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Field study on the corrosion and ash deposition of low-temperature heating surface in a large-scale coal-fired power plant
Fuel 208 (2017) 149–159
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Full Length Article
Field study on the corrosion and ash deposition of low-temperature heating surface in a large-scale coal-fired power plant Heng Chen, Peiyuan Pan, Yungang Wang, Qinxin Zhao ⇑ Key Laboratory of Thermo-Fluid Science and Engineering of MOE, School of Energy and Power Engineering, Xi’an Jiaotong University, Xi’an, Shaanxi 710049, China
h i g h l i g h t s Corrosion and ash deposition of low-temperature heating surface before the precipitator. Three materials were tested under different tube wall temperatures in real flue gas. Mechanisms of dewpoint corrosion and viscous deposition were discussed. Coupling model of acid condensation and fly ash behaviors was proposed. Effects of sulphuric acid, hydrochloric acid and fluoric acid were all investigated.
a r t i c l e
i n f o
Article history: Received 13 December 2016 Received in revised form 1 May 2017 Accepted 27 June 2017
Keywords: Flue gas cooling Low-temperature heating surface Dewpoint corrosion Viscous ash deposition Coal-fired power plant Acid condensation
a b s t r a c t The corrosion and ash deposition of low-temperature heating surface were investigated in a 660 MW coal-fired power plant. The temperature-controlled test probes constructed of three materials were tested under different wall temperatures (90 °C, 80 °C, 70 °C, 60 °C, 50 °C and 40 °C). The metal specimens and deposit samples were analyzed by X-ray fluorescence, X-ray diffraction and scanning electron microscope with energy dispersive spectroscopy. The results revealed that when the wall temperature fell to 70 °C, viscous deposits began to form on the probes due to the condensation of sulphuric acid, hydrochloric acid and hydrofluoric acid. Meanwhile, the sulphuric acid condensate and hydrochloric acid condensate stimulated the corrosion of the metal surface. The corrosion and deposits increased with the decrease of the wall temperature. The corrosion resistances of the three tested materials were 316 L > ND > 20#. The corrosion mechanism and ash deposition mechanism of low-temperature heating surface were discussed. The coupling model of acid condensation and fly ash behaviors was proposed, and the main factors affecting the corrosion and ash deposition were summarized. Suggestions were made to alleviate the corrosion and fouling of waste heat recovery devices in coal-fired power plants. Ó 2017 Elsevier Ltd. All rights reserved.
1. Introduction In China, the power industry has developed vigorously, and the power coal consumption has been accounted for >50% of the total coal production [1]. According to surveys, the exhaust gas temperature of utility boiler in China typically maintains in the level of 120–150 °C [2]. A 10 °C decrease in the flue gas temperature can cause a 0.6%–1.0% increase in the boiler efficiency [3]. Therefore, the foreground of waste heat recovery for coal-fired power plants is considerable. In recent years, waste heat recovery devices have been widely applied in coal-fired power plants in China, which can recover heat from flue gas [1,4,5] and help in synergistically reducing SO3/H2SO4 ⇑ Corresponding author. E-mail address: [email protected] (Q. Zhao). http://dx.doi.org/10.1016/j.fuel.2017.06.120 0016-2361/Ó 2017 Elsevier Ltd. All rights reserved.
and particulate emissions [6]. However, some of these already used heat recovery devices have suffered severe corrosion and fouling during their operations, which led to the leaking of heat exchange tubes, the increase of gas flow resistance, the decrease of heat transfer efficiency and even the shutdown of the power plants. The lowest heating surface temperature of a heat recovery device is usually low, approximately 60 °C–90 °C. When the heating surface temperature is below the dewpoints of the acids (sulphuric acid, hydrochloric acid, etc.) in the flue gas, the acids can condense onto the heating surface, resulting in dewpoint corrosion and viscous ash deposits [7], which are severe problems for the heat recovery devices of coal-fired power plants. Many studies have been done regarding the corrosion and ash deposition of low-temperature heating surface. Much of the literature focuses on predicting the sulphuric acid dewpoint in the flue gas [8–13]. A few researchers experimentally investigated the
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dewpoint corrosion with simulated flue gas [14,15] or immersion tests [16,17]. A volume of work has been carried out on the corrosion and deposits of low-temperature heating surface by field sampling [18–25]. However, field experimental research on dewpoint corrosion and viscous ash deposition is still insufficient. Vainio [26] and Wang [27] examined the low-temperature corrosion of biomass boilers in the field. Wang [28] and Liang [3,29] explored the coupling mechanism between dewpoint corrosion and ash deposition in coal-fired power plants, but they did the tests after the electrostatic precipitators, where the fly ash concentrations were very low. And the fly ash concentration of the flue gas has an important influence to the low-temperature corrosion and ash deposition. What’s more, most of the applied waste heat recovery devices are installed before precipitators for synergistically removing SO3/H2SO4 and particulates [30,31]. Hence, it is necessary to study the corrosion and ash deposition of the low-temperature heating surface before the precipitators in coal-fired power plants. Li [32] investigated the relation of ash deposition and sulphuric acid condensation under different temperatures before the precipitator on a coal-fired boiler unit, but the corrosion mechanism and the effects of other acids were not fully discussed. In this paper, the corrosion and ash deposition characteristics of low-temperature heating surface were experimentally studied in a large-scale coal-fired power plant. Six test probes were examined under different wall temperatures in the flue gas before the electrostatic precipitator, and the corresponding metal specimens and deposit samples were analyzed. The objective was to investigate the mechanisms of the dewpoint corrosion and viscous ash deposition under high fly ash concentration during the flue gas cooling process, which would be beneficial to reduce the corrosion and fouling of the waste heat recovery devices for coal-fired power plants.
Table 1 Typical property of the burned coal of the boiler analyzed according to Chinese National Standards. Parameter
Value
Chinses National Standard
Proximate analysis
14.60 5.76 12.92 31.85 55.23 27.97
GB/T 212-2008
71.03 3.97 10.68 0.94 0.46 0.022 0.013 48.44 21.28 1.02 6.64 10.00 1.30 1.10 1.54 4.71 3.97
GB/T 31391-2015
Moisture (wt%, ar) Moisture (wt%, ad) Ash (wt%, db) Volatile matter (wt%, db) Fixed carbon (wt%, db) Higher heating value (MJ/kg, db) Ultimate analysis C (wt%, db) H O N S Cl content of the coal (wt%, db) F content of the coal (wt%, db) Ash composition SiO2 (wt%, ash basis) Al2O3 TiO2 Fe2O3 CaO MgO Na2O K2O SO3 Others
Note: ar – as received basis; ad – air dry basis; db – dry basis.
29.3 MPa. The typical property of the coal burned by the boiler was analyzed on the basis of Chinese National Standards, as given in Table 1. As Fig. 1 shows, the temperature-control multi-element laminar test probe [33] was put into the vertical flue duct after the air preheater and in front of the flue gas cooler. The flue gas flowed across the probe from below, and the outer tube wall temperature was kept by the cooling water. A constant-temperature cycle machine was applied to maintain the inlet cooling water’s temperature constant. Comparing to the studies with simulated flue gas or immersion tests, this method with cooled specimens inserted into the boiler flue duct during normal service, is closer to the conditions
2. Experimental section The experiment was conducted in a 660 MW ultra-supercritical coal-burning power plant. The boiler of the plant is a single reheat, G-type arrangement, tangentially fired and pulverized coal boiler. The rated evaporating capacity of the boiler is 1968t/h. The main steam temperature and pressure of the boiler are 603 °C and
Outer Tube
Flue gas
Cooling Water
Wall of the flue duct
Inner Tube
20#
ND
316L
Test probe Desulfurizing tower
Boiler
Air heater
GB/T 3558-2014 GB/T 4633-2014 GB/T 1574-2007
Flue gas cooler Electrostatic Coolant precipitator
Fig. 1. Schematic diagram of the experimental location and the test probe.
Smoke stack
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H. Chen et al. / Fuel 208 (2017) 149–159 Table 2 Elemental compositions of the three tested materials (wt%). Material
C
Si
Mn
P
S
Cu
Ni
Cr
Mo
Sb
Fe
20# ND 316L
0.19 0.08 0.03
0.21 0.22 0.41
0.53 0.48 0.95
0.013 0.011 0.038
0.003 0.005 0.030
0.03 0.29 –
0.01 0.02 10.96
0.03 0.79 18.12
– – 2.81
– 0.06 –
Bal. Bal. Bal.
Table 3 Flue gas parameters at the testing location during the experiment. Parameter
Unit
Maximum
Minimum
Average
Velocity Temperature SO2 NOx O2 Fly ash concentration
m/s °C mg/m3 mg/m3 % g/m3
11.32 126.37 946.89 26.57 7.91 10.23
8.48 105.76 656.21 9.63 5.39 13.76
9.87 114.25 798.43 18.94 6.84 12.47
180°
Metal specimen Metal specimen
test probe consisted of three materials: mild steel 20#, weathering steel ND and stainless steel 316 L, and Table 2 shows their compositions. In this study, the corrosion and ash deposition of lowtemperature heating surface were investigated when the outer tube wall temperature (Tw) was 90 °C, 80 °C, 70 °C, 60 °C, 50 °C
90°
100 2
Weight of deposits (mg/cm )
270°
Metal specimen
Metal specimen
0° Flue gas
80 60 40 20 0
Fig. 2. Metal specimens cut from the outer tube of the test probe.
existing in practice [7]. Only this type of test can be expected to yield realistic results for the corrosion and ash deposition in service conditions giving condensation of acid [33]. The outer tube of the
40
50
60
Tw (°C)
70
80
90
Fig. 4. Weights of the deposits on the test probes after 72-h testing.
