Water Wall Tubes’ High Temperature Corrosion Root Cause Investigation: A 300 MW Level Boiler Case

: High temperature corrosion poses a great threat to boiler water wall safe operation. To investigate the corrosion root cause, a 300 MW level boiler water wall high temperature H 2 S corrosion case was reported. The typical hydrogen sulﬁde H 2 S corrosion feature was large amounts of sulfur which could be found in the cut down sample tube corrosion layer, with a thickness of 482 µ m. In addition, huge amounts of lead (Pb) could be found in the corrosion layer, which resulted from the lead sulﬁde (PbS) deposition when the high temperature ﬂue gas condensed at the water wall tubes. Meanwhile, the sulfur in the corrosion layer was closely related to the H 2 S concentration in the water wall ambience. The related ambience test showed that the H 2 S could achieve up to 1000 ppm when the boiler was in operation, far larger than the suggested reference value of 100 ppm. Hence, the overlarge H 2 S concentration was a vital factor for the tube corrosion. To further investigate the reason why the H 2 S was kept in such high concentration in the boiler long term operation, and the reasons for the over-high sulfur content in the coal and the over-large diameter of the imaginary circle of primary air (DICPA), two factors were obtained. The peak sulfur content reached 2.5% and the suggested sulfur content was below 1%. The DICPA was so large (1580 mm) that the pulverized coal easily scoured the water wall tubes, which would boost the thinning process of the tubes. To relieve the high temperature corrosion, improve the coal qualities, decrease the DICPA, adjust the operation diameter and adopt a coating technology four measures were suggested.


Introduction
China has proposed the "Double Carbon Plan", i.e., China would reach the CO 2 emission peak before the year 2030 and carbon neutrality before the year 2060 [1].To this end, the coal-fired power plants have to participate in kurtosis modulation running to release more electrical load for the new energy resources power plants, such as solar energy plants, wind power plants, hydropower stations, and so on [2].Hence, large amounts of coal-fired boilers are forced to take as low as possible a load operation.For example, a 20-30% boiler rated load is a common operation condition for a boiler.Not only that, but the boiler, meanwhile, must achieve NOx emissions lower than 50 mg/m 3 [3].To achieve this goal, the boiler has to conduct low oxygen operations in the main combustion area to reduce the NOx emission, which makes the water wall tube suffer substantial high temperature corrosion.A direct phenomenon can be seen in the water wall tube thickness thinning, increasing the tube burst rate.In China, no matter how large the boiler unit capacity, 300 MW [4], 600 MW [5] and 1000 MW [6] level boilers all have the tendency towards high temperature corrosion.
Due to the complex three-dimensional flow coupled with combustion in the real furnace, many factors can contribute to the high temperature corrosion.The steel material is a key factor.Zhao et al. [7] compared the two T23 and T24 steels corrosion rates in simulated furnace atmospheres.Nimmervoll et al. [8] tested and acquired five austenitic stainless steels with corrosion resistance ability under HCl and H 2 S ambience.Bai et al. [9] studied the alloy AlFe2.5NiMoNbCr'shigh temperature chloride corrosion behavior.These past lab-scale studies supplied plenty of data on the fundamental corrosion rate of multiple boiler steels.However, compared to the furnace practical corrosion rate, some of them may produce a large error when used to guide the boiler operation, because the lab scale simulation corrosion environment is substantially different from that in the real boiler furnace.Hence, directly investigating the eroded tube can produce more practical information.The general methodology is cutting down the tubes [10,11] where corrosion has severely occurred and analyzing the sample tubes' outer layer compositions to judge the possible corrosion mechanism.For example, Yu et al. [12], Wang et al. [13] and Xiong et al. [14], respectively, analyzed a 300 MW level boiler water wall tube corrosion mechanism in a section of cut down eroded tube.The same issue they reported was the H 2 S corrosion type for the existence of sulfur under the scaling layer covering the water wall tube.On the other hand, for the field corrosion study, besides the steel material, reducing the ambience adjacent to the water wall in the boiler operation is also an important factor.Bukowski et al. [15] tested the O 2 and CO concentrations in a BP-1150 boiler to evaluate the corrosion rate.Hardy et al. [16] developed a CFD model to predict the O 2 and CO correlations in the vicinity of the front boiler wall.These works in the literature attempted to predict the high temperature corrosion rate by evaluating the H 2 S or CO concentration.Note that the CO is not the direct corrosive gas, despite it being closely related to H 2 S content.If the mole ratio of CO/(CO + CO 2 ) increases from 8% to 24%, the concentration of the gas phase H 2 S will increase from 0.02% to 0.07% [12].Hence, directly measuring the H 2 S concentration is more meaningful for evaluating the corrosion.However, H 2 S data on the field boiler are rare, especially rare for the H 2 S and CO synchronous measurement data on the 300 MW level boiler.Only Shirai et al. [17] and Tsuji et al. [18] reported the H 2 S concentrations, but this was conducted in a 750 KW level test rig rather than a field boiler.Hence, it is necessary to measure the reducing gas concentration directly on a field boiler when investigating the corrosion mechanism.
Based on this, this paper selected a severely high temperature corrosion 300 MW boiler as the object and investigated the root cause for the corrosion from the characterization analysis of a cut down sample tube.Meanwhile, we also synchronously measured the reducing ambience, including H 2 S, CO, O 2 and H 2 adjacent to the water wall, and the H 2 S and CO, H 2 S and H 2 correlations were proposed, which can be used to guide the boiler operation adjustment.Finally, four measures were proposed to relieve the high temperature corrosion.

