Oxid Met DOI 10.1007/s11085-017-9767-8 ORIGINAL PAPER
Fireside Corrosion of Ni Base Self-Fluxing Alloy Coatings in WtE Plant: Effect of Flue-Gas and Metal Temperature J. M. Brossard1 • F. Maad1 • J. Chartier1 R. Chavrot1 • Y. Kawahara2
•
Received: 18 January 2017 / Revised: 28 February 2017 Springer Science+Business Media New York 2017
Abstract Increase in the efficiency of energy recovery facilities is one of the challenges facing waste-to-energy (WtE) operators in the EU. To achieve this target, one option is optimization of the water/steam cycle to increase electrical efficiency. Nevertheless, increase in steam temperature in heat exchanger tubes results in increased fireside corrosion risks, particularly in superheater tubes, where severe corrosion loss of materials, frequent shutdowns for repairs and high operational costs occur. In this study, two heat-treated self-fluxing Cr–Mo–Si–B–Ni base alloys containing, respectively, 15.6 and 16.4 wt.% Cr, were applied to low- and hightemperature pendant superheater tubes (LTSH and HTSH). Detailed analyses for flue-gas and metal temperatures in service at different locations of the pendant tubes (around 850 and 400 C, respectively) and analyses of deposits collected on both tubes (Na, K, Ca, Si, Zn, Pb, Cl, S) were conducted. Both coatings exhibited a corrosion rate close to ones reported for Inconel 625 in similar conditions. Localized corrosion was found and associated with molten phase-assisted corrosion mechanism damaging Si-rich protective layer. Correlations between corrosion rate and & J. M. Brossard
[email protected] F. Maad
[email protected] J. Chartier
[email protected] R. Chavrot
[email protected] Y. Kawahara
[email protected] 1
Veolia Recherche et Innovation, 291 Avenue Dreyfous Ducas, 78520 Limay, France
2
Dai-Ichi High Frequency Co.,Ltd., 1-6-2, Nihonbashibakuro-cho, Chuo-Ku, Tokyo 103-0002, Japan
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%Cr in the coating, Tflue-gas, Tmetal and amount of molten phase in deposit are presented. Keywords Fireside corrosion CFD analysis Waste-to-energy Corrosionresistant coating Ni base self-fluxing alloy
Introduction Recently the EU has encouraged the waste-to-energy industries to play an essential role in sustainable energy by increasing energy efficiency of WtE facilities [1] that are classified as energy recovery facilities. One way to increase electrical efficiency of boiler consists to optimize the water/steam process by increasing outlet steam pressure and temperature, commonly around 400 C/60 bars [2]. This strategy is also instigated by the existing experiences in biomass and coal power plants where high steam cycle had been reached (540 C/110bar and 600 C/250 bar, respectively) [3, 4]. In these solid fuel combustion applications, fireside corrosion issues are reported since several decades [5]. Many laboratory studies on corrosion mechanisms under simulated environment and performances of wide range of alloys and coatings [6, 7] had been published. Such literatures point out that fireside corrosion mechanism of heat exchanger tubes is a competition or a combination of different hightemperature corrosion mechanisms relatively well described individually: (1) (2) (3) (4)
Corrosion by gaseous phase including ‘‘active oxidation’’ by chlorine (HCl, Cl2) [8], Condensation of alkali and heavy metals chloride and/or sulfates [9], Deposit-induced corrosion and sulfidation of condensed chlorides, Molten salts eutectics induce dissolution of protective oxide scales and metallic tubes (‘‘fluxage’’) [10].
This complex degradation mechanism requires particular attention to the effect of the different parameters governing each corrosion mechanism to evaluate their relative contribution to fireside corrosion mechanism and kinetics. Among these parameters, we can mention: • •
•
Local Tflue-gas/Tsteam directly linked to boiler design and type of heat exchangers (waterwall, superheaters, evaporators, etc.) [4, 11] Deposit phase composition and properties highly depend on solid fuel composition (ash content, amount of free alkali or heavy metals) and local Tflue-gas - Tsteam at each heat exchanger location [12, 13] Gas phase composition related to solid fuel properties (moisture, Cl, S) and combustion conditions (O2 content and variation) [14]
Considering these parameters allows to emphasize why WtE facilities are subject to more severe corrosion than coal or biomass power plants and why tube lifetime remains one of the main issues to increase WtE boiler efficiency. Then, even if
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corrosion mechanism is well understood in laboratory, it is often more difficult to establish an accurate feedback from on-site experiment considering the number of parameters to be recorded to analyze rigorously the results. This paper aims at presenting an industrial feedback on self-fluxing alloy-coated superheater tube in particularly severe conditions related to boiler design (Tfluegas = 850 C/Tsteam [ 400 C) after 8000 h in service. An effort was made to gather the main key parameters like local flue-gas and steam temperature, deposit composition, gas phase composition to support corrosion test results. Correlation between corrosion rates and key parameters governing fireside corrosion is discussed.