Fig. 3. Appearances of the test probes after 72-h testing.
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and 40 °C. It took 72 h to examine one test probe in the flue duct under one temperature condition. Table 3 illustrates the flue gas parameters at the testing location during the experiment. After the experiment, the test probes were observed visually. We took the deposits off the probes and weighed them. The outer tubes of the test probes were cut into small metal specimens, as
shown in Fig. 2. Due to the symmetry, only half of each cross section was necessary to be observed and detected. Four specimens were cut from the half of each cross section, and the corresponding angle of each specimen was 45°. Then the cross sections of the specimens were polished and analyzed by scanning electron microscope (SEM) with energy dispersive spectroscopy (EDS).
20# Tw=90°C
ND Tw=90°C
316L Tw=90°C
20# Tw=80°C
ND Tw=80°C
316L Tw=80°C
20# Tw=70°C
ND Tw=70°C
316L Tw=70°C
20# Tw=60°C
ND Tw=60°C
316L Tw=60°C
20# Tw=50°C
ND Tw=50°C
316L Tw=50°C
20# Tw=40°C
ND Tw=40°C
316L Tw=40°C
Fig. 5. Typical SEM pictures of the cross sections of the metal specimens cut from the test probes’ outer tubes.
H. Chen et al. / Fuel 208 (2017) 149–159
The deposits taken from the test probes were finely ground for the following analysis. X-ray fluorescence (XRF) was used to determine the elemental compositions of the deposit samples, and X-ray diffraction (XRD) was applied to identify the main compounds in the deposits. The micro-morphologies and different micro-zones’ elemental compositions of the deposit samples were inspected by SEM EDS.
3. Results 3.1. Visual observation After being tested in the actual flue gas for 72 h, the test probes were taken out, and Fig. 3 shows their appearances. Fig. 4 presents the weights of the deposits on the probes. The deposits on the probes significantly increase with the decrease of the wall temperature when it is less than 70 °C. When the wall temperature is or above 60 °C, the deposits on the probes are scattered without ‘‘coated” ash layers, concentrating on the leeward sides of the probes. While the wall temperature is lower than 60 °C, the deposits cover the whole surfaces of the probes. And the deposits on the leeward sides are fragile, but the deposits on the windward sides are dense like ‘‘hard shells”. It seems that the deposits on the leeward side of the probe under the wall temperature 40 °C were broken before the probe was brought out. When the wall temperature is higher than 60 °C, no visible rust exists on the test probes. How-
Average corroison layer depth (μm)
80
180°
70 270°
90°
60 50
0° Flue gas
40 30 20 10 0 20#
ND
316L
Fig. 6. Average corrosion layer depths of different regions of the test probe’ outer tube under the condition Tw = 60 °C.
153
ever, evident corrosion can be seen on the probes when the wall temperature is or below 60 °C.
3.2. Analysis results of the metal specimens The metal specimens of the three tested materials under different wall temperature conditions were all observed by SEM. Because the corrosion and deposits formed on the surface in contact with the flue gas, only the outside surfaces of the test probes’ outer tubes were of interest in this study. SEM pictures were uniformly taken from the areas near the outer surfaces on the cross sections of the metal specimens. The typical SEM pictures of the metal specimens are presented in Fig. 5. The corrosion of the metal surface becomes worse as the wall temperature decreases, especially when the wall temperature is below 70 °C. There are distinct corrosion layers on 20# and ND under all the six conditions, and obvious cracks can be seen in some corrosion layers. But significant pitting corrosion appears on 316 L when the wall temperature is lowered to 60 °C. The depths of the corrosion layers of the metal specimens were all measured on their SEM pictures. Then the average corrosion layer depths of different regions (corresponding to the metal specimens) of the test probes under different conditions could be calculated. We found that the region that is 90°–135° to the gas flow direction had the deepest corrosion layer for one material under one condition. As an example, the average corrosion layer depths at different regions of the test probe’ outer tube under the condition Tw = 60 °C are shown in Fig. 6. It is likely that the regions that are 90°–135° to the gas flow direction were the most dangerous regions of the test probes considering the corrosion risk. In order to compare the corrosion statuses under different wall temperatures, Fig. 7 shows the average corrosion layer depths of the regions that are 90°–135° to the gas flow direction of the three tested materials under different wall temperatures. When the wall temperature is lower than 80 °C, the corrosion layer depths of 20# and ND increases rapidly. But the corrosion layer depth of 316 L is nearly zero when the wall temperature is higher than 60 °C. In summary, the corrosion resistances of the three materials are 316 L > ND > 20#. To find out the reason for the corrosion of the tested materials under different wall temperatures, the elemental compositions of all the corrosion layers were determined by EDS. For example, the typical EDS analysis results of the metal specimens under the conditions Tw = 80 °C, Tw = 70 °C and Tw = 60 °C are presented in Fig. 8 and Table 4 (no visible corrosion layers on 316 L when the wall temperature is above 60 °C). When the wall temperature is
Fig. 7. Average corrosion layer depths of the regions that are 90°–135° to the flue gas flow direction of the three tested materials under different wall temperature conditions.
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H. Chen et al. / Fuel 208 (2017) 149–159
20# Tw=80°C
1
ND Tw=80°C
6
3 7 2
4
5 ND Tw=70°C
20# Tw=70°C
10
14
8
12 13
9
11
ND Tw=60°C
20# Tw=60°C
25
19 16 20
316L Tw=60°C
27
23 21
15
28
18
29
24 22
17
26
Fig. 8. Typical EDS detecting micro-zones on the corrosion layers of the three tested materials under the conditions Tw = 80 °C, Tw = 70 °C and Tw = 60 °C.
Table 4 EDS analysis results of the corrosion layers corresponding to the detecting micro-zones in Fig. 8 (wt%). Tw (°C)
Material
Zone
O
Si
Na
S
Cl
Cr
Fe
Ni
Cu
Sb
80
20#
1 2 3 4 5 6 7
42.21 42.37 44.75 42.10 44.80 43.20 43.18
– – – – – – –
– – – – – – –
0.08 0.09 0.05 – 0.04 – –
0.07 0.06 0.06 0.13 – 0.06 –
– – – – 1.28 0.64 0.73
57.64 57.47 55.15 57.71 52.44 54.15 55.18
– – – – – – –
– – – – 1.42 1.96 0.92
– – – – – – –
8 9 10 11 12 13 14
46.55 48.96 47.40 46.65 36.05 30.40 35.34
– – – – – – –
– – – – 2.22 – –
– – 0.23 0.27 0.65 – –
0.74 0.69 1.06 0.99 0.56 0.86 0.93
– – – – 0.46 0.62 2.08
52.71 50.35 51.31 51.97 59.01 68.11 60.06
– – – – – – –
– – – – 0.51 – 0.74
– – – – 0.02 – 0.94
15 16 17 18 19 20 21 22 23 24 25 26 27 28 29
50.48 48.70 45.68 45.94 44.73 44.85 45.38 44.76 43.61 42.28 31.85 47.04 44.42 43.24 45.83
– – – – 2.45 2.27 – – – – – – – – –
– – – – – – – – – – – – – – –
0.14 0.22 – – 0.05 0.15 0.26 0.52 0.11 0.12 0.3 0.39 0.40 0.08 0.22
3.56 5.65 2.18 4.68 3.29 3.39 5.40 5.8 3.34 3.07 3.24 7.14 7.58 6.78 6.91
– – – – – – 0.16 0.07 0.75 0.68 – 10.33 2.78 5.18 1.95
45.82 45.44 52.14 49.38 49.48 49.34 48.75 48.78 52.15 53.21 63.40 31.8 42.77 40.77 41.81
– – – – – – – – – – – 3.30 1.77 3.94 3.29
– – – – – – 0.05 0.07 – 0.65 1.16 – 0.25 – –
– – – – – – – – – – – – – – –
ND
70
20#
ND
60
20#
ND
316 L
higher than 70 °C, there is little sulphur or chlorine existing in the corrosion layers of 20# and ND. The contents of sulphur and chlorine become evident in the corrosion layers when the wall temperature falls to 70 °C, and chlorine is richer than sulphur in the
corrosion layers. When the wall temperature decreases to 60 °C, the chlorine content in the corrosion layers of the three tested materials is extremely high, but the sulphur content is not in high levels.