Boiler Basic Design Parameter
The boiler was manufactured by the Shanghai Boiler Factory, SG1025/18.3-M833.The original design capacity was 300 MW.Then, it was reconstructed to 330 MW afterward.It is a subcritical, single drum, intermediate reheating, controlled circulation, dry ash extraction and Π shape pulverized coal boiler.The furnace width is 11.97 m, the depth is 11.76 m, the width to depth ratio is 1.02:1, the elevation of the furnace top heat surface tube is 58.4 m, and the elevation of the boiler drum centerline is 59.32 m.The water wall material is 20G (Chinese standard, GB/5310), and the ribbed tube Φ45 * 6 mm.Alongside the element iron, the major composition elements are C, Si, Mn, P and S for the material 20G.The specific values can be seen in Table 1.The daily fuel is lean coal, with a volatile (dry ash free basis, daf for abbreviation, similarly hereinafter) around 16% and an average total sulfur 1.76% (as received basis).The air dry basis ash (A ad ) is 32.38% and the dry basis fixed carbon (C d ) is 55.91%.The as received basis lower calorific value (Q net,ar ) is 20.74 MJ/kg.The typical coal quality can be seen in Table 2.

Corrosion Status
During the boiler maintenance period, after the boiler operation was stopped, the larger water wall areas were found to be severely corroded among the four walls.The thinnest tube thickness is only 3 mm, with a 50% thickness reduction rate.Generally, the water wall tube is required to be replaced by the new tube when the thickness reduction rate exceeds 30%.Hence, large areas of the water wall tubes were cut down and renewed, as Figure 1a-c shows.As for the corrosion details, large corrosion products covered the tubes, presenting a multilayer and colorful structure, as seen in Figure 1d,e.Part of the iron substrate was corroded and fell from the tube.The daily fuel is lean coal, with a volatile (dry ash free basis, daf for abbreviation, similarly hereinafter) around 16% and an average total sulfur 1.76% (as received basis).The air dry basis ash (Aad) is 32.38% and the dry basis fixed carbon (Cd) is 55.91%.The as received basis lower calorific value (Qnet,ar) is 20.74 MJ/kg.The typical coal quality can be seen in Table 2.

Corrosion Status
During the boiler maintenance period, after the boiler operation was stopped, the larger water wall areas were found to be severely corroded among the four walls.The thinnest tube thickness is only 3 mm, with a 50% thickness reduction rate.Generally, the water wall tube is required to be replaced by the new tube when the thickness reduction rate exceeds 30%.Hence, large areas of the water wall tubes were cut down and renewed, as Figure 1a-c shows.As for the corrosion details, large corrosion products covered the tubes, presenting a multilayer and colorful structure, as seen in Figure 1d,e.Part of the iron substrate was corroded and fell from the tube.After careful observation of the inside furnace, when the boiler was stopped for maintenance, the corrosion morphology can be sorted into three types, as in the shadow area shown in Figure 2. The primary air jetted from the burners at four furnace corners formed an anticlockwise tangential flow in the furnace.For each wall (front, rear, left and right wall), near the corner adjacent to the upstream burner, the tubes are normal and uncorroded.Along with the downstream of the primary air flow, corrosion occurred on the right side of the tubes, namely type 1.As the primary air flow moved on, followed by the type 1 corrosion area, the corrosion occurred at the middle area of tubes, namely type 2.Then, continuing moving, the corrosion area occurred at both the left and right sides of After careful observation of the inside furnace, when the boiler was stopped for maintenance, the corrosion morphology can be sorted into three types, as in the shadow area shown in Figure 2. The primary air jetted from the burners at four furnace corners formed an anticlockwise tangential flow in the furnace.For each wall (front, rear, left and right wall), near the corner adjacent to the upstream burner, the tubes are normal and uncorroded.Along with the downstream of the primary air flow, corrosion occurred on the right side of the tubes, namely type 1.As the primary air flow moved on, followed by the type 1 corrosion area, the corrosion occurred at the middle area of tubes, namely type 2.Then, continuing moving, the corrosion area occurred at both the left and right sides of the tubes, namely type 3.The corrosion location in each tube from type 1 transition to type 3 implied the change of fluid state outside the water wall tubes.Along with the direction from the upstream flow to downstream flow, the fluid state had changed from laminar to turbulent.This can explain how corrosion occurred in both two sides of the tubes (type 3).