Experimental Procedures Coating Description Two Cr–Mo–Si–B–Ni base alloys (C1 and C2) containing 15.6 and 16.4 wt.% Cr, respectively, were tested as self-fluxing coatings (see Table 1). Boron and silicon contained in self-fusing powder promote formation of low-melting eutectics with nickel and restore oxide on the surfaces of substrate with the formation of borosilicate slags (self-fluxing) in the presence of a liquid phase. Microstructure of coating applied by induction heating after flame spraying is dense and free of defects such as voids, open porosities or non-metallic inclusions. Strong bonding strength with the substrate (above 440 Mpa) is enhanced by induction remelting process which promote interdiffusion layer formation. The precipitated phases like borides and silicides (CrxBy,NixSiy) contribute to improve the hardness of the coating (above 55HRc). C1 and C2 coatings had been applied on P235GH carbon steel superheater tube (OD = 38 mm, thickness = 5.6 mm, length = 3.5 m). Two tube panels of each coating had been prepared to be installed at different superheater locations. On-Site Test Procedures Experiment had been conducted in one WtE vertical boiler equipped with 12tons/h combustion grate which treats 98% MSW ? 2% non-hazardous industrial waste (NHIW). Flue-gas composition had been measured at 820 C during 2 h, close to tube test area, using FTIR coupled with O2 laser using a high-temperature sampling probe (Table 2). Table 1 Chemical composition of tested material (wt.%) Specimens
Ni
Cr
Mo
Fe
C
Cu
Si
B
C1
Bal.
15.56
\3.5
\5
0.4 * 0.9
\4
4.41
2.5 * 4.0
C2
Bal.
16.42
\3.5
\5
\0.9
\3
4.04
2.5 * 4.0
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Oxid Met Table 2 Gas phase composition close to corrosion test area (average on 2 h)
Tflue-gas
H2O (vol. %)
O2 (vol. %)
CO2 (%)
HCl (mg Nm3)
SO2 (mg Nm3)
10.0–19.3
8.5–11.6
6.1–9.3
680–1352
70–720
Test tubes had been installed on outlet steam tube of low-temperature superheater (LTSH) and high-temperature superheater (HTSH) pendants in the second pass of the boiler (Fig. 1). In this area, the corrosion is known to be the most severe. The flue-gas temperature is assumed to be around 850 C, and the steam temperature is 350 C for LTSH and 400 C for HTSH. Test tubes were placed close to boiler center axis separating at each side of the medium wall (rows 8 and 15) assuming that flue-gas stream and temperature are symmetric to boiler center axis. Local operating conditions in test area had been particularly examined during test period: •
flue-gas and steam temperature measurements had been used to support CFD modeling,
Fig. 1 Location of superheater pendant tube specimens in boiler: a cross section of boiler, b top view of superheater in second pass
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•
deposit sample had been collected after 1-year operation for chemical composition analysis (ICP-OES and X-ray fluorescence analysis) and thermal properties measurement by Setaram Setsys Evolution TGA/TDA device
Metallographic Analysis of Sample After Test After one year in service, 4 test tubes had been removed from boiler, and three sections had been sampled by cutting on each tube at different elevations from the roof, such as Level 1 = 0.25 m, Level 4 = 1.10 m, Level 7 = 2.50 m. Samples were embedded into resin, and cross sections were polished at #4000 SiC grade under water. Cross sections were observed, and coating thickness was measured by using Olympus optical microscope and Stream image analysis software. The metallographic cross sections were characterized by scanning electron microscopy coupled with energy-dispersive X-ray spectroscopy analyzer (SEM/ EDX JEOL J7600F, JEOL JSM-6010/LA) and electron probe micro-analysis (EPMA) to investigate corrosion product layers and to detect the presence of corrosive elements. Modeling Procedures Computational fluid dynamics (CFD) software ANSYS FLUENT 15.0 was used to simulate the flow dynamics in the furnace, the first pass and the second pass of the boiler. Three-dimensional conservation equations were solved for mass, energy, momentum, together with the k - e turbulence model (k = turbulent kinetic energy, e = rate of dissipation of the turbulent kinetic energy). Physical and chemical characteristics at any point of the domain can be estimated by these calculations. A first simulation was carried out in the furnace and the first pass, considering turbulence, heat transfer and combustion phenomena of the gas phase. Thus, the gas flow characteristics were estimated at the first pass outlet, and such characteristics were used as boundary conditions for a second simulation in the second pass of the boiler, considering turbulence and heat transfer phenomena in the gases and the steam phases, and heat conduction phenomenon in the superheater tubes. For modeling of the calculation, the plant operation was supposed to be stationary. The temporal operation fluctuations due to waste composition and flow rates (waste, air and steam) variations were not considered.