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H. Chen et al. / Fuel 208 (2017) 149–159 Table 5 Elemental compositions of the deposit samples identified by XRF (expressed as oxides, wt%). Deposit sample
MgO
Cl
Na2O
CaO
TiO2
K2O
SO3
Fe2O3
F
Al2O3
SiO2
Deposits on the flue duct before the flue gas cooler Deposits on the test probes Tw = 90 °C Tw = 80 °C Tw = 70 °C Tw = 60 °C Tw = 50 °C Tw = 40 °C
1.01
0.42
1.46
8.30
0.86
2.57
1.48
5.96
0.41
20.94
49.50
1.42 1.40 1.32 1.16 1.21 1.18
0.41 0.44 0.85 2.42 2.64 2.52
1.58 1.60 1.81 1.75 1.64 1.66
6.86 6.72 8.24 6.86 6.28 7.05
0.94 0.94 0.90 0.77 0.81 0.81
2.82 2.78 2.58 2.43 2.32 2.32
1.47 1.46 2.22 2.70 3.45 4.20
5.99 6.05 7.53 8.34 9.29 7.05
0.40 0.40 0.98 2.63 1.95 2.76
21.16 20.97 19.84 18.16 19.08 18.90
51.13 51.77 50.49 47.06 46.42 44.71
Table 6 Primary compounds in the deposit samples identified by XRD. Deposit sample
Primary compounds
Deposits on the flue duct before the flue gas cooler Deposits on the Tw = 90 °C test probes Tw = 80 °C
SiO2, Al2SiO5, Ca12Al14O33, CaSO4, (K, Na) AlSiO4, KAlSi2O6, FeAl2O4 SiO2, Al2SiO5, Ca3Al2O6, CaSO4, KAlSi2O6, Na2SiO36H2O, Fe2O3 SiO2, Al2SiO5, Ca3Al2O6, CaSO4, KAlSi2O6, NaAlSi2O6, Fe2O3 SiO2, Al2SiO5, CaAl2Si2O84H2O, CaSO4, KCl, KNaSiF6, Fe2O3 SiO2, Al2SiO5, CaAl2SiO6, CaSO4, KNaSiF6, (K0.6Na0.4)Cl, NaCl, Fe2O3 SiO2, Al2SiO5, Ca5Si6O16(OH)2, CaSO4, KNaSiF6, NaCa(AlF5)F, FeCl22H2O, FeO(OH) SiO2, Al2SiO5, CaSi2O52H2O, CaSO4, KNaSiF6, (K0.6Na0.4)Cl, FeClO, Fe2O3
Tw = 70 °C Tw = 60 °C Tw = 50 °C Tw = 40 °C
3.3. Analysis results of the deposits Table 5 shows the XRF analysis results of the deposits on the flue duct before the flue gas cooler and the deposits on the test probes under different wall temperatures. The elemental compositions of the deposits on the probes under the wall temperature 80 °C and 90 °C are similar to that of the deposits on the flue duct. However, when the wall temperature falls to 70 °C, the contents of chlorine, sulphur and fluorine in the deposits grow dramatically. It is likely that hydrochloric acid, sulphuric acid and hydrofluoric acid began to condense onto the wall at this temperature. When the wall temperature is lowered to 60 °C, the chlorine content and fluorine content in the deposits are more than double those of the deposits under the condition Tw = 70 °C, which implies that the condensate of hydrochloric acid and hydrofluoric acid deposited on the probes under the condition Tw = 60 °C was much more than that under the condition Tw = 70 °C. The primary compounds in the deposit samples determined by XRD are given in Table 6. When the wall temperatures are 80 °C and 90 °C, the main compounds in the deposits on the probes are similar to those in the deposits on the flue duct. Sulphur exists as CaSO4 in all the deposit samples. It seems CaSO4 was the product of the reactions between sulphuric acid or sulphurous acid and ash. When the wall temperature is lower than 80 °C, there are also chlorine-containing compounds and fluorine-containing compounds in the deposits, which could be the reaction products between hydrochloric acid or hydrofluoric acid and ash or metal surface. According to the compounds in the deposit samples, we can see that the acid condensate mainly reacted with the compounds containing alkali metal elements (calcium, sodium, potassium, etc.) of fly ash. Fig. 9 and Table 7 present the typical SEM pictures with EDS detecting micro-zones and the corresponding EDS analysis results of the deposit samples. The appearances of the deposits on the flue duct are alike with those of the deposits on the probes when the wall temperature is higher than 70 °C. And there are mainly spher-
ical particles in these three deposit samples. When the wall temperature is or below 70 °C, obvious agglutinate blocks exist in the deposits. The agglutinate blocks contain high contents of sulphur, chlorine and fluorine, which means the condensed acid stimulated the forming of the blocks. And it is likely that the fine particles in the agglutinate blocks were sticky and acted as ‘‘adhesion agent” during the viscous ash deposit formation. In order to investigate the acid condensate distribution in the deposits. The deposits on the probe under the condition Tw = 50 °C were divided into three layers for elemental analysis. The contents of sulphur, chlorine and fluorine in the deposit layers are depicted in Fig. 10. The chlorine and fluorine contents are higher in the outer layer, but the sulphur content doesn’t change much in different layers. It seems that the hydrochloric acid condensate and fluoric acid condensate were more inclined to react with ash than the sulphuric acid condensate. But the chlorine content is still very high in the inner layer and much more than the contents of sulphur and fluorine, which implies that the hydrochloric acid condensate might play the most important role in the corrosion.
4. Discussion The analysis results of the metal specimens showed that the corrosion rates of 20# and ND increased notably when the wall temperature was lower than 80 °C, and the corrosion of 316 L worsened when the wall temperature dropped to 60 °C. There was noticeable sulphur and chlorine existing in the corrosion layers of 20# and ND when the wall temperature was 70 °C. When the wall temperature decreased to 60 °C, the chlorine content became much more than the sulphur content in the corrosion layers. Sulphuric acid and hydrochloric acid might begin to condense onto the probe and corrode the metal surface when the wall temperature fell to 70 °C. It appears that mainly sulphuric acid and hydrochloric acid contributed to aggravating the corrosion of the metal surface. The chlorine content was particularly high in the corrosion layers, and hydrochloric acid has a stronger corrosion ability than sulphuric acid [7], which means that hydrochloric acid played the greater role in the dewpoint corrosion. Since the corrosion products could fall off the metal surface and mingle with the deposits on the probes, the possible corrosion products are able to be deduced from the Fe-containing compounds in the deposits. Table 6 suggests that when the wall temperature was above 50 °C, the major corrosion product was probably Fe2O3; as the wall temperature was 50 °C, the corrosion products could be FeCl22H2O and FeO(OH); when the wall temperature was 40 °C, the corrosion products might be FeClO and Fe2O3. The analysis results of the deposit samples indicated that the deposits on the probe grew rapidly when the wall temperature was less than 70 °C. When the wall temperature decreased to 70 °C, the contents of sulphur, chlorine and fluorine in the deposit samples became significant, which implies that sulphuric acid, hydrochloric acid and hydrofluoric acid were possible to start
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H. Chen et al. / Fuel 208 (2017) 149–159
Tw=90°C
Deposits on the flue duct
3
1 2
Tw=80°C
5
4
Tw=70°C
8 9
6 7
10
Tw=60°C
Tw=50°C
11 15
12 13
14
16
Tw=40°C
17
18
19 Fig. 9. Typical SEM pictures with EDS detecting micro-zones of the deposit samples.
condensing and depositing onto the probe at this temperature. It seems that the increase of the deposits on the probe was caused by the condensation of these three acids. But when the wall temperature was higher than 50 °C, the deposits on the probe were not many and mainly on the leeward side instead of covering the whole probe. In addition, the acid condensate could react with the fly ash to form salt compounds. And mainly the compounds containing alkali metals in the ash reacted with the acid condensate. Since sulphur, chlorine and fluorine but no nitrogen were found in the deposit samples and the corrosion layers, we can infer that sulphuric acid, hydrochloric acid, hydrofluoric acid and sulphurous acid might condense during the experiment. The corrosion and ash
deposition of low-temperature heating surface were closely related to the dewpoints of these acids in the flue gas. The prediction of sulphuric acid dewpoint has been extensively investigated in the last decade [12]. In this paper, the sulphuric acid dewpoint and water dewpoint of the flue gas were approximately 90.25 °C and 42.78 °C, calculated by Soviet Union Thermal Power Computation Standard (1973) [34], which is the most common method in engineering in China [35]. Less research has been performed on estimating the dewpoints of hydrochloric acid and sulphurous acid in the flue gas. According to gas-liquid equilibrium data, Kiang [36] provided the empirical correlations for calculating the dewpoints of hydrochloric acid and sulphurous acid based on the partial pressures of water vapor and hydrochloric acid vapor or SO2
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H. Chen et al. / Fuel 208 (2017) 149–159 Table 7 EDS analysis results of the deposit samples corresponding to the detected micro-zones in Fig. 9 (expressed as oxides, wt%). Deposit sample
Zone
F
Na2O
MgO
Al2O3
SiO2
SO3
Cl
K2O
CaO
TiO2
Fe2O3
Deposits on the flue duct before the flue gas cooler Deposits on the test probes Tw = 90 °C
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19
– – – – – – – 2.31 – – 11.17 – – 3.76 4.92 3.83 3.24 – –
1.79 1.09 – – – 1.63 1.46 – – 2.32 – – – – 0.88 – – – –
2.39 – – 3.22 – – – – – 0.96 – – –0.88 1.18 – – – –
24.90 48.58 2.42 25.68 3.87 12.47 13.79 2.19 1.66 17.25 5.29 4.63 5.04 8.77 13.43 8.22 1.62 3.00 8.71
70.36 61.89 41.39 48.50 104.11 73.16 77.18 8.06 4.54 57.48 9.86 9.33 71.92 19.23 31.17 32.79 2.05 5.22 29.29
– – – –
– – – – – – – 12.60 15.90 1.58 8.42 6.64 3.91 9.04 6.24 5.58 0.66 1.59 1.67
3.57 2.63 – – 1.55 1.96 1.30 – – 3.02 – – 1.25 – 1.29 1.25 – – 1.22
3.90 4.11 1.83 18.74
– – – 2.64 – – – – – – – – – – – – – – –
8.21 – 70.06 7.86 – 3.29 3.90 87.28 72.89 16.04 30.00 97.28 22.43 34.73 26.65 25.76 – 3.97 60.05
Tw = 80 °C Tw = 70 °C
Tw = 60 °C
Tw = 50 °C
Tw = 40 °C
5
Cl S F
Element content (%)
4 3 2 1 0
Inner layer (close to the wall)
Middle layer
Outer layer (close to the flue gas)
Fig. 10. Contents of sulphur, chlorine and fluorine in the deposit layers on the probe under the condition Tw = 50 °C identified by XRF.
