

356.19

308.27

299.84

175.97

152.33

148.13

33.33

87.22

95.59

Energy consumption (kWh/kg CO2) Coal consumption rate (g/kWh) CO2 emission per kWh (g/kWh) Comprehensive evaluation coefficient (%)

(b) 330MW(with)

660MW(with)

1000MW(with)

Energy penalty (%)

13.78

11.75

11.89


30.59

35.95

37.07

Effect on output (%)

0.31

0.25

0.24

400.66

341.68

345.61

401.70

341.79

331.45

Energy consumption (kWh/kg CO2) Coal consumption rate (g/kWh)


Energy & Fuels 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

CO2 emission per kWh (g/kWh)

Page 28 of 46

198.46

168.89

163.75

33.33

86.51

96.00

Comprehensive evaluation coefficient (%)

Tables 10 (a) and (b) show that based on the analysis method, for the 330 MW power plant, the comprehensive evaluation coefficient is the same whether auxiliary consumption is considered or not. For the 660 MW power plant, the comprehensive evaluation coefficient without auxiliary consumption is slightly higher than that with auxiliary consumption. For the 1000 MW power plant, the comprehensive evaluation coefficient without auxiliary consumption is slightly lower than that with auxiliary consumption. This phenomenon is because the selection of evaluation indicators is the optimal selection among all of the indicators of the three power plants, and no optimal indicator in any case of 330 MW power plant exists. The weight coefficient is selected as the same value at 1/6. In future studies, indicators can be further optimized, such as increasing electricity prices, construction costs, and other indicators. Evaluation indicators can select the best indicators in the industry. Simultaneously, further optimal to the weight, such as from different angles to evaluate the weight. However, regardless of the auxiliary consumption, the integration of 1000 MW power plant with CO2 capture system shows the best performance, followed by the 660 MW power plant, and the 330 MW power plant is the worst.

4 Discussion Assuming the same auxiliary energy consumption, the integration characteristics of power plants with different capacities with CO2 capture process are analyzed on the basis of the integration method adopted in the previous application. The steam parameters of power plants with different capacities differ; thus, the influence on the system caused by extraction great differs. At 3.2 MJ/kgCO2 heat duty, the influence of temperature on different capacity power plant is shown in Figure 10. The energy


Page 29 of 46 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

Energy & Fuels

consumption per ton of CO2 of 330 and 1000 MW power plant is the lowest and highest, respectively. The three lines in the figure all have a change in slope, which is due to the different parameters of each stage steam turbine and each feedwater heaters of power plants with different capacities. According to the principle of utilization of temperature grade, the position of the extracted steam and the position of the condensed water after heat transfer by reboiler are different to use energy as efficiently as possible. For a 330 MW coal-fired power plant, at temperatures between 120 °C and 130 °C; 135 °C and 150 °C; and 155 °C and 160 °C, the extraction point is between LP3 and LP4; LP2 and LP3; and LP1 and LP2, and the condensate returns to the HTR1; HTR2; and HTR3, respectively. For a 660 MW coal-fired power plant, at temperatures between 120 °C and 130 °C and between 135 °C and 160 °C, the extraction points are both between LP1 and LP2, and the condensate returns to HTR3 and deaerator, respectively. For a 1000 MW coal-fired power plant, at temperatures between 120 °C and 140 °C and between 145 °C and 160 °C, the extraction points are both between LP2 and LP3, and the condensate returns to HTR2 and HTR3, respectively. However, given the difference in output power, the effect after integrated system differs. At temperatures between 120 °C and 130 °C and between 135 °C and 160 °C, the influence of 660 MW coal-fired power plant integrated with CO2 capture system is the greatest and minimal, respectively. For the three-capacity power plants, the trend of 330 and 1000 MW is basically similar to the whole range of variation, whereas the trend of 660 MW differs from the others. This phenomenon is because at any temperature, the condensate from the 330 and 660 MW coal-fired power plants integrated with CO2 capture system returns to the LP feedwater heaters, whereas that from the 660 MW coal-fired power plant returns to deaerator at temperatures higher than 135 °C. In general, the effects of coal-fired power plants integrated with CO2 capture system on the output are basically similar. Compared with the average, the maximum deviation within the entire range does not exceed 2.5%.