Results Estimation of Tflue-gas/Tmetal Tflue-gas had been measured at entrance of the second pass (open pass). Tube metal temperature had been measured on each pendant tube in front of superheater header
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of the roof outside room (not in contact with flue-gas flow). These measurement positions are a little far from the area of specimen’s points, but measured temperatures are considered to really represent the exposure conditions of coated tube positions. Consequently, this measurement had been used to establish and validate a CFD model of the flue-gas flow in the second pass and of steam flow in heat exchanger, and enabling to determine flue-gas, steam and metal temperature profiles. It can be observed (Fig. 2) that higher flue-gas temperatures were obtained in LTSH pendant areas, about 150–200 C higher than the gas temperatures around HTSH pendants. Moreover, the modeling of steam temperature profile illustrates the gradual increase in steam temperature along the tube arrangements between inlet and outlet of each superheater. Inlet and outlet steam temperature was evaluated, respectively, about 260 C and 370 C in LTSH, and about 320 and 420 C in HTSH. The metal temperature calculated at 100 lm from tube surface is determined to be about 10–30 C higher than steam temperature along the superheater pendants. CFD results were used to estimate local temperature conditions (Tflue gas and Tmetal) of corroded sample examined (Table 3). Deposit Deposits collected on low- and high-temperature superheaters were analyzed by ICP (Fig. 3) and reveal the presence of chlorine, potassium, heavy metal (zinc and lead) and sulfur. Deposits are usually constituted of silicate oxides and calcium sulfate with K and Na chlorides and sulfates. Chlorine content was close for both deposits. Higher amount of alkali and heavy metal, particularly zinc, is measured on LTSH, while HTSH deposit contains more ash oxide elements.
Fig. 2 Temperature profiles (C) by CFD modeling of flue-gas (left) and steam (right) estimated in vertical boiler with platen superheaters located in second pass
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Oxid Met Table 3 Summary of average corrosion rates, associated operating parameters and molten salts amount Corrosion rate (lm/8000 h)
Average
%Cr
Taflue-gas(C)
Tametal(C)
[Tmetal - Tsolidus]b
Xmelted
C1—HTSH—Level 1
311
15.6
639
430
20
4
C1—HTSH—Level 4
987
15.6
667
428
18
4
C1—HTSH—Level 7
1147
15.6
660
425
15
4
C2—HTSH—Level 1
795
16.4
639
430
20
4
C2—HTSH—Level 4
1058
16.4
667
428
18
4
C2—HTSH—Level 7
1010
16.4
660
425
15
4
C1—LTSH—Level 1
398
15.6
827
400
-10
0
C1—LTSH—Level 4
460
15.6
833
386
-24
0
C1—LTSH—Level 7
435
15.6
827
379
-31
0
C2—LTSH—Level 1
519
16.4
827
400
-10
0
C2—LTSH—Level 4
661
16.4
833
386
-24
0
C2—LTSH—Level 7
582
16.4
827
379
-31
0
a
Extracted from CFD modeling
b
Estmated from thermodynamical approach
Fig. 3 Mean chemical compositions of low-temperature (blue) and high-temperature (red) superheater deposits in vertical boiler (Color figure online)
Difference on LTSH and HTSH deposit compositions, for tubes close to each other and at similar elevation, can be attributed to their different positions in regard to flue-gas flow coming from first pass (Tflue-gas) and to steam temperature (thus metal temperature) difference as observed on CFD modeling (Fig. 2). A principal component analysis (PCA) has been made on 15 superheater deposit chemical contents taken from 4 different vertical boilers at same flue-gas temperature (650–850 C). This statistical representation aims at identifying similar behavior of chemical elements regarding their distribution. The major behavior identified can be seen as a salt/inert ratio indicator as proposed by W. Spiegel [15]. Salt elements (heavy and alkali metals) in deposit seem to be correlated among
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themselves as well as inert element that represent oxide ash elements (Al, Si, Fe, Ca, etc.). Salt and inert contents increase in opposite way. TDA tests have been performed on LTSH and HTSH deposits from 20 to 900 C at 10 C/min to evaluate the temperature at which first fraction of deposit is able to melt (Fig. 4). Heat flow fluctuations indicate some melting areas associated with endothermic pic after drying process (above 100–150 C). These melting domains comprise between 350 and 650 C, and are similar between the two samples, but we can notice that heat flow absorption recorded is greater on LTSH deposit assuming higher molten phase fraction: • • • •
The first lowest melting temperature was between 350 and 375 C, The second melting temperature was around 400 C particularly in LTSH deposit, The third melting temperature was between 425 and 450 C, Two other melting temperatures were above tube temperature at T [ 450 C.