without the consideration of the fly ash in the flue gas. According to these empirical correlations, the calculated dewpoints of hydrochloric acid and sulphurous acid were about 43.55 °C and
– – – – 3.57 12.31 3.52 1.47 13.09 10.29 11.46 64.28 45.67 8.67
5.72 3.39 1.23 1.06 9.99 30.00 7.33 6.44 16.82 21.66 29.27 45.38 33.38 8.95
43.17 °C. Besides, Xiang [37] noted that the SO2 in flue gas could only combine water condensate to form sulphurous acid when the temperature was lower than the water dewpoint of the flue gas. Since little literature has been published regarding the hydrofluoric acid dewpoint, it is hard to estimate the hydrofluoric acid dewpoint in the flue gas. When the wall temperature is lower than the dewpoint of one acid, the acid vapor in the flue gas will condense in the field near the wall, where the field temperature is below the acid dewpoint. Fig. 11 illustrates the possible behaviors of acid condensate and ash particles when the flue gas flows across the low-temperature heating surface. The acid condensate mainly has three probable behaviors: (1) depositing onto the tube wall, causing corrosion, attracting the ash particles from the flue gas and reacting with the deposited ash particles; (2) adhering to ash particles in the flue gas and making the particles sticky, reacting with the ash at the same time; (3) flowing away with the flue gas. The possible behaviors of the ash particles are: (1) absorbing the acid condensate in the flue gas; (2) depositing onto the tube wall; (3) hitting against the tube wall, then going away; (4) flowing away with the flue gas directly. The ash particles that have absorbed acid condensate and become sticky probably act in three ways: (1) depositing onto
Fig. 11. Coupling model of acid condensation and fly ash behaviors in the field near the low-temperature heating surface when the wall temperature is below the acid dewpoint of the flue gas.
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Fig. 12. Main factors affecting the dewpoint corrosion and viscous deposits of low-temperature heating surface.
Fig. 13. Acid condensate that contributes to the dewpoint corrosion and viscous deposits under different wall temperatures.
the tube wall; (2) bonding to other particles; (3) flowing away with the flue gas. As the wall temperature decreases, more and more acid condensate will form and deposit onto the tube wall, resulting in more severe dewpoint corrosion and viscous deposits. The fly ash can help to reduce the corrosion and viscous deposits by absorbing and reacting with the acid condensate. In addition, there are particles especially big particles to scour the wall, which is beneficial to remove the deposits on the wall. The above analysis can explain the basic formation processes of the corrosion and viscous ash deposits on low-temperature heating surface when the wall temperature is lower than the acid dewpoints. And according to the behaviors of acid condensate and fly ash, we can propose the main factors that affect the dewpoint corrosion and viscous deposits on low-temperature heating surface, as indicated in Fig. 12. In this paper, when the wall temperature was 80 °C and 90 °C, which were very likely below the sulphuric acid dewpoint in the flue gas, the metal surface didn’t suffer obvious acid corrosion. The corrosion of 20# and ND might be caused by oxygen or some acid condensate on the ash particles at these temperatures, and the corrosion was not severe. The corrosion of the metal surface started to deteriorate because of the sulphuric acid and hydrochloric acid condensate when the wall temperature fell to 70 °C. It seems the condensation rates of the sulphuric acid and hydrochloric acid were bigger than the rate that the fly ash absorbed and reacted with the acid condensate in the flue gas at this time. The
contents of sulphur, chlorine and fluorine began to be significant in the deposits when the wall temperature was 70 °C, which means viscous deposits could form under this temperature. But there were not many deposits on the probes until the wall temperature decreased to 50 °C. A possible explanation for this is that the viscous deposits were not enough to cover the probe on account of the particles’ hitting and scouring the probes. When the wall temperature was 40 °C that was lower than the water dewpoint, water and sulphurous acid would also condense onto the wall. The different kinds of acid condensate that formed and contributed to the dewpoint corrosion and viscous deposits under different wall temperatures are summarized in Fig. 13. In addition, the results suggest that the actual dewpoints of sulphuric acid, hydrochloric acid and hydrofluoric acid should be higher than 70 °C. Because of the differences in fired coal properties, flue gas parameters and power plants, it is difficult to compare the results of this paper to the previous study [3,28,29] that performed after the electrostatic precipitators in coal-fired power plants. But it is still worthwhile to note that the wall temperature under which ‘‘coated” deposits could form on the tubes was much lower before the precipitator than that after the precipitator. Besides, the effects of hydrochloric acid and fluoric acid on the corrosion and ash deposition of the low-temperature heating surface in coal-fired power plants didn’t draw enough attention in the previous work.
H. Chen et al. / Fuel 208 (2017) 149–159
Two points are worth of notice in the application of waste heat recovery devices for coal-fired power plants: the wall temperature at which the tube can suffer hydrochloric acid corrosion is possibly as high as 70 °C; when the wall temperature is less than 80 °C, not only sulphuric acid but also hydrochloric acid and fluoric acid can contribute to the viscous deposits on the heating surface. In addition, the corrosion of 20# and ND seems inevitable during the flue gas cooling process, but the corrosion rate can be controlled by adjusting the tube wall temperature and other methods. 5. Conclusions This study investigated the corrosion and ash deposition of lowtemperature heating surface with temperature-controlled test probes in a large-scale coal-fired power plant. Three materials were examined under six wall temperatures, and the corresponding deposit samples and metal specimens were analyzed. The results showed that the corrosion and ash deposition became worse as the wall temperature decreased. When the wall temperature dropped to 70 °C, sulphuric acid, hydrochloric acid and hydrofluoric acid started to condense onto the probe. The actual dewpoints of sulphuric acid, hydrochloric acid and hydrofluoric acid in the flue gas should be higher than 70 °C. These three acids caused the viscous deposits on the probes, but ‘‘coated” deposits didn’t form until the wall temperature was lowered to 50 °C. The acid condensate could react with the fly ash to produce salt compounds. Mainly sulphuric acid condensate and hydrochloric acid condensate exacerbated the corrosion of the metal surface, and the possible corrosion products were different under different wall temperatures. The corrosion resistances of the three tested materials were 316 L > ND > 20#. The coupling model of acid condensation and fly ash behaviors was proposed to explain the corrosion and ash deposition mechanisms of low-temperature heating surface. By absorbing and reacting with the acid condensate, the fly ash could help to reduce the corrosion caused by acid condensation. The main factors affecting the corrosion and ash deposition were also summarized and recommendations were drawn to reduce the corrosion and fouling of the heat recovery devices in coal-fired power plant. Future research on the corrosion and ash deposition of low-temperature heating surface can be conducted with long-term tests in the field or different types of heat exchange tubes such as finned tubes. Acknowledgements This work was supported by the National Natural Science Foundation of China (NO. 51606144) and the National Key Research and Development Program of China (No. 2016YFC0801904). References [1] Xu G, Xu C, Yang Y, Fang Y, Li Y, Song X. A novel flue gas waste heat recovery system for coal-fired ultra-supercritical power plants. Appl Therm Eng 2014;67:240–9. [2] Ye Y, Shen S. Characteristics of European high-efficiency coal fired units and their implications for Chinese power plant. Electr Power Constr 2011;32:54–8 (In Chinese). [3] Liang ZY, Zhao QX. Research on dew point corrosion of materials. Appl Mech Mater 2013;281:441–7. [4] Wang C, He B, Sun S, Wu Y, Yan N, Yan L, et al. Application of a low pressure economizer for waste heat recovery from the exhaust flue gas in a 600 MW power plant. Energy 2012;48:196–202. [5] Wang C, He B, Yan L, Pei X, Chen S. Thermodynamic analysis of a low-pressure economizer based waste heat recovery system for a coal-fired power plant. Energy 2014;65:80–90.