The Water Wall Tubes' Ambience Gas Sampling Methods Description
The traditional water wall tubes ambience gas sampling method is to weld an 8 mm steel tube to the membrane between the two water wall tubes, as shown in Figure 3a.The issue for this gas sampling method is that the 8 mm sampling tube no longer works once the tube is blocked by the slag.To ensure the H2S can be continually measured, a new gas sampling vent method was developed, i.e., two water wall tubes were retrofitted to ensure that the flue gas sampling tube diameter is large enough to prevent the slag blocking the sample tube, or the sample tube can be reopened by cleaning the slag.Hence, a 70 mm large diameter sampling tube was mounted on the water wall with a flange connected at the end outside, as shown in Figure 3b.The reducing ambience test diagram can be seen in Figure 3c.The CO, H2, CO2 and O2 were detected by coal gas analyzer (Gasboard 3100p), while the H2S was measured by Sulfur sentry analyzer, Event Eng corporation.

The Water Wall Tubes' Ambience Gas Sampling Methods Description
The traditional water wall tubes ambience gas sampling method is to weld an 8 mm steel tube to the membrane between the two water wall tubes, as shown in Figure 3a.The issue for this gas sampling method is that the 8 mm sampling tube no longer works once the tube is blocked by the slag.To ensure the H 2 S can be continually measured, a new gas sampling vent method was developed, i.e., two water wall tubes were retrofitted to ensure that the flue gas sampling tube diameter is large enough to prevent the slag blocking the sample tube, or the sample tube can be reopened by cleaning the slag.Hence, a 70 mm large diameter sampling tube was mounted on the water wall with a flange connected at the end outside, as shown in Figure 3b.The reducing ambience test diagram can be seen in Figure 3c.The CO, H 2 , CO 2 and O 2 were detected by coal gas analyzer (Gasboard 3100p), while the H 2 S was measured by Sulfur sentry analyzer, Event Eng corporation.

The Water Wall Tubes' Ambience Gas Sampling Methods Description
The traditional water wall tubes ambience gas sampling method is to weld an 8 mm steel tube to the membrane between the two water wall tubes, as shown in Figure 3a.The issue for this gas sampling method is that the 8 mm sampling tube no longer works once the tube is blocked by the slag.To ensure the H2S can be continually measured, a new gas sampling vent method was developed, i.e., two water wall tubes were retrofitted to ensure that the flue gas sampling tube diameter is large enough to prevent the slag blocking the sample tube, or the sample tube can be reopened by cleaning the slag.Hence, a 70 mm large diameter sampling tube was mounted on the water wall with a flange connected at the end outside, as shown in Figure 3b.The reducing ambience test diagram can be seen in Figure 3c.The CO, H2, CO2 and O2 were detected by coal gas analyzer (Gasboard 3100p), while the H2S was measured by Sulfur sentry analyzer, Event Eng corporation.Energies 2023, 16, 1767 5 of 13

Corroded Tube Sampling and Characterization
The boiler water wall tubes had only partly adopted coating technology due to the cost factor.To analyze the possible corrosion products, two sample tubes were cut down.One was processed with coating technology and the other was not.We cut the sample tubes into small pieces, used the epoxy resin to encapsulate these small pieces and conducted the line scan test.The micromorphology of sampling tubes was characterized by means of a JSM 7000F field emission scanning electron microscope (SEM) and the element distribution was analyzed, combining the energy dispersive X-ray spectrometer (EDS).