Energy & Fuels

330MW 660MW 1000MW

Energy consumption (kWh/t CO2)

240 230 220 210 200 190 180 170 160 120

130

140

150

160

Temperature(oC)

(a) 330MW 660MW 1000MW

0.18

0.16

Effect

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 46

0.14

0.12 115

120

125

130

135

140

145

150

155

Temperature (℃)

(b)


160

165

Page 31 of 46

energy penalty（%）

8.5

8.0

7.5

7.0

6.5

330MW 600MW 1000MW

6.0

5.5 120

125

130

135

140

145

150

155

160

165

Temperature(℃)

(c)

330MW 660MW 1000MW

43

42

Thermal efficiency（%）

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

Energy & Fuels

41

40

39

38

37 120

125

130

135

140

145

150

155

Temperature(℃)

(d)


160

165

Energy & Fuels

330MW 660MW 1000MW

Coal consumption(g/kWh)

340

330

320

310

300

290 120

125

130

135

140

145

150

155

160

165

Temperature(℃)

(e) 330MW 660MW 1000MW 165

160

Emission(g/kWh)

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 32 of 46

155

150

145

140 120

125

130

135

140

145

150

155

160

165

Temperature(℃)

(f) Fig 10 the influence of temperature on different capacity power plant At 150 °C extraction temperature, the influence of heat duty on power plants with different capacities is shown in Figure 11. With increasing heat duty, the regenerative heat consumption of the reboiler increases, and the energy consumption of the CO2 capture is mainly the regenerative heat consumption; thus, energy consumption increases. Energy consumption per ton CO2 of 330 and 1000 MW power plant is the lowest and highest, respectively. This finding is mainly due to the difference in the amount of heat exchange in the reboiler. Under the same heat duty, the heat exchange capacity


Page 33 of 46

of the reboiler of the integration of 1000 and 600 MW coal-fired power plant with CO2 capture system is the largest and smallest, respectively. Given the difference of output, the influence differs. In the whole heat duty range, the output power of 660 MW coal-fired power plant integrated with CO2 capture system shows the least influence. At heat duties between 2 MJ/kg CO2 and 3.6 MJ/kg CO2 and between 4 MJ/kg CO2 and 5 MJ/kg CO2, the influence of the output power of 330 and 1000 MW coalfired power plant integrated with CO2 capture system is the greatest. In general, the effects of coalfired power plants integrated with CO2 capture system on the output are basically similar. Compared with the average, the maximum deviation within the entire range does not exceed 2%. For each capacity power plant, no change in the slope in Figure 9 exists, which is due to the whole heat duty variation range, and the position of extraction and condensate remains unchanged under consistent temperature.

330MW 660MW 1000MW

350

Energy consumption (kWh/t CO2)

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

Energy & Fuels

300

250

200

150

100 2.0

2.5

3.0

3.5

4.0

4.5

Heat duty (MJ/kg CO2)

(a)


5.0

Energy & Fuels

330MW 660MW 1000MW 0.25

Effect

0.20

0.15

0.10

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

5.5

Heaty duty (MJ/kg CO2)

(b) 330MW 660MW 1000MW

14

12

Energy penalty(%)

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 34 of 46

10

8

6

4 2.0

2.5

3.0

3.5

4.0

4.5

Heat duty(MJ/kg CO2)

(c)


5.0

Page 35 of 46

330MW 660MW 1000MW

Thermal efficiency（%）

44

42

40

38

36

34

32 2.0

2.5

3.0

3.5

4.0

4.5

5.0


(d) 330MW 660MW 1000MW

380

Coal consumption(g/kWh)

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

Energy & Fuels

360

340

320

300

280 2.0

2.5

3.0

3.5

4.0

4.5


(e)


5.0

Energy & Fuels

330MW 660MW 1000MW

190

180

Emission(g/kWh)