Metallographic Analysis The residual thickness measured by optical microscope on all 12 samples had been represented as residual thickness density diagram on Fig. 5 and compared to initial coating thickness distribution (average thickness around 1.6 mm). In Fig. 5a, b, corrosion behavior of both coatings was compared for each tube location (LTSH and HTSH), considering simultaneously all the residual thickness measured at each level. It clearly appears that coating C1 looks to be more corrosion-resistant than C2 coating on LTSH pendant tube, while corrosion resistance of both coating looks
Fig. 4 DTA result of deposits collected in LTSH and HTSH
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Fig. 5 Density diagram of residual thickness frequency according to coating material and position in the superheaters (straight line for residual thickness, dot line for initial thickness)
quite similar on HTSH pendant tube. Average corrosion rate reported for each level in table (Fig. 5a, b) and also tends to demonstrate that corrosion rate is lower on Level 1 than corrosion rates at Levels 4 and 7 for both LTSH and HTSH. Figure 5c, d shows that corrosion rate is higher on HTSH than on LTSH for both coating at a given level. Thickness density profile also highlights that thickness loss is not uniform and local low residual thickness is reported (below 400 lm on C1 and C2 coating on HTSH). Maximum corrosion rates calculated for C1 and C2 are approximately of 1.5 mm/year. Cross-sectional observations point out a lot of small corrosion pits on the surface with pits depth ranging from 0.1 to 1 mm (Fig. 6). Corrosion damage occurred by the connection of such localized corrosion in cross-sectional microstructures of both coatings. Some cracks were formed in the coating layer, and small interface corrosions were observed under the cracks (Fig. 6a). These cracks were considered to arise during service period from these sharp shapes on the edge of surface due to thermal stresses and fluctuation loaded on tubes. Figure 6b shows corrosion pits illustrating localized corrosion, examined by EPMA in Fig. 9. When continuous and uniform Si oxide layer or mixed Si–Cr oxide layer is formed, like on C2 coating from LTSH Level 4 (Fig. 7), corrosion seems to be suppressed or limited. But as soon as this Si-rich oxide layer becomes discontinuous and less enriched in Si, localized corrosion and pits are considered to be formed (Fig. 8). In EPMA results obtained on C1—LTSH—Level 4 (pits on Fig. 6b), large amounts of K, Ca, Zn, Pb, S, O and Cl were present in deposits and also in corrosion scale (Fig. 9). Upper part of the scale is mainly composed of Ni, Fe, Cr, Zn, Pb mixed oxide and/or sulfate, while under layer is rich in Cr, Si, Ca, K oxide and/or
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Fig. 6 Cross-sectional observations of C1—LTSH—Level 4 sample after 8000 h of exposition
Fig. 7 EDX mapping of C2—LTSH—Level 4 sample after 8000-h exposure
chloride. O2 and SO2 from flue-gas promote the formation of oxide scale and sulfidation of alkali chloride initially deposited on tube surface. In the interface between corrosion products and coating, Cl or S is rich supporting that gaseous
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Fig. 8 EDX mapping of C2—LTSH—Level 4 sample after 8000-h exposure
Fig. 9 EPMA mapping of C1—LTSH—Level 4 sample after 8000-h exposure
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species diffuse through the coating interface, and considered to lead to chlorination/sulfidation gaseous reaction under the scales. Cr- and Si-rich oxide layers were formed in corrosion scale close to the coating interface, but these are not considered to be continuous and partly protective in this superheater conditions under thermal stresses and fluctuations. Deposits containing heavy metal are cause of very severe corrosive environments that can lead to localized attack of protective oxide scales, if melting temperature of such deposits is lower than metal temperature. The depth of pitting growth is considered to be due to these local damages of protective oxide layers in the pits.