Water Wall Tube Corrosion Category Evaluation: H 2 S Corrosion
Generally, boiler high temperature corrosion caused by sulfur can be divided into two categories of H 2 S corrosion and sulfate corrosion [19].To further ensure the specific corrosion category, the sampling tubes element line scan test was conducted.Figure 4 displayed the element distribution of the 'no coating' processed tube.It was seen that adjacent to the Fe substrate was the corrosion layer, with a thickness of 482 µm.An apparent characteristic is the gradual decrease in iron content and the gradual increase of sulfur along the horizontal axis distance, as shown in Figure 4a.The existence of sulfur is a typical feature of H 2 S corrosion.Meanwhile, the element lead (Pb) is also largely found in the corrosion layer.Along the horizontal axis direction, the larger the distance, the more the lead (Pb) content, as shown in Figure 4b.The lead (Pb) layer resulted from the PbS deposition during the coal combustion process [13].

Corroded Tube Sampling and Characterization
The boiler water wall tubes had only partly adopted coating technology due to the cost factor.To analyze the possible corrosion products, two sample tubes were cut down.One was processed with coating technology and the other was not.We cut the sample tubes into small pieces, used the epoxy resin to encapsulate these small pieces and conducted the line scan test.The micromorphology of sampling tubes was characterized by means of a JSM 7000F field emission scanning electron microscope (SEM) and the element distribution was analyzed, combining the energy dispersive X-ray spectrometer (EDS).

Water Wall Tube Corrosion Category Evaluation: H2S Corrosion
Generally, boiler high temperature corrosion caused by sulfur can be divided into two categories of H2S corrosion and sulfate corrosion [19].To further ensure the specific corrosion category, the sampling tubes element line scan test was conducted.Figure 4 displayed the element distribution of the 'no coating' processed tube.It was seen that adjacent to the Fe substrate was the corrosion layer, with a thickness of 482 μm.An apparent characteristic is the gradual decrease in iron content and the gradual increase of sulfur along the horizontal axis distance, as shown in Figure 4a.The existence of sulfur is a typical feature of H2S corrosion.Meanwhile, the element lead (Pb) is also largely found in the corrosion layer.Along the horizontal axis direction, the larger the distance, the more the lead (Pb) content, as shown in Figure 4b.The lead (Pb) layer resulted from the PbS deposition during the coal combustion process [13].Figure 5 displayed the sample tube with the coating technology processed.Differently from Figure 4, the Cr and Ni were largely found while element Pb was not found.The elements Cr and Ni were mainly from coating material elements.The coating thickness was 260 μm.Meanwhile, the amount of sulfur was largely found in the coating layer but was rare in the substrate, showing that the existence of coating effectively prevents the sulfur from permeating into the substrate.With the aid of the coating layer, the sulfurcontaining layer thickness was much reduced compared to that with no coating layer.Figure 5 displayed the sample tube with the coating technology processed.Differently from Figure 4, the Cr and Ni were largely found while element Pb was not found.The elements Cr and Ni were mainly from coating material elements.The coating thickness was 260 µm.Meanwhile, the amount of sulfur was largely found in the coating layer but was rare in the substrate, showing that the existence of coating effectively prevents the sulfur from permeating into the substrate.With the aid of the coating layer, the sulfur-containing layer thickness was much reduced compared to that with no coating layer.Figure 6a displayed the SEM morphology of the coating processed tube.There were many round balls with a diameter around 25 μm, as label 1 shows.The EDS results in Figure 6b showed that these round balls' element compositions were Ti, V, Al, etc., and their metallic oxides.Label 2 elements were mainly Fe and O, which were the results of iron substrate oxidation.The major label 3 element was carbon, which was from the unburnt fly ash.From the above characteristics analysis, it can be certified that the water wall tubes corrosion was caused by H2S produced by the coal lean oxygen combustion.To further explore the corrosion rate, it is necessary to evaluate the H2S source and concentration value.

The Source of H2S and the Water Wall H2S Concentration
The formation H2S in the boiler was attributed to the coal combustion in an oxygen deficit ambience.Hence, the content in coal was, naturally, closely related with the H2S concentration.Figure 7 listed the coal sulfur trend in recent two years.It can be seen that the sulfur was obviously larger in the first three quarters of the year 2021 compared to the same period of 2020.The average sulfur amount was 1.8% in the first three quarters of the year 2021, and the peak sulfur value reached 2.5%, which was the typical high sulfur Figure 6a displayed the SEM morphology of the coating processed tube.There were many round balls with a diameter around 25 µm, as label 1 shows.The EDS results in Figure 6b showed that these round balls' element compositions were Ti, V, Al, etc., and their metallic oxides.Label 2 elements were mainly Fe and O, which were the results of iron substrate oxidation.The major label 3 element was carbon, which was from the unburnt fly ash. Figure 6a displayed the SEM morphology of the coating processed tube.There were many round balls with a diameter around 25 μm, as label 1 shows.The EDS results in Figure 6b showed that these round balls' element compositions were Ti, V, Al, etc., and their metallic oxides.Label 2 elements were mainly Fe and O, which were the results of iron substrate oxidation.The major label 3 element was carbon, which was from the unburnt fly ash.From the above characteristics analysis, it can be certified that the water wall tubes corrosion was caused by H2S produced by the coal lean oxygen combustion.To further explore the corrosion rate, it is necessary to evaluate the H2S source and concentration value.