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 46

170

160

150

140 2.0

2.5

3.0

3.5

4.0

4.5

5.0


(f) Fig 11 the influence of heat duty on different capacity power plants For these six factors, namely, energy penalty, thermal efficiency, effect on output, energy consumption, coal consumption rate, and CO2 emission per kWh, the optimal situation is the lowest and energy penalty, effect on the output, energy consumption, coal consumption rate, CO2 emission per kWh separately show the highest thermal efficiency. Figures 10 (a–f) and 11(a–f) shows that whether it's changing the temperature or heat duty, when these six factors are analyzed separately, the optimal case for each factor is not the same unit. For example, at 150 °C temperature, the 330 MW integrated unit has the lowest energy consumption and energy penalty, and the 660 MW integrated unit exhibits the lowest effect, whereas the 1000 MW integrated unit shows the lowest coal consumption and emission and highest thermal efficiency. At 3.5 MJ/kg CO2 heat duty, the 330 MW integrated unit has the lowest energy consumption and energy penalty, and the 660 MW integrated unit has the lowest effect, whereas the 1000 MW integrated unit has the lowest coal consumption and emission and highest thermal efficiency. Considering all of the factors is necessary for a comprehensive evaluation. Thus, the gray correlation analysis method mentioned above is used to evaluate the overall performance of the integrated system. The results are shown in Table 11. Table 11 The comprehensive evaluation coefficient is proposed based on grey relational analysis (a) when the temperature is from 120 to 160℃ for three different capacity power plants


Page 37 of 46 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

Energy & Fuels

Temperature 330

660

1000

120

0.67

0.49

0.73

125

0.67

0.50

0.73

130

0.67

0.50

0.73

135

0.60

0.63

0.67

140

0.57

0.66

0.67

145

0.57

0.67

0.67

150

0.55

0.67

0.67

155

0.56

0.68

0.67

160

0.56

0.68

0.67

（℃）

(a) when the heat duty is from 2 MJ/kg CO2 to 160 MJ/kg CO2 for three different capacity power plants Heat duty (MJ/kg

330

660

1000

2

0.56

0.66

0.72

2.2

0.56

0.66

0.71

24

0.56

0.67

0.70

2.6

0.56

0.67

0.69

2.8

0.56

0.67

0.68

3.2

0.55

0.67

0.67

3.6

0.56

0.68

0.67

4

0.57

0.68

0.67

4.5

0.56

0.69

0.65

5

0.56

0.70

0.65

CO2)


Energy & Fuels 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

Based on the results from Tables 10 (a) and (b), for the same condition (the same temperature or the same heat duty), the best overall performance is different. Using the results for horizontal comparison, which is the overall performance of different capacities integrated with the same CO2 capture system under the same conditions, is feasible. However, if the overall performance of the same unit under different circumstances must be evaluated, the optimal index in the calculation must be changed, but the method is applicable. The index selection in this paper is the optimal value of each parameter obtained when different capacity coal-fired power plants are integrated with the same CO2 capture system under the same condition. At present, the cooling methods of coal-fired power plants are mainly air and water cooling. The air-cooling power plant can reduce approximately 80% of the total water consumption and can avoid the evaporation, drift, and blowdown losses caused by the direct contact of circulating cooling water with air in the wet cooling tower. However, given the condenser design pressure of the air-cooling power plant is higher than that of the wet-cooling power plant, the annual power supply is less than that of the wet-cooling power plant. On the basis of ensuring power supply, the coal consumption of the air-cooling power plant is higher than that of the wet-cooling power plant. In this paper, the 330MW coal-fired power plant is air-cooling power plant, and 660 and 1000 MW are water-cooling power plants. For the air-cooling power plant, given that its coal consumption is higher than that of water-cooling power plant, its CO2 emission is higher than that of the water-cooling power plant under the same flue gas composition. When the air-cooling power plant and water-cooling air plant with the same capacity are integrated with the same CO2 capture system, the air-cooling power plant emits CO2 into the atmosphere under constant CO2 capture rate. When air-cooling power plant is integrated with CO2 capture system, CO2 capture rate must be appropriately increased to improve environmental protection. Even though the coal consumption of the water-cooling power plant is lower than that of the air-cooling power plant, the water consumption of the water-cooling power plant is large. The CO2 capture system must also consume a large amount of water. In terms of saving water resources, the performance of the water-cooling power plant is worse than that of the aircooling power plant.