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Full Length Article
Field study on the corrosion and ash deposition of low-temperature heating surface in a large-scale coal-fired power plant Heng Chen, Peiyuan Pan, Yungang Wang, Qinxin Zhao ⇑ Key Laboratory of Thermo-Fluid Science and Engineering of MOE, School of Energy and Power Engineering, Xi’an Jiaotong University, Xi’an, Shaanxi 710049, China
h i g h l i g h t s Corrosion and ash deposition of low-temperature heating surface before the precipitator. Three materials were tested under different tube wall temperatures in real flue gas. Mechanisms of dewpoint corrosion and viscous deposition were discussed. Coupling model of acid condensation and fly ash behaviors was proposed. Effects of sulphuric acid, hydrochloric acid and fluoric acid were all investigated.
a r t i c l e
i n f o
Article history: Received 13 December 2016 Received in revised form 1 May 2017 Accepted 27 June 2017
Keywords: Flue gas cooling Low-temperature heating surface Dewpoint corrosion Viscous ash deposition Coal-fired power plant Acid condensation
a b s t r a c t The corrosion and ash deposition of low-temperature heating surface were investigated in a 660 MW coal-fired power plant. The temperature-controlled test probes constructed of three materials were tested under different wall temperatures (90 °C, 80 °C, 70 °C, 60 °C, 50 °C and 40 °C). The metal specimens and deposit samples were analyzed by X-ray fluorescence, X-ray diffraction and scanning electron microscope with energy dispersive spectroscopy. The results revealed that when the wall temperature fell to 70 °C, viscous deposits began to form on the probes due to the condensation of sulphuric acid, hydrochloric acid and hydrofluoric acid. Meanwhile, the sulphuric acid condensate and hydrochloric acid condensate stimulated the corrosion of the metal surface. The corrosion and deposits increased with the decrease of the wall temperature. The corrosion resistances of the three tested materials were 316 L > ND > 20#. The corrosion mechanism and ash deposition mechanism of low-temperature heating surface were discussed. The coupling model of acid condensation and fly ash behaviors was proposed, and the main factors affecting the corrosion and ash deposition were summarized. Suggestions were made to alleviate the corrosion and fouling of waste heat recovery devices in coal-fired power plants. Ó 2017 Elsevier Ltd. All rights reserved.
1. Introduction In China, the power industry has developed vigorously, and the power coal consumption has been accounted for >50% of the total coal production [1]. According to surveys, the exhaust gas temperature of utility boiler in China typically maintains in the level of 120–150 °C [2]. A 10 °C decrease in the flue gas temperature can cause a 0.6%–1.0% increase in the boiler efficiency [3]. Therefore, the foreground of waste heat recovery for coal-fired power plants is considerable. In recent years, waste heat recovery devices have been widely applied in coal-fired power plants in China, which can recover heat from flue gas [1,4,5] and help in synergistically reducing SO3/H2SO4 ⇑ Corresponding author. E-mail address: [email protected] (Q. Zhao). http://dx.doi.org/10.1016/j.fuel.2017.06.120 0016-2361/Ó 2017 Elsevier Ltd. All rights reserved.
and particulate emissions [6]. However, some of these already used heat recovery devices have suffered severe corrosion and fouling during their operations, which led to the leaking of heat exchange tubes, the increase of gas flow resistance, the decrease of heat transfer efficiency and even the shutdown of the power plants. The lowest heating surface temperature of a heat recovery device is usually low, approximately 60 °C–90 °C. When the heating surface temperature is below the dewpoints of the acids (sulphuric acid, hydrochloric acid, etc.) in the flue gas, the acids can condense onto the heating surface, resulting in dewpoint corrosion and viscous ash deposits [7], which are severe problems for the heat recovery devices of coal-fired power plants. Many studies have been done regarding the corrosion and ash deposition of low-temperature heating surface. Much of the literature focuses on predicting the sulphuric acid dewpoint in the flue gas [8–13]. A few researchers experimentally investigated the
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dewpoint corrosion with simulated flue gas [14,15] or immersion tests [16,17]. A volume of work has been carried out on the corrosion and deposits of low-temperature heating surface by field sampling [18–25]. However, field experimental research on dewpoint corrosion and viscous ash deposition is still insufficient. Vainio [26] and Wang [27] examined the low-temperature corrosion of biomass boilers in the field. Wang [28] and Liang [3,29] explored the coupling mechanism between dewpoint corrosion and ash deposition in coal-fired power plants, but they did the tests after the electrostatic precipitators, where the fly ash concentrations were very low. And the fly ash concentration of the flue gas has an important influence to the low-temperature corrosion and ash deposition. What’s more, most of the applied waste heat recovery devices are installed before precipitators for synergistically removing SO3/H2SO4 and particulates [30,31]. Hence, it is necessary to study the corrosion and ash deposition of the low-temperature heating surface before the precipitators in coal-fired power plants. Li [32] investigated the relation of ash deposition and sulphuric acid condensation under different temperatures before the precipitator on a coal-fired boiler unit, but the corrosion mechanism and the effects of other acids were not fully discussed. In this paper, the corrosion and ash deposition characteristics of low-temperature heating surface were experimentally studied in a large-scale coal-fired power plant. Six test probes were examined under different wall temperatures in the flue gas before the electrostatic precipitator, and the corresponding metal specimens and deposit samples were analyzed. The objective was to investigate the mechanisms of the dewpoint corrosion and viscous ash deposition under high fly ash concentration during the flue gas cooling process, which would be beneficial to reduce the corrosion and fouling of the waste heat recovery devices for coal-fired power plants.
Table 1 Typical property of the burned coal of the boiler analyzed according to Chinese National Standards. Parameter
Value
Chinses National Standard
Proximate analysis
14.60 5.76 12.92 31.85 55.23 27.97
GB/T 212-2008
71.03 3.97 10.68 0.94 0.46 0.022 0.013 48.44 21.28 1.02 6.64 10.00 1.30 1.10 1.54 4.71 3.97
GB/T 31391-2015
Moisture (wt%, ar) Moisture (wt%, ad) Ash (wt%, db) Volatile matter (wt%, db) Fixed carbon (wt%, db) Higher heating value (MJ/kg, db) Ultimate analysis C (wt%, db) H O N S Cl content of the coal (wt%, db) F content of the coal (wt%, db) Ash composition SiO2 (wt%, ash basis) Al2O3 TiO2 Fe2O3 CaO MgO Na2O K2O SO3 Others
Note: ar – as received basis; ad – air dry basis; db – dry basis.
29.3 MPa. The typical property of the coal burned by the boiler was analyzed on the basis of Chinese National Standards, as given in Table 1. As Fig. 1 shows, the temperature-control multi-element laminar test probe [33] was put into the vertical flue duct after the air preheater and in front of the flue gas cooler. The flue gas flowed across the probe from below, and the outer tube wall temperature was kept by the cooling water. A constant-temperature cycle machine was applied to maintain the inlet cooling water’s temperature constant. Comparing to the studies with simulated flue gas or immersion tests, this method with cooled specimens inserted into the boiler flue duct during normal service, is closer to the conditions
2. Experimental section The experiment was conducted in a 660 MW ultra-supercritical coal-burning power plant. The boiler of the plant is a single reheat, G-type arrangement, tangentially fired and pulverized coal boiler. The rated evaporating capacity of the boiler is 1968t/h. The main steam temperature and pressure of the boiler are 603 °C and
Outer Tube
Flue gas
Cooling Water
Wall of the flue duct
Inner Tube
20#
ND
316L
Test probe Desulfurizing tower
Boiler
Air heater
GB/T 3558-2014 GB/T 4633-2014 GB/T 1574-2007
Flue gas cooler Electrostatic Coolant precipitator
Fig. 1. Schematic diagram of the experimental location and the test probe.
Smoke stack
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H. Chen et al. / Fuel 208 (2017) 149–159 Table 2 Elemental compositions of the three tested materials (wt%). Material
C
Si
Mn
P
S
Cu
Ni
Cr
Mo
Sb
Fe
20# ND 316L
0.19 0.08 0.03
0.21 0.22 0.41
0.53 0.48 0.95
0.013 0.011 0.038
0.003 0.005 0.030
0.03 0.29 –
0.01 0.02 10.96
0.03 0.79 18.12
– – 2.81
– 0.06 –
Bal. Bal. Bal.
Table 3 Flue gas parameters at the testing location during the experiment. Parameter
Unit
Maximum
Minimum
Average
Velocity Temperature SO2 NOx O2 Fly ash concentration
m/s °C mg/m3 mg/m3 % g/m3
11.32 126.37 946.89 26.57 7.91 10.23
8.48 105.76 656.21 9.63 5.39 13.76
9.87 114.25 798.43 18.94 6.84 12.47
180°
Metal specimen Metal specimen
test probe consisted of three materials: mild steel 20#, weathering steel ND and stainless steel 316 L, and Table 2 shows their compositions. In this study, the corrosion and ash deposition of lowtemperature heating surface were investigated when the outer tube wall temperature (Tw) was 90 °C, 80 °C, 70 °C, 60 °C, 50 °C
90°
100 2
Weight of deposits (mg/cm )
270°
Metal specimen
Metal specimen
0° Flue gas
80 60 40 20 0
Fig. 2. Metal specimens cut from the outer tube of the test probe.
existing in practice [7]. Only this type of test can be expected to yield realistic results for the corrosion and ash deposition in service conditions giving condensation of acid [33]. The outer tube of the
40
50
60
Tw (°C)
70
80
90
Fig. 4. Weights of the deposits on the test probes after 72-h testing.