The Source of H2S and the Water Wall H2S Concentration
The formation of H2S in the boiler was attributed to the coal combustion in an oxygen deficit ambience.Hence, the sulfur content in coal was, naturally, closely related with the H2S concentration.Figure 7 listed the coal sulfur trend in recent two years.It can be seen that the sulfur was obviously larger in the first three quarters of the year 2021 compared to the same period of 2020.The average sulfur amount was 1.8% in the first three quarters of the year 2021, and the peak sulfur value reached 2.5%, which was the typical high sulfur From the above characteristics analysis, it can be certified that the water wall tubes corrosion was caused by H 2 S produced by the coal lean oxygen combustion.To further explore the corrosion rate, it is necessary to evaluate the H 2 S source and concentration value.

The Source of H 2 S and the Water Wall H 2 S Concentration
The formation of H 2 S in the boiler was attributed to the coal combustion in an oxygen deficit ambience.Hence, the sulfur content in coal was, naturally, closely related with the H 2 S concentration.Figure 7 listed the coal sulfur trend in recent two years.It can be seen that the sulfur was obviously larger in the first three quarters of the year 2021 compared to the same period of 2020.The average sulfur amount was 1.8% in the first three quarters of the year 2021, and the peak sulfur value reached 2.5%, which was the typical high sulfur coal.The sulfur started to decline until October.Even so, the average sulfur was still as high as 1.1%.It was suggested to control the sulfur in coal to below 1% by coal blending technology if possible [14].The high sulfur coal was detrimental to the control of H 2 S concentration.
Energies 2023, 16, x FOR PEER REVIEW 7 of 13 coal.The sulfur started to decline until October.Even so, the average sulfur was still as high as 1.1%.It was suggested to control the sulfur in coal to below 1% by coal blending technology if possible [14].The high sulfur coal was detrimental to the control of H2S concentration.To further evaluate the reducing ambience near the water wall tubes, the H2S, CO, H2 and O2 were synchronously tested after the boiler restarted operations when the maintenance was over.Figure 8a presented the test results in the boiler main combustion area.It can be seen that the H2S and CO kept a gradual increase trend.The two parameters kept a good synchronism characteristic, i.e., increasing or decreasing concurrently.The peak value of CO reached 12%, while that of H2S reached 1000 ppm.H2 presented the same tendency with CO.The H2 mainly came from the bond break between the organic carbon hydrogen functional groups.Under the ultra-low NOx operation mode, the main combustion area had severely insufficient oxygen.Hence, this area was substantially viewed as a gasification process.Due to the high temperature (1400 °C ) in this area, the hydrocarbon molecules are few.The major reducing ambience gases were CO and H2.The increase of H2 was conducive to the formation of H2S.The reactions were as follows [20,21]  To further evaluate the reducing ambience near the water wall tubes, the H 2 S, CO, H 2 and O 2 were synchronously tested after the boiler restarted operations when the maintenance was over.Figure 8a presented the test results in the boiler main combustion area.It can be seen that the H 2 S and CO kept a gradual increase trend.The two parameters kept a good synchronism characteristic, i.e., increasing or decreasing concurrently.The peak value of CO reached 12%, while that of H 2 S reached 1000 ppm.