Page 38 of 46

Page 39 of 46 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

Energy & Fuels

In this paper, the flue gas parameter is form Munmorah Power Station. The flue gas temperature is 120 °C because Munmorah Power Station is operated without FGD. However, the flue gas from the coal-fired power plant in most areas has been treated by desulfurization. At present, FGD is mainly divided into three categories: wet, semi-dry, and dry desulphurization. Wet desulphurization technology is mature, highly efficiency, and simple operation. At present, wet FGD is the most widely used. Wet FGD has high desulphurization efficiency (90%–98%), strong adaptability of coal, low operating cost, and easy recovery of by-products. The temperature of the flue gas after wet desulfurization is relatively low generally at approximately 40 °C–50 °C and can directly enter the absorption tower of the CO2 capture system. Given the limitation of absorbent reaction temperature, flue gas cannot pass directly into the CO2 capture system absorption tower without desulfurization treatment. Therefore, flue gas was passed through a pretreatment column first to reduce the flue gas temperature and to remove impurities. Given that NH3 has the performance of co-absorbing SO2 and CO2, coal-fired power plant does not pretend FGD is feasible in theory, only the absorption tower of CO2 capture system must be modified to save the investment cost of FGD. The heat contained in high-temperature flue gas can be simultaneously used to wash NH3. For the energy consumption caused by steam extraction, as shown in Figures 8 and 9, the energy consumption of different capacity coal-fired power plants differs. The energy required for the generation of the solvent determines the extraction flow. Based on the quantitative analysis of the influence of temperature and heat duty on power plants with different capacities, the influence of the extracted steam required by CO2 capture system on the system can be obtained. Based on the simulation results of Ebsilon, its formula fitting results are shown in Table 12. The energy consumption caused by extracted steam can be calculated by Eq. (7). P𝑠𝑡𝑒𝑎𝑚 = 𝑝00 + 𝑝10 𝑇 + 𝑝01 𝐻 + 𝑝20 𝑇 2 + 𝑝11 𝑇𝐻 + 𝑝02 𝐻 2 + 𝑝30 𝑇 3 + 𝑝21 𝑇 2 𝐻 + 𝑝12 𝑇𝐻 2 + 𝑝03 𝐻 3(7)

𝑇 is the temperature of the steam (°C), 𝐻 is the heat duty of the reboiler (MJ/kg CO2), p𝑖𝑗 is the coefficient of terms，𝑖 is the square number of T, and 𝑗 is the square number of H.


Energy & Fuels 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 40 of 46

Table 12 The coefficients of the fitting formula of different capacity power plants 330MW

660MW

1000MW

P00

-374.6

-1081

-82.1

P10

8.11

22.34

1.656

P01

-3.928

63.03

-13.92

P20

-0.058

-0.1534

-0.01167

P11

0.468

-0.3239

0.6484

P02

-1.843

-3.363

-1.205

P30

0.000139

0.00035

0.0000282

P21

-0.00012

0.002606

-0.0006

P12

0.01063

0.01225

0.007731

P03

0.02535

0.1361

0.003112

The compression of power plants with different capacities is only related to the pressure of the stripper and the transportation pressure required for CO2; thus, the energy consumption of the compression can be calculated using the same formula for the same CO2 compression process integrated with power plants with different capacities. The energy loss caused by CO2 compression can be calculated by Eq. (8), which has been verified in our previous work [23]. The energy consumption caused by other auxiliary equipment is assumed to be 68.06 kWh/t CO2 based on the simulation results for this CO2 capture system. For other CO2 capture systems, the value can be selected based on the absorbent and operating parameters. P𝑝𝑟𝑒𝑠 = −28.52 ln 𝑝 + 120.81

(8)

where 𝑝 is the pressure of Stripper (bar). The overall energy consumption caused by extracted steam in three power plants with different capacities can be calculated by the equations mentioned above.