Discussion The present industrial feedback on Ni base self-fluxing alloy coating in WtE boiler after 8000-h operation confirmed that corrosion rates recorded on pendant superheater tubes located in the second pass of the boiler are very important due to severe corrosive conditions. Maximum corrosion rate reported, around 1.5 mm/ 8000 h in the most severe conditions, is almost equal to alloy 625 mono-pass overlays. Nevertheless, thickness of self-fluxing coatings is usually thinner (1 *1.5 mm) than weld overlay cladding (around 2.5) that their lifetime is lower. The best corrosion resistance of C1 coating observed on LTSH pendant tube is in agreement with laboratory test results reported by Galetz et al. [7] who also observed the formation of Si-rich oxide layer. Formation of silica layer at surface below chromium-rich oxide scale is known to reduce oxidation rate of Ni–Cr alloys, and also known to decrease the minimum amount of chromia required to establish a protective chromia scale [16]. Dense microstructure obtained by remelting process of the thermal spray coating suppresses the internal corrosion between splats, but radial cracks formed in service allow the penetration of corrosive species and attack at coating/substrate interface. On HTSH, corrosion rates are much higher for both coatings, and it is more difficult to distinguish the best coating between C1 and C2. Localized corrosion looks increasing when chromia- and/or silica-rich layer is damaged by molten salts attack or other factor such as thermal stress, temperatures and many kinds of fluctuations. Higher corrosion rates reported on HTSH pendant tube should be supported by severe corrosive environment induced by additional molten phase (Na, K, Ca, Zn, Pb, Cl, S) corrosion processes and by the higher metal temperature [6]. The fluxing of the oxide scale by molten heavy metal chlorides with sulfates is mainly reported in the literature [12, 17]. Schaal et al. [18] recently suggested that zinc chloride, existing in the Na–K–Ca–Cl–S liquid salt phase, attacks chromia scale formed on Inconel 625 alloy according to the following reactions:
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ZnCl2 þ 2 Cr þ 2 O2 ¼ 1=4 ZnCr2 O4 þ Cl2ðgÞ
ð1Þ
2 ZnCl2 þ 2 Cr2 O3 þ O2 ¼ 1=42 ZnCr2 O4 þ 2 Cl2ðgÞ
ð2Þ
Oxid Met
Less data are available on the stability of SiO2-rich scale at relatively low temperature in the presence of molten salts. Nonetheless, Ishitsuka [17] claims that molten deposits are basics according to the gas composition and particularly in the high H2O content in the waste-to-energy plants. Brossard et al. [19] proposed one elementary step of the dissolution of silica could be explained by reaction 3 (Eq. 3). SiO2 þ Na2 SO4ðlÞ ¼ Na2 SiO3 þ SO3ðgÞ
ð3Þ
In an oxidation environment, this reaction will be promoted only if the O2 flow favors a rapid removal of SO3(g) and drive the reaction to the Na2SiO3 formation. Local temperature data extracted from CFD modeling presented in Table 3 confirm more precisely that temperature reached on HTSH pendant tube is slightly higher (around 30 C) than one of LTSH. Nevertheless, effect of these slight temperature differences on formation of molten phases in deposit is not easy to predict considering that deposit composition changes between LTSH tube and HTSH tube. The difference of deposit composition can be explained from difference between metal temperature and flue-gas temperature closed to the two pendant tubes for a given elevation (833 and 667 C, respectively, at Level 4). Condensation mechanisms involved in deposition process are highly dependent on flue-gas temperature and metal temperature, gas flow condition and ash compositions. At high flue-gas temperature (Tflue-gas [ 650–700 C), alkali metals and heavy metals are mainly present as volatile chlorides that can condensate on low-temperature tube [9], while at lower flue-gas temperature, these corrosive species can be present in flue gas as condensate particles that will impact and adhere to tube surfaces. Also the molten phase content in the deposits was suggested to be important factor to control corrosion rate in these kinds of molten chlorides-/sulfates-induced corrosion [20]. Based on deposit compositions and phase diagram data available on Factsage 6.4TM software (2013) (KCl–NaCl–ZnCl2; KCl–NaCl–PbCl2; KCl–NaCl–K2SO4– Na2SO4; K2SO4–Na2SO4), an algorithm was developed to estimate: (1) (2)
compounds able to be present in the deposit the maximum reachable fraction of melting salt amount from a mixed salts of K, Na, Zn, Pb, Cl, SO4 elements considering solidus temperatures of each system independently (chemical interaction between systems is neglected).