Nov
coal.The sulfur started to decline until October.Even so, the average sulfur was still as high as 1.1%.It was suggested to control the sulfur in coal to below 1% by coal blending technology if possible [14].The high sulfur coal was detrimental to the control of H2S concentration.To further evaluate the reducing ambience near the water wall tubes, the H2S, CO, H2 and O2 were synchronously tested after the boiler restarted operations when the maintenance was over.Figure 8a presented the test results in the boiler main combustion area.It can be seen that the H2S and CO kept a gradual increase trend.The two parameters kept a good synchronism characteristic, i.e., increasing or decreasing concurrently.The peak value of CO reached 12%, while that of H2S reached 1000 ppm.H2 presented the same tendency with CO.The H2 mainly came from the bond break between the organic carbon hydrogen functional groups.Under the ultra-low NOx operation mode, the main combustion area had severely insufficient oxygen.Hence, this area was substantially viewed as a gasification process.Due to the high temperature (1400 °C ) in this area, the hydrocarbon molecules are few.The major reducing ambience gases were CO and H2.The increase of H2 was conducive to the formation of H2S.The reactions were as follows [20,21]: H 2 presented the same tendency with CO.The H 2 mainly came from the bond break between the organic carbon hydrogen functional groups.Under the ultra-low NOx operation mode, the main combustion area had severely insufficient oxygen.Hence, this area was substantially viewed as a gasification process.Due to the high temperature (1400 • C) in this area, the hydrocarbon molecules are few.The major reducing ambience gases were CO and H 2 .The increase of H 2 was conducive to the formation of H 2 S. The reactions were as follows [20,21]: The source of CO had two paths.One was from the coal internal oxygen, such as an ether bond.The other was from the char reacting with the external oxygen.
The presence of CO also benefitted the formation of H 2 S by the reaction: The H 2 S and CO curves were fitted, respectively, and the mutual relation can be obtained as the Figure 8b black line shown.Similarly, the H 2 S and H 2 relationship can be obtained (the blue line).Fitting formulas were proposed as below, with the Adj.R-Square values of both correlations larger than 0.99.

The Diameter of Imaginary Circle of Primary Air (DICPA) Analysis
For the tangential combustion boiler, the DICPA is a vital parameter for the boiler design.In general, the DICPA is from 600 to 1000 mm, depending on the coal category.A recommended formular is below [22]: where d is the DICPA, mm; k is an empirical coefficient, ranging from 0.05 to 0.12; a, b is the length and width of the furnace, respectively, in mm.According to this formula, even taking the upper limit value of k, the largest DICPA should be 1424 mm.That means the DICPA parameter is required to be no more than 1424 mm when designing the boiler.However, in practice, the DICPA is as large as 1580 mm.When the boiler was in operation, the real tangential circle diameter was 5 to 10 times the DICPA [22].Hence, the primary air flows at four corners of the boiler are apt to deflect to the downstream direction with the action of upstream current.Then, the primary air would erode the tubes in the downstream area of water walls, as shown in Figure 9.The shadow area represents the severely eroded water wall tube area due to the primary air deflection.Hence, the DICPA is too large for this boiler and results in the primary air flow eroding the water wall.
The slag adhering to the water wall tubes was a strong evidence for the overlarge DICPA.Figure 10 displayed the slag on the rear water wall during the boiler maintenance period.It can be seen that nearly the whole rear water wall was covered by the slag.The two red line areas were the traces of slag falling from the rear wall when the furnace temperature decreased during the boiler stop period.The length of one falling slag section was around 3 m.When the hot pulverized coal encountered the relatively cold water wall, the sticky coal particles in the primary air flow were condensed and adhered to the water wall.If the DICPA was smaller, the coal particles would have fewer possibilities to erode the water wall.The slag adhering to the water wall tubes was a strong evidence for the DICPA.Figure 10 displayed the slag on the rear water wall during the boiler ma period.It can be seen that nearly the whole rear water wall was covered by the two red line areas were the traces of slag falling from the rear wall when the fur perature decreased during the boiler stop period.The length of one falling sl was around 3 m.When the hot pulverized coal encountered the relatively cold w the sticky coal particles in the primary air flow were condensed and adhered to wall.If the DICPA was smaller, the coal particles would have fewer possibilitie the water wall.The slag adhering to the water wall tubes was a strong evidence for the o DICPA.Figure 10 displayed the slag on the rear water wall during the boiler main period.It can be seen that nearly the whole rear water wall was covered by the s two red line areas were the traces of slag falling from the rear wall when the furn perature decreased during the boiler stop period.The length of one falling slag was around 3 m.When the hot pulverized coal encountered the relatively cold wa the sticky coal particles in the primary air flow were condensed and adhered to th wall.If the DICPA was smaller, the coal particles would have fewer possibilities the water wall.