Page 41 of 46 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

Energy & Fuels

At 150 °C temperature, heat duty is 3.2 MJ/kg CO2, the energy consumption of the 330, 660, and 1000 MW integrated systems is calculated as 332.349, 334.632, and 345.337 kWh/t CO2, and the results obtained through Ebsilon simulation are 328.468, 341.682, and 340.112 kWh/t CO2, and the errors between results are 1.18%, 1.67%, and 1.54%, respectively, which is within the tolerated value. Combined with the grey relational analysis method in 3.3, Equation 9 can be used to evaluate the performance of three capacity units under the following other operation parameters: 1 6

0.5

𝐸𝑖 = ∗ ( (𝐴𝑚𝑎𝑥−𝐴 ) 0.5

𝑖 −0.5 𝐴𝑚𝑎𝑥 −𝐴𝑚𝑖𝑛

+

0.5 (𝐵𝑖 −𝐵𝑚𝑖𝑛 ) −0.5 𝐵𝑚𝑎𝑥 −𝐵𝑚𝑖𝑛

+

0.5 (𝐶𝑚𝑎𝑥 −𝐶𝑖 ) −0.5 𝐶𝑚𝑎𝑥 −𝐶𝑚𝑖𝑛

+

0.5 (𝐷𝑚𝑎𝑥 −𝐷𝑖 ) −0.5 𝐷𝑚𝑎𝑥 −𝐷𝑚𝑖𝑛

)

+

0.5 (𝐸𝑚𝑎𝑥 −𝐸) −0.5 𝐸𝑚𝑎𝑥 −𝐸𝑚𝑖𝑛

+

(9)

(𝐹𝑚𝑎𝑥 −𝐹𝑖 ) −0.5 𝐹𝑚𝑎𝑥 −𝐹

Among them, A is energy penalty (%), B is thermal efficiency (%), C is effect on output (%), D is overall energy consumption (kWh/t CO2), E is coal consumption rate (g/kWh), and F is emission (g/kWh).

5 Conclusion This paper studies the integration of power plants with different capacities with the NH3-based CO2 capture process and discusses two different situations in which the system considers the influence of the auxiliary machines. Three typical units with 330, 660, and 1000 MW capacities were studied. The turbine of 330, 660, and 1000 MW coal-fired power plants is N330-16.67/538/538, N660-

24.2/566/566, and N1000-25/600/600 respectively. When the auxiliary consumption is not considered, the energy penalty of 660 MW coal-fired power plant is 7.84%, which is the lowest, followed by the 1000 MW at 8.01%, and 330 MW at 9.87%, which is the highest after integrating with the same CO2 capture system. From the perspective of the thermal efficiency of the system, the thermal efficiency of 1000 MW power plant is the highest at 40.98%, followed by that of 660 MW power plant at 40.01%,


Energy & Fuels 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

and the thermal efficiency of 330 MW power plant is the lowest at 34.49%. When considering the Energy consumption of the auxiliary machines, the energy penalty of the 660, 1000, and 330 MW power plant under the same integration mode is 11.75%, 11.89%, and 13.78%, respectively. However, from the thermal efficiency of the system, the thermal efficiency of the integration of 1000 MW power plant is the highest at 37.07%, followed by that of 660 MW power plant at 35.58%, and the thermal efficiency of 330 MW coal-fired power plants is the lowest at 30.59%. The trend of the results is similar to that of the unconsidered auxiliary machines. On the basis of energy penalty and thermal efficiency, the performance of power plants with different capacities is contradictory because the original steam parameters of 1000 MW coal-fired power plant are relatively high, and the single indicator is one-sided. Combined with the following six indicators: energy penalty, thermal efficiency, effect on output, energy consumption rate, coal consumption rate, and CO2 emission per kWh, on the basis of the grey relational analysis, after integrating with the same CO2 capture system, the performance of 1000 MW power plant is the best, 660 MW power plant is second, and 330 MW power plant has the worst performance. Assuming that the auxiliary energy consumption is the same, according to the temperature and heat duty to quantitative analysis of the influence of different capacity of the coal-fired power plant, and the fitting results based on Matlab, a fitting formula can be obtained. The compression of power plants with different capacities is only related to the pressure of stripper. The transportation pressure is required by CO2 to ensure that the energy consumption of compression can be calculated by the same formula for power plants with different capacities. The energy consumption coefficients caused by different extractions can be simulated to obtain the total energy consumption caused by CO2 capture system. Finally, a new performance evaluation system of the integration of coal-fired power plant with CO2 capture system can be obtained by combining the energy consumption formula and grey correlation analysis,.