Fig. 3. Appearances of the test probes after 72-h testing.
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and 40 °C. It took 72 h to examine one test probe in the flue duct under one temperature condition. Table 3 illustrates the flue gas parameters at the testing location during the experiment. After the experiment, the test probes were observed visually. We took the deposits off the probes and weighed them. The outer tubes of the test probes were cut into small metal specimens, as
shown in Fig. 2. Due to the symmetry, only half of each cross section was necessary to be observed and detected. Four specimens were cut from the half of each cross section, and the corresponding angle of each specimen was 45°. Then the cross sections of the specimens were polished and analyzed by scanning electron microscope (SEM) with energy dispersive spectroscopy (EDS).
20# Tw=90°C
ND Tw=90°C
316L Tw=90°C
20# Tw=80°C
ND Tw=80°C
316L Tw=80°C
20# Tw=70°C
ND Tw=70°C
316L Tw=70°C
20# Tw=60°C
ND Tw=60°C
316L Tw=60°C
20# Tw=50°C
ND Tw=50°C
316L Tw=50°C
20# Tw=40°C
ND Tw=40°C
316L Tw=40°C
Fig. 5. Typical SEM pictures of the cross sections of the metal specimens cut from the test probes’ outer tubes.
H. Chen et al. / Fuel 208 (2017) 149–159
The deposits taken from the test probes were finely ground for the following analysis. X-ray fluorescence (XRF) was used to determine the elemental compositions of the deposit samples, and X-ray diffraction (XRD) was applied to identify the main compounds in the deposits. The micro-morphologies and different micro-zones’ elemental compositions of the deposit samples were inspected by SEM EDS.
3. Results 3.1. Visual observation After being tested in the actual flue gas for 72 h, the test probes were taken out, and Fig. 3 shows their appearances. Fig. 4 presents the weights of the deposits on the probes. The deposits on the probes significantly increase with the decrease of the wall temperature when it is less than 70 °C. When the wall temperature is or above 60 °C, the deposits on the probes are scattered without ‘‘coated” ash layers, concentrating on the leeward sides of the probes. While the wall temperature is lower than 60 °C, the deposits cover the whole surfaces of the probes. And the deposits on the leeward sides are fragile, but the deposits on the windward sides are dense like ‘‘hard shells”. It seems that the deposits on the leeward side of the probe under the wall temperature 40 °C were broken before the probe was brought out. When the wall temperature is higher than 60 °C, no visible rust exists on the test probes. How-
Average corroison layer depth (μm)
80
180°
70 270°
90°
60 50
0° Flue gas
40 30 20 10 0 20#
ND
316L
Fig. 6. Average corrosion layer depths of different regions of the test probe’ outer tube under the condition Tw = 60 °C.
153
ever, evident corrosion can be seen on the probes when the wall temperature is or below 60 °C.
3.2. Analysis results of the metal specimens The metal specimens of the three tested materials under different wall temperature conditions were all observed by SEM. Because the corrosion and deposits formed on the surface in contact with the flue gas, only the outside surfaces of the test probes’ outer tubes were of interest in this study. SEM pictures were uniformly taken from the areas near the outer surfaces on the cross sections of the metal specimens. The typical SEM pictures of the metal specimens are presented in Fig. 5. The corrosion of the metal surface becomes worse as the wall temperature decreases, especially when the wall temperature is below 70 °C. There are distinct corrosion layers on 20# and ND under all the six conditions, and obvious cracks can be seen in some corrosion layers. But significant pitting corrosion appears on 316 L when the wall temperature is lowered to 60 °C. The depths of the corrosion layers of the metal specimens were all measured on their SEM pictures. Then the average corrosion layer depths of different regions (corresponding to the metal specimens) of the test probes under different conditions could be calculated. We found that the region that is 90°–135° to the gas flow direction had the deepest corrosion layer for one material under one condition. As an example, the average corrosion layer depths at different regions of the test probe’ outer tube under the condition Tw = 60 °C are shown in Fig. 6. It is likely that the regions that are 90°–135° to the gas flow direction were the most dangerous regions of the test probes considering the corrosion risk. In order to compare the corrosion statuses under different wall temperatures, Fig. 7 shows the average corrosion layer depths of the regions that are 90°–135° to the gas flow direction of the three tested materials under different wall temperatures. When the wall temperature is lower than 80 °C, the corrosion layer depths of 20# and ND increases rapidly. But the corrosion layer depth of 316 L is nearly zero when the wall temperature is higher than 60 °C. In summary, the corrosion resistances of the three materials are 316 L > ND > 20#. To find out the reason for the corrosion of the tested materials under different wall temperatures, the elemental compositions of all the corrosion layers were determined by EDS. For example, the typical EDS analysis results of the metal specimens under the conditions Tw = 80 °C, Tw = 70 °C and Tw = 60 °C are presented in Fig. 8 and Table 4 (no visible corrosion layers on 316 L when the wall temperature is above 60 °C). When the wall temperature is
Fig. 7. Average corrosion layer depths of the regions that are 90°–135° to the flue gas flow direction of the three tested materials under different wall temperature conditions.
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20# Tw=80°C
1
ND Tw=80°C
6
3 7 2
4
5 ND Tw=70°C
20# Tw=70°C
10
14
8
12 13
9
11
ND Tw=60°C
20# Tw=60°C
25
19 16 20
316L Tw=60°C
27
23 21
15
28
18
29
24 22
17
26
Fig. 8. Typical EDS detecting micro-zones on the corrosion layers of the three tested materials under the conditions Tw = 80 °C, Tw = 70 °C and Tw = 60 °C.
Table 4 EDS analysis results of the corrosion layers corresponding to the detecting micro-zones in Fig. 8 (wt%). Tw (°C)
Material
Zone
O
Si
Na
S
Cl
Cr
Fe
Ni
Cu
Sb
80
20#
1 2 3 4 5 6 7
42.21 42.37 44.75 42.10 44.80 43.20 43.18
– – – – – – –
– – – – – – –
0.08 0.09 0.05 – 0.04 – –
0.07 0.06 0.06 0.13 – 0.06 –
– – – – 1.28 0.64 0.73
57.64 57.47 55.15 57.71 52.44 54.15 55.18
– – – – – – –
– – – – 1.42 1.96 0.92
– – – – – – –
8 9 10 11 12 13 14
46.55 48.96 47.40 46.65 36.05 30.40 35.34
– – – – – – –
– – – – 2.22 – –
– – 0.23 0.27 0.65 – –
0.74 0.69 1.06 0.99 0.56 0.86 0.93
– – – – 0.46 0.62 2.08
52.71 50.35 51.31 51.97 59.01 68.11 60.06
– – – – – – –
– – – – 0.51 – 0.74
– – – – 0.02 – 0.94
15 16 17 18 19 20 21 22 23 24 25 26 27 28 29
50.48 48.70 45.68 45.94 44.73 44.85 45.38 44.76 43.61 42.28 31.85 47.04 44.42 43.24 45.83
– – – – 2.45 2.27 – – – – – – – – –
– – – – – – – – – – – – – – –
0.14 0.22 – – 0.05 0.15 0.26 0.52 0.11 0.12 0.3 0.39 0.40 0.08 0.22
3.56 5.65 2.18 4.68 3.29 3.39 5.40 5.8 3.34 3.07 3.24 7.14 7.58 6.78 6.91
– – – – – – 0.16 0.07 0.75 0.68 – 10.33 2.78 5.18 1.95
45.82 45.44 52.14 49.38 49.48 49.34 48.75 48.78 52.15 53.21 63.40 31.8 42.77 40.77 41.81
– – – – – – – – – – – 3.30 1.77 3.94 3.29
– – – – – – 0.05 0.07 – 0.65 1.16 – 0.25 – –
– – – – – – – – – – – – – – –
ND
70
20#
ND
60
20#
ND
316 L
higher than 70 °C, there is little sulphur or chlorine existing in the corrosion layers of 20# and ND. The contents of sulphur and chlorine become evident in the corrosion layers when the wall temperature falls to 70 °C, and chlorine is richer than sulphur in the
corrosion layers. When the wall temperature decreases to 60 °C, the chlorine content in the corrosion layers of the three tested materials is extremely high, but the sulphur content is not in high levels.