Water Wall High Temperature Corrosion Root Cause Analysis
According to the above discussion, the high temperature corrosion root c cluded the overly high sulfur content in coal and overlarge DICPA two factors.T high sulfur coal incurred high H2S concentration near the water wall tubes when t was in low NOx operation mode.The corrosion rate was exponential to the H2S tration [23].The higher the H2S concentration, the faster the tube corrosion rate.tion, the overlarge DICPA resulted in the pulverized coal eroding the water wall the downstream area.The fusion coal ash would be slagged on the water wall and increased the tube surface temperature, which boosted the corrosion to a deepen As for the specific H2S corrosion mechanism, it can be seen in Figure 11.Specific active sulfur atom came from the pyrite in coal.When heating, the pyrite release

Water Wall High Temperature Corrosion Root Cause Analysis
According to the above discussion, the high temperature corrosion root cause included the overly high sulfur content in coal and overlarge DICPA two factors.The over-high sulfur coal incurred high H 2 S concentration near the water wall tubes when the boiler was in low NOx operation mode.The corrosion rate was exponential to the H 2 S concentration [23].The higher the H 2 S concentration, the faster the tube corrosion rate.In addition, the overlarge DICPA resulted in the pulverized coal eroding the water wall tubes in the downstream area.The fusion coal ash would be slagged on the water wall and further increased the tube surface temperature, which boosted the corrosion to a deepen extent.As for the specific H 2 S corrosion mechanism, it can be seen in Figure 11.Specifically, the active sulfur atom came from the pyrite in coal.When heating, the pyrite releases sulfur atoms.Further, the sulfur atoms reacted with hydrogen to form H 2 S. The active sulfur atoms and hydrogen sulfide were two strong corrosive media, which could directly reacted with the substrate iron and the iron oxide layer.In normal conditions, the iron oxidation was a protective layer.According to the metal high temperature oxidation theory [24], a temperature of 570 • C was a critical point.Above this value, the oxide layer was consisted of FeO, Fe 3 O 4 and Fe 2 O 3 with a layered structure.Under this value, the oxide layer was only consisted of Fe 3 O 4 and Fe 2 O 3 .Considering that the boiler main stream was subcritical, the water wall temperature must be lower than 570 • C. Hence, the oxide layer was composed of Fe 3 O 4 and Fe 2 O 3 .When the oxide layer was converted into ferrous sulfide, the expansibility differs hugely between the iron oxide and ferrous sulfide layer.When the boiler undergone rapid increase or decrease in load, the water wall temperature varied considerably.With the aid of the thermal stress action, the ferrous sulfide layer had the tendency to fall from the substrate.Furthermore, the high temperature coal particles kept on scouring and deposited on the water wall.When the particles' weight accumulated to some extent, the corrosion layer, along with the coal particles, fell from the iron substrate.Then, the fresh iron substrate was exposed to the high temperature flue gas and the corrosion circle was restarted.The tubes were thinned after long period operation.
atoms.Further, the sulfur atoms reacted with hydrogen to form H2S. The active sulfur atoms and hydrogen sulfide were two strong corrosive media, which could directly reacted with the substrate iron and the iron oxide layer.In normal conditions, the iron oxidation was a protective layer.According to the metal high temperature oxidation theory [24], a temperature of 570 °C was a critical point.Above this value, the oxide layer was consisted of FeO, Fe3O4 and Fe2O3 with a layered structure.Under this value, the oxide layer was only consisted of Fe3O4 and Fe2O3.Considering that the boiler main stream was subcritical, the water wall temperature must be lower than 570 °C .Hence, the oxide layer was composed of Fe3O4 and Fe2O3.When the oxide layer was converted into ferrous sulfide, the expansibility differs hugely between the iron oxide and ferrous sulfide layer.When the boiler undergone rapid increase or decrease in load, the water wall temperature varied considerably.With the aid of the thermal stress action, the ferrous sulfide layer had the tendency to fall from the substrate.Furthermore, the high temperature coal particles kept on scouring and deposited on the water wall.When the particles' weight accumulated to some extent, the corrosion layer, along with the coal particles, fell from the iron substrate.Then, the fresh iron substrate was exposed to the high temperature flue gas and the corrosion circle was restarted.The tubes were thinned after long period operation.

Practical Significance: High Temperature Corrosion Prevention
As for the lean coal-fired boiler, the water wall high temperature corrosion phenomenon is more severe than that in a bituminous coal-fired boiler.Hence, measures must be

Practical Significance: High Temperature Corrosion Prevention
As for the lean coal-fired boiler, the water wall high temperature corrosion phenomenon is more severe than that in a bituminous coal-fired boiler.Hence, measures must be taken to relieve the corrosion rate.The most important thing is to reduce the sulfur

Figure 1 .
Figure 1.The water wall inspection during the boiler maintenance period.(a) The cut down area in water wall; (b) The repaired area in water wall; (c) The cut down corrosion water wall tubes (d) The enlargement of the corrosion tubes, I; (e) The enlargement of corrosion tubes, II.