Page 42 of 46

Page 43 of 46 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

Energy & Fuels

Acknowledgements The research work is supported by National Major Fundamental Research Program of China (No. 2015CB251505), China National Natural Science Foundation (No. 51776063), the Fundamental Research Funds for the Central Universities (2016XS29, 2016YQ04), China Scholarship Council.

References [1]. IEA. CO2 emissions from fuel combustion-overview. International Energy Agency.2018.edition. [2]. Esmaeil Koohestanian, Jafar Sadeghi, Davod Mohebbi-Kalhori, Farhad Shahraki, Abdolreza Samimi, A novel process for CO2 capture from the flue gases to produce urea and ammonia, Energy, Volume 144, 1 February 2018, Pages 279-285. [3]. Mohamed Kanniche, René Gros-Bonnivard, Philippe Jaud, Jose Valle-Marcos, Jean-Marc Amann, Chakib Bouallou, Pre-combustion, post-combustion and oxy-combustion in thermal power plant for CO2 capture, In Applied Thermal Engineering, Volume 30, Issue 1, 2010, Pages 53-62. [4]. Rochelle GT. Amine Scrubbing for CO2 Capture. Science 2009, 325: 1652-1654. [5]. Georgios Fytianos, Andreas Grimstvedt, Hanna Knuutila, Hallvard F. Svendsen, Effect of MEA's Degradation Products on Corrosion at CO2 Capture Plants, In Energy Procedia, Volume 63, 2014, Pages 1869-1875. [6]. Aaron D, Tsouris C. Separation of CO2 from flue gas: a review. Sep Sci Technol 2005;40(1– 3):321–48. [7]. Chen X, Huang G, An C, et al. Emerging N- nitrosamines and N- nitramines from Amine-based Post-combustion CO 2 Capture - A Review[J]. Chemical Engineering Journal, 2017, 335:921935. [8]. G. Puxty, R. Rowland, A. Allport, Q. Yang, M. Bown, R. Burns, M. Maeder, M. Attalla, Carbon dioxide postcombustion capture: a novel screening study of the carbon dioxide absorption performance of 76 amines, Environ. Sci. Technol. 43 (16) (2009) 6427–6433.


Energy & Fuels 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

[9]. Zhao B, Liu F, Cui Z, et al. Enhancing the energetic efficiency of MDEA/PZ-based CO 2, capture technology for a 650 MW power plant: Process improvement[J]. Applied Energy, 2017, 185:362-375. [10].

Zhang Y, Zhang J, Liu B C, et al. Experimental comparison of CO2 absorption performance

of flue gas in power plants with mixed alcohol amine /MEA method [C]/ China chemical society 2010 annual conference and petroleum supplement and alternative energy development and utilization technology BBS, 2010. [11].

Liu S , Gao H , He C , et al. Experimental evaluation of highly efficient primary and

secondary amines with lower energy by a novel method for post-combustion CO2 capture[J]. Applied Energy, 2019, 233-234:443-452. [12].

Ling H , Gao H , Liang Z . Comprehensive solubility of N2O and mass transfer studies on an

effective reactive N,N-dimethylethanolamine (DMEA) solvent for post-combustion CO2 capture[J]. Chemical Engineering Journal, 2019, 355:369-379. [13].