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H. Chen et al. / Fuel 208 (2017) 149–159 Table 5 Elemental compositions of the deposit samples identified by XRF (expressed as oxides, wt%). Deposit sample
MgO
Cl
Na2O
CaO
TiO2
K2O
SO3
Fe2O3
F
Al2O3
SiO2
Deposits on the flue duct before the flue gas cooler Deposits on the test probes Tw = 90 °C Tw = 80 °C Tw = 70 °C Tw = 60 °C Tw = 50 °C Tw = 40 °C
1.01
0.42
1.46
8.30
0.86
2.57
1.48
5.96
0.41
20.94
49.50
1.42 1.40 1.32 1.16 1.21 1.18
0.41 0.44 0.85 2.42 2.64 2.52
1.58 1.60 1.81 1.75 1.64 1.66
6.86 6.72 8.24 6.86 6.28 7.05
0.94 0.94 0.90 0.77 0.81 0.81
2.82 2.78 2.58 2.43 2.32 2.32
1.47 1.46 2.22 2.70 3.45 4.20
5.99 6.05 7.53 8.34 9.29 7.05
0.40 0.40 0.98 2.63 1.95 2.76
21.16 20.97 19.84 18.16 19.08 18.90
51.13 51.77 50.49 47.06 46.42 44.71
Table 6 Primary compounds in the deposit samples identified by XRD. Deposit sample
Primary compounds
Deposits on the flue duct before the flue gas cooler Deposits on the Tw = 90 °C test probes Tw = 80 °C
SiO2, Al2SiO5, Ca12Al14O33, CaSO4, (K, Na) AlSiO4, KAlSi2O6, FeAl2O4 SiO2, Al2SiO5, Ca3Al2O6, CaSO4, KAlSi2O6, Na2SiO36H2O, Fe2O3 SiO2, Al2SiO5, Ca3Al2O6, CaSO4, KAlSi2O6, NaAlSi2O6, Fe2O3 SiO2, Al2SiO5, CaAl2Si2O84H2O, CaSO4, KCl, KNaSiF6, Fe2O3 SiO2, Al2SiO5, CaAl2SiO6, CaSO4, KNaSiF6, (K0.6Na0.4)Cl, NaCl, Fe2O3 SiO2, Al2SiO5, Ca5Si6O16(OH)2, CaSO4, KNaSiF6, NaCa(AlF5)F, FeCl22H2O, FeO(OH) SiO2, Al2SiO5, CaSi2O52H2O, CaSO4, KNaSiF6, (K0.6Na0.4)Cl, FeClO, Fe2O3
Tw = 70 °C Tw = 60 °C Tw = 50 °C Tw = 40 °C
3.3. Analysis results of the deposits Table 5 shows the XRF analysis results of the deposits on the flue duct before the flue gas cooler and the deposits on the test probes under different wall temperatures. The elemental compositions of the deposits on the probes under the wall temperature 80 °C and 90 °C are similar to that of the deposits on the flue duct. However, when the wall temperature falls to 70 °C, the contents of chlorine, sulphur and fluorine in the deposits grow dramatically. It is likely that hydrochloric acid, sulphuric acid and hydrofluoric acid began to condense onto the wall at this temperature. When the wall temperature is lowered to 60 °C, the chlorine content and fluorine content in the deposits are more than double those of the deposits under the condition Tw = 70 °C, which implies that the condensate of hydrochloric acid and hydrofluoric acid deposited on the probes under the condition Tw = 60 °C was much more than that under the condition Tw = 70 °C. The primary compounds in the deposit samples determined by XRD are given in Table 6. When the wall temperatures are 80 °C and 90 °C, the main compounds in the deposits on the probes are similar to those in the deposits on the flue duct. Sulphur exists as CaSO4 in all the deposit samples. It seems CaSO4 was the product of the reactions between sulphuric acid or sulphurous acid and ash. When the wall temperature is lower than 80 °C, there are also chlorine-containing compounds and fluorine-containing compounds in the deposits, which could be the reaction products between hydrochloric acid or hydrofluoric acid and ash or metal surface. According to the compounds in the deposit samples, we can see that the acid condensate mainly reacted with the compounds containing alkali metal elements (calcium, sodium, potassium, etc.) of fly ash. Fig. 9 and Table 7 present the typical SEM pictures with EDS detecting micro-zones and the corresponding EDS analysis results of the deposit samples. The appearances of the deposits on the flue duct are alike with those of the deposits on the probes when the wall temperature is higher than 70 °C. And there are mainly spher-
ical particles in these three deposit samples. When the wall temperature is or below 70 °C, obvious agglutinate blocks exist in the deposits. The agglutinate blocks contain high contents of sulphur, chlorine and fluorine, which means the condensed acid stimulated the forming of the blocks. And it is likely that the fine particles in the agglutinate blocks were sticky and acted as ‘‘adhesion agent” during the viscous ash deposit formation. In order to investigate the acid condensate distribution in the deposits. The deposits on the probe under the condition Tw = 50 °C were divided into three layers for elemental analysis. The contents of sulphur, chlorine and fluorine in the deposit layers are depicted in Fig. 10. The chlorine and fluorine contents are higher in the outer layer, but the sulphur content doesn’t change much in different layers. It seems that the hydrochloric acid condensate and fluoric acid condensate were more inclined to react with ash than the sulphuric acid condensate. But the chlorine content is still very high in the inner layer and much more than the contents of sulphur and fluorine, which implies that the hydrochloric acid condensate might play the most important role in the corrosion.
4. Discussion The analysis results of the metal specimens showed that the corrosion rates of 20# and ND increased notably when the wall temperature was lower than 80 °C, and the corrosion of 316 L worsened when the wall temperature dropped to 60 °C. There was noticeable sulphur and chlorine existing in the corrosion layers of 20# and ND when the wall temperature was 70 °C. When the wall temperature decreased to 60 °C, the chlorine content became much more than the sulphur content in the corrosion layers. Sulphuric acid and hydrochloric acid might begin to condense onto the probe and corrode the metal surface when the wall temperature fell to 70 °C. It appears that mainly sulphuric acid and hydrochloric acid contributed to aggravating the corrosion of the metal surface. The chlorine content was particularly high in the corrosion layers, and hydrochloric acid has a stronger corrosion ability than sulphuric acid [7], which means that hydrochloric acid played the greater role in the dewpoint corrosion. Since the corrosion products could fall off the metal surface and mingle with the deposits on the probes, the possible corrosion products are able to be deduced from the Fe-containing compounds in the deposits. Table 6 suggests that when the wall temperature was above 50 °C, the major corrosion product was probably Fe2O3; as the wall temperature was 50 °C, the corrosion products could be FeCl22H2O and FeO(OH); when the wall temperature was 40 °C, the corrosion products might be FeClO and Fe2O3. The analysis results of the deposit samples indicated that the deposits on the probe grew rapidly when the wall temperature was less than 70 °C. When the wall temperature decreased to 70 °C, the contents of sulphur, chlorine and fluorine in the deposit samples became significant, which implies that sulphuric acid, hydrochloric acid and hydrofluoric acid were possible to start
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H. Chen et al. / Fuel 208 (2017) 149–159
Tw=90°C
Deposits on the flue duct
3
1 2
Tw=80°C
5
4
Tw=70°C
8 9
6 7
10
Tw=60°C
Tw=50°C
11 15
12 13
14
16
Tw=40°C
17
18
19 Fig. 9. Typical SEM pictures with EDS detecting micro-zones of the deposit samples.
condensing and depositing onto the probe at this temperature. It seems that the increase of the deposits on the probe was caused by the condensation of these three acids. But when the wall temperature was higher than 50 °C, the deposits on the probe were not many and mainly on the leeward side instead of covering the whole probe. In addition, the acid condensate could react with the fly ash to form salt compounds. And mainly the compounds containing alkali metals in the ash reacted with the acid condensate. Since sulphur, chlorine and fluorine but no nitrogen were found in the deposit samples and the corrosion layers, we can infer that sulphuric acid, hydrochloric acid, hydrofluoric acid and sulphurous acid might condense during the experiment. The corrosion and ash
deposition of low-temperature heating surface were closely related to the dewpoints of these acids in the flue gas. The prediction of sulphuric acid dewpoint has been extensively investigated in the last decade [12]. In this paper, the sulphuric acid dewpoint and water dewpoint of the flue gas were approximately 90.25 °C and 42.78 °C, calculated by Soviet Union Thermal Power Computation Standard (1973) [34], which is the most common method in engineering in China [35]. Less research has been performed on estimating the dewpoints of hydrochloric acid and sulphurous acid in the flue gas. According to gas-liquid equilibrium data, Kiang [36] provided the empirical correlations for calculating the dewpoints of hydrochloric acid and sulphurous acid based on the partial pressures of water vapor and hydrochloric acid vapor or SO2
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H. Chen et al. / Fuel 208 (2017) 149–159 Table 7 EDS analysis results of the deposit samples corresponding to the detected micro-zones in Fig. 9 (expressed as oxides, wt%). Deposit sample
Zone
F
Na2O
MgO
Al2O3
SiO2
SO3
Cl
K2O
CaO
TiO2
Fe2O3
Deposits on the flue duct before the flue gas cooler Deposits on the test probes Tw = 90 °C
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19
– – – – – – – 2.31 – – 11.17 – – 3.76 4.92 3.83 3.24 – –
1.79 1.09 – – – 1.63 1.46 – – 2.32 – – – – 0.88 – – – –
2.39 – – 3.22 – – – – – 0.96 – – –0.88 1.18 – – – –
24.90 48.58 2.42 25.68 3.87 12.47 13.79 2.19 1.66 17.25 5.29 4.63 5.04 8.77 13.43 8.22 1.62 3.00 8.71
70.36 61.89 41.39 48.50 104.11 73.16 77.18 8.06 4.54 57.48 9.86 9.33 71.92 19.23 31.17 32.79 2.05 5.22 29.29
– – – –
– – – – – – – 12.60 15.90 1.58 8.42 6.64 3.91 9.04 6.24 5.58 0.66 1.59 1.67
3.57 2.63 – – 1.55 1.96 1.30 – – 3.02 – – 1.25 – 1.29 1.25 – – 1.22
3.90 4.11 1.83 18.74
– – – 2.64 – – – – – – – – – – – – – – –
8.21 – 70.06 7.86 – 3.29 3.90 87.28 72.89 16.04 30.00 97.28 22.43 34.73 26.65 25.76 – 3.97 60.05
Tw = 80 °C Tw = 70 °C
Tw = 60 °C
Tw = 50 °C
Tw = 40 °C
5
Cl S F
Element content (%)
4 3 2 1 0
Inner layer (close to the wall)
Middle layer
Outer layer (close to the flue gas)
Fig. 10. Contents of sulphur, chlorine and fluorine in the deposit layers on the probe under the condition Tw = 50 °C identified by XRF.