Figure 1 .
Figure 1.The water wall inspection during the boiler maintenance period.(a) The cut down area in water wall; (b) The repaired area in water wall; (c) The cut down corrosion water wall tubes (d) The enlargement of the corrosion tubes, I; (e) The enlargement of corrosion tubes, II.

Energies 2023 ,Figure 2 .
Figure 2. Schematic diagram of three types of corrosion morphology.

Figure 3 .
Figure 3.The sampling tubes description and reducing ambience measurement diagram.(a) The traditional sampling tube; (b) New sampling tube in this test; (c) Reducing ambience measurement diagram.

Figure 2 .
Figure 2. Schematic diagram of three types of corrosion morphology.

Energies 2023 ,Figure 2 .
Figure 2. Schematic diagram of three types of corrosion morphology.

Figure 3 .
Figure 3.The sampling tubes description and reducing ambience measurement diagram.(a) The traditional sampling tube; (b) New sampling tube in this test; (c) Reducing ambience measurement diagram.

Figure 3 .
Figure 3.The sampling tubes description and reducing ambience measurement diagram.(a) The traditional sampling tube; (b) New sampling tube in this test; (c) Reducing ambience measurement diagram.

Figure 4 .
Figure 4.The line scan results of the no coating processed tube.(a) Part I, element C, O, Al, Si, S and Fe; (b) Part II, element Ca, Fe, Zn and Pb

Figure 4 .
Figure 4.The line scan results of the no coating processed tube.(a) Part I, element C, O, Al, Si, S and Fe; (b) Part II, element Ca, Fe, Zn and Pb.

Figure 5 .
Figure 5.The line scan results of the coating processed tube (the data were smoothed by the Savitzky-Golay method, 50 points).

Figure 6 .
Figure 6.The SEM morphology and EDS analysis of the coating processed tube.(a) Morphology of the cut down tube; (b)The EDS test results

Figure 5 .
Figure 5.The line scan results of the coating processed tube (the data were smoothed by the Savitzky-Golay method, 50 points).

Figure 5 .
Figure 5.The line scan results of the coating processed tube (the data were smoothed by the Savitzky-Golay method, 50 points).

Figure 6 .
Figure 6.The SEM morphology and EDS analysis of the coating processed tube.(a) Morphology of the cut down tube; (b)The EDS test results

Figure 6 .
Figure 6.The SEM morphology and EDS analysis of the coating processed tube.(a) Morphology of the cut down tube; (b)The EDS test results.

Figure 7 .
Figure 7.The coal sulfur comparison between the years 2020 and 2021 (The boiler was stopped for maintenance in April, no sulfur data).(a) The year 2020; (b) The year 2021

Figure 8 .
Figure 8.The ambience near the water wall tube test in rear wall.(a) Flue gas species: H2S, CO, H2 and O2; (b) The H2S and CO, H2S and H2 fitting correlation curves based on (a).

Figure 7 .
Figure 7.The coal sulfur comparison between the years 2020 and 2021 (The boiler was stopped for maintenance in April, no sulfur data).(a) The year 2020; (b) The year 2021.

Figure 7 .
Figure 7.The coal sulfur comparison between the years 2020 and 2021 (The boiler was stopped for maintenance in April, no sulfur data).(a) The year 2020; (b) The year 2021

Figure 8 .
Figure 8.The ambience near the water wall tube test in rear wall.(a) Flue gas species: H2S, CO, H2 and O2; (b) The H2S and CO, H2S and H2 fitting correlation curves based on (a).

Figure 8 .
Figure 8.The ambience near the water wall tube test in rear wall.(a) Flue gas species: H 2 S, CO, H 2 and O 2 ; (b) The H 2 S and CO, H 2 S and H 2 fitting correlation curves based on (a).

Figure 9 .
Figure 9.The diameter of imaginary circle of primary air schematic diagram.

Figure 10 .
Figure 10.The slag on the rear water wall.

3. 4 .
Water Wall High Temperature Corrosion Root Cause Analysis According to the above discussion, the high temperature corrosion root cluded the overly high sulfur content in coal and overlarge DICPA two factors.

Figure 9 .Figure 9 .
Figure 9.The diameter of imaginary circle of primary air schematic diagram.

Figure 10 .
Figure 10.The slag on the rear water wall.

Figure 10 .
Figure 10.The slag on the rear water wall.

Table 1 .
The element composition of 20G.

Table 2 .
The typical coal quality during the boiler operation.

Table 2 .
The typical coal quality during the boiler operation.