Lu R, Li K, Chen J, et al. CO 2 capture using piperazine-promoted, aqueous ammonia

solution: Rate-based modelling and process simulation[J]. International Journal of Greenhouse Gas Control, 2017, 65:65-75. [14].

Mengxiang Fang, Qunyang Xiang, Xuping Zhou, Qinhui Ma, Zhongyang Luo, Experimental

Study on CO2 Absorption into Aqueous Ammonia-based Blended Absorbents, In Energy Procedia, Volume 61, 2014, Pages 2284-2288. [15].Li K, Yu H, Yan S, et al. Technoeconomic Assessment of an Advanced Aqueous AmmoniaBased Postcombustion Capture Process Integrated with a 650-MW Coal-Fired Power Station.[J]. Environmental Science & Technology, 2016, 50(19):10746-10755. [16].

Minkai Zhang, Yincheng Guo, Optimization of Carbon Capture Process Using Aqueous

Ammonia with Rate-based Simulation Method, In Energy Procedia, Volume 114, 2017, Pages 1469-1479. [17].

Li K, Cousins A, Yu H, et al. Systematic study of aqueous monoethanolamine‐based CO2

capture process: model development and process improvement[J]. Energy Science & Engineering, 2016, 4(1):23-39.


Page 44 of 46

Page 45 of 46 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

Energy & Fuels

[18].

Marcin Stec, Adam Tatarczuk, Lucyna Więcław-Solny, Aleksander Krótki, Marek Ściążko,

Stanisław Tokarski, Pilot plant results for advanced CO2 capture process using amine scrubbing at the Jaworzno II Power Plant in Poland, Fuel, Volume 151, 2015, 50-56, [19].

H. Yu, L. Wardhaugh, P. Feron, Q. Yang, K. Li, M. Tade, L. Li, M. Maeder, Development of

an aqueous ammonia-based PCC technology for Australian conditions, Final report to Australian National Low Emissions Coal Research and Development (ANLEC R&D). 2016. [20].

Gazzani M , Sutter D , Mazzotti M . Improving the Efficiency of a Chilled Ammonia CO2

Capture Plant Through Solid Formation: A Thermodynamic Analysis[J]. Energy Procedia, 2014, 63:1084-1090. [21].

Yu J , Wang S . Development of a novel process for aqueous ammonia based CO2 capture[J].

International Journal of Greenhouse Gas Control, 2015, 39:129-138. [22].

Lucquiaud M, Chalmers H, Gibbins J. Capture-ready supercritical coal-fired power plants and

flexible post-combustion CO 2, capture[J]. Energy Procedia, 2009, 1(1):1411-1418. [23].

SeYoung, Yun, Seokwon, et al. Process integration and design for maximizing energy

efficiency of a coal-fired power plant integrated with amine-based CO2 capture process[J]. Applied Energy, 2018, 216. [24].

Xu G, Hu Y, Tang B, et al. Integration of the steam cycle and CO 2, capture process in a

decarbonization power plant[J]. Applied Thermal Engineering, 2014, 73(1):277-286. [25].

Pfaff I, Oexmann J, Kather A. Optimised integration of post-combustion CO2 capture process

in greenfield power plants. Energy 2010;35(10):4030–41. [26].

Zhai, R., et al. (2018). "Integration of the 660 MW supercritical steam cycle with the NH 3 based CO 2 capture process: System integration mechanism and general correlation of energy penalty." International Journal of Greenhouse Gas Control 72: 117-129.

[27].

R. Zhai, H. Yu, L. Feng, Y. Chen, K. Li, Y. Yang, Integration of a Coal-Fired Power Plant with an Ammonia-Based CO2 Capture Process in Three Operation Modes, Energy & Fuels, 32 (2018) 10760-10772.


Energy & Fuels 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

[28].

Li, K., et al., 2014. Process modeling of an advanced NH3 abatement and recycling

technology in the ammonia-based CO2 capture process. Environ. Sci. Technol. 48 (12), 7179– 7186


Page 46 of 46

Integration of power plants with different capacities with aqueous

Recommend Documents