without the consideration of the fly ash in the flue gas. According to these empirical correlations, the calculated dewpoints of hydrochloric acid and sulphurous acid were about 43.55 °C and
– – – – 3.57 12.31 3.52 1.47 13.09 10.29 11.46 64.28 45.67 8.67
5.72 3.39 1.23 1.06 9.99 30.00 7.33 6.44 16.82 21.66 29.27 45.38 33.38 8.95
43.17 °C. Besides, Xiang [37] noted that the SO2 in flue gas could only combine water condensate to form sulphurous acid when the temperature was lower than the water dewpoint of the flue gas. Since little literature has been published regarding the hydrofluoric acid dewpoint, it is hard to estimate the hydrofluoric acid dewpoint in the flue gas. When the wall temperature is lower than the dewpoint of one acid, the acid vapor in the flue gas will condense in the field near the wall, where the field temperature is below the acid dewpoint. Fig. 11 illustrates the possible behaviors of acid condensate and ash particles when the flue gas flows across the low-temperature heating surface. The acid condensate mainly has three probable behaviors: (1) depositing onto the tube wall, causing corrosion, attracting the ash particles from the flue gas and reacting with the deposited ash particles; (2) adhering to ash particles in the flue gas and making the particles sticky, reacting with the ash at the same time; (3) flowing away with the flue gas. The possible behaviors of the ash particles are: (1) absorbing the acid condensate in the flue gas; (2) depositing onto the tube wall; (3) hitting against the tube wall, then going away; (4) flowing away with the flue gas directly. The ash particles that have absorbed acid condensate and become sticky probably act in three ways: (1) depositing onto
Fig. 11. Coupling model of acid condensation and fly ash behaviors in the field near the low-temperature heating surface when the wall temperature is below the acid dewpoint of the flue gas.
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Fig. 12. Main factors affecting the dewpoint corrosion and viscous deposits of low-temperature heating surface.
Fig. 13. Acid condensate that contributes to the dewpoint corrosion and viscous deposits under different wall temperatures.
the tube wall; (2) bonding to other particles; (3) flowing away with the flue gas. As the wall temperature decreases, more and more acid condensate will form and deposit onto the tube wall, resulting in more severe dewpoint corrosion and viscous deposits. The fly ash can help to reduce the corrosion and viscous deposits by absorbing and reacting with the acid condensate. In addition, there are particles especially big particles to scour the wall, which is beneficial to remove the deposits on the wall. The above analysis can explain the basic formation processes of the corrosion and viscous ash deposits on low-temperature heating surface when the wall temperature is lower than the acid dewpoints. And according to the behaviors of acid condensate and fly ash, we can propose the main factors that affect the dewpoint corrosion and viscous deposits on low-temperature heating surface, as indicated in Fig. 12. In this paper, when the wall temperature was 80 °C and 90 °C, which were very likely below the sulphuric acid dewpoint in the flue gas, the metal surface didn’t suffer obvious acid corrosion. The corrosion of 20# and ND might be caused by oxygen or some acid condensate on the ash particles at these temperatures, and the corrosion was not severe. The corrosion of the metal surface started to deteriorate because of the sulphuric acid and hydrochloric acid condensate when the wall temperature fell to 70 °C. It seems the condensation rates of the sulphuric acid and hydrochloric acid were bigger than the rate that the fly ash absorbed and reacted with the acid condensate in the flue gas at this time. The
contents of sulphur, chlorine and fluorine began to be significant in the deposits when the wall temperature was 70 °C, which means viscous deposits could form under this temperature. But there were not many deposits on the probes until the wall temperature decreased to 50 °C. A possible explanation for this is that the viscous deposits were not enough to cover the probe on account of the particles’ hitting and scouring the probes. When the wall temperature was 40 °C that was lower than the water dewpoint, water and sulphurous acid would also condense onto the wall. The different kinds of acid condensate that formed and contributed to the dewpoint corrosion and viscous deposits under different wall temperatures are summarized in Fig. 13. In addition, the results suggest that the actual dewpoints of sulphuric acid, hydrochloric acid and hydrofluoric acid should be higher than 70 °C. Because of the differences in fired coal properties, flue gas parameters and power plants, it is difficult to compare the results of this paper to the previous study [3,28,29] that performed after the electrostatic precipitators in coal-fired power plants. But it is still worthwhile to note that the wall temperature under which ‘‘coated” deposits could form on the tubes was much lower before the precipitator than that after the precipitator. Besides, the effects of hydrochloric acid and fluoric acid on the corrosion and ash deposition of the low-temperature heating surface in coal-fired power plants didn’t draw enough attention in the previous work.
H. Chen et al. / Fuel 208 (2017) 149–159
Two points are worth of notice in the application of waste heat recovery devices for coal-fired power plants: the wall temperature at which the tube can suffer hydrochloric acid corrosion is possibly as high as 70 °C; when the wall temperature is less than 80 °C, not only sulphuric acid but also hydrochloric acid and fluoric acid can contribute to the viscous deposits on the heating surface. In addition, the corrosion of 20# and ND seems inevitable during the flue gas cooling process, but the corrosion rate can be controlled by adjusting the tube wall temperature and other methods. 5. Conclusions This study investigated the corrosion and ash deposition of lowtemperature heating surface with temperature-controlled test probes in a large-scale coal-fired power plant. Three materials were examined under six wall temperatures, and the corresponding deposit samples and metal specimens were analyzed. The results showed that the corrosion and ash deposition became worse as the wall temperature decreased. When the wall temperature dropped to 70 °C, sulphuric acid, hydrochloric acid and hydrofluoric acid started to condense onto the probe. The actual dewpoints of sulphuric acid, hydrochloric acid and hydrofluoric acid in the flue gas should be higher than 70 °C. These three acids caused the viscous deposits on the probes, but ‘‘coated” deposits didn’t form until the wall temperature was lowered to 50 °C. The acid condensate could react with the fly ash to produce salt compounds. Mainly sulphuric acid condensate and hydrochloric acid condensate exacerbated the corrosion of the metal surface, and the possible corrosion products were different under different wall temperatures. The corrosion resistances of the three tested materials were 316 L > ND > 20#. The coupling model of acid condensation and fly ash behaviors was proposed to explain the corrosion and ash deposition mechanisms of low-temperature heating surface. By absorbing and reacting with the acid condensate, the fly ash could help to reduce the corrosion caused by acid condensation. The main factors affecting the corrosion and ash deposition were also summarized and recommendations were drawn to reduce the corrosion and fouling of the heat recovery devices in coal-fired power plant. Future research on the corrosion and ash deposition of low-temperature heating surface can be conducted with long-term tests in the field or different types of heat exchange tubes such as finned tubes. Acknowledgements This work was supported by the National Natural Science Foundation of China (NO. 51606144) and the National Key Research and Development Program of China (No. 2016YFC0801904). References [1] Xu G, Xu C, Yang Y, Fang Y, Li Y, Song X. A novel flue gas waste heat recovery system for coal-fired ultra-supercritical power plants. Appl Therm Eng 2014;67:240–9. [2] Ye Y, Shen S. Characteristics of European high-efficiency coal fired units and their implications for Chinese power plant. Electr Power Constr 2011;32:54–8 (In Chinese). [3] Liang ZY, Zhao QX. Research on dew point corrosion of materials. Appl Mech Mater 2013;281:441–7. [4] Wang C, He B, Sun S, Wu Y, Yan N, Yan L, et al. Application of a low pressure economizer for waste heat recovery from the exhaust flue gas in a 600 MW power plant. Energy 2012;48:196–202. [5] Wang C, He B, Yan L, Pei X, Chen S. Thermodynamic analysis of a low-pressure economizer based waste heat recovery system for a coal-fired power plant. Energy 2014;65:80–90.
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