Total salt amount is found to be more important in LTSH deposit (40 wt.% oxides/15wt. % chlorides/45 wt.% sulfates) than in HTSH (52 wt.% oxides/16wt. % chlorides/31 wt.% sulfates). First melting salts appeared around 410–420 C for both deposits (Fig. 10) slightly higher than temperature identified by TDA (Fig. 5). Important ZnCl2 amount and low inert content on LTSH induce an important potential of melted fraction in the deposit at low temperature. Nevertheless, metal temperature on LTSH does not exceed 400 C; thus, melting of deposit should not be promoted on low-temperature superheater, and melted fraction should be equal to 0. This assumption must be considered carefully as TDA points out lowertemperature melting process on LTSH deposit and that metal temperature can fluctuate in service.
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Fig. 10 Estimation of molten salts content in deposits calculated by thermodynamic approach using Factsage software
On the other hand, molten phases will be activated on HTSH pendant tube which metal temperature ranges from 420 to 430 C. According to Fig. 10, melted fraction (Xmelted) on HTSH tube in service could be estimated to be around 4% as reported in Table 3. Regarding these results, a first attempt is proposed to establish a correlation of corrosion rates measured, Cr content (Cr %) in the coating, Tflue-gas, Tmetal and amount of molten phases present on the tube. The following equation of corrosion rate had been proposed using linear multiple regression analysis and gives a R2 value close to 0.8 (Eq. 1): CR Ave ¼ A þ 150 Cr% þ 20 Tfluegas þ 2:64 ½Tmetal Xmelted
ð4Þ
This preliminary result is not enough to conclude on the mechanism involved and to establish a corrosion rate law, but aims at identifying and quantifying the relative degree of contribution for the operating parameters on fireside corrosion rates. This suggests to investigate more in details regarding the thermodynamic and thermal behavior of the deposit to define accurately the lowest melting temperature of molten phases and increase in the melting fraction with temperature.
Conclusions The evaluation of fireside corrosion resistance of coatings in WtE application requires particular attention for accurate estimation considering local operating conditions to discuss corrosion rates and mechanisms. The results obtained in this study are summarized as follows. In the present study, CFD modeling had been used to quantify flue-gas/metal temperature at different elevation of LTSH and HTSH outlet steam tubes. LTSH outlet steam pendant tube is exposed to higher flue-gas temperature than HTSH
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outlet steam pendant tube while metal tube temperature ranges from 379 to 400 C for LTSH tube and from 425 to 430 C for HTSH. (1)
(2)
(3)
Deposit compositions showed that LTSH deposits contained more heavy metal (Zn, Pb) and sulfates than HTSH deposits which contain less such salts (Na, K, Cl) by flue-gas condensation and inert salts (Ca, Al, Si oxide) by flying ash adhesion. Deposits showed the same melting temperatures for both coatings, but endothermic peaks of DTA showed that molten salt content is higher on LTSH. An attempt was proposed to establish correlation between corrosion rate and %Cr in the coating, Tflue-gas, Tmetal and amount of molten phase in deposit in service. This work must be continued with a particular focus on characterization of melting fraction evolution with temperature. Corrosion rates measured on LTSH pendant tube were lower than the one reported HTSH pendant tube. It is suggested that LTSH metal temperature remains lower than melting temperature of deposits, and then, the molten salt corrosion does not seem to occur, while higher metal temperatures in HTSH can lead to the molten salt-induced corrosion. In both cases, maximum corrosion rate reported is around 1.5 mm/8000 h. This corrosion rate is closed to the one for Inconel 625 mono-pass weld overlay (2.5 mm thick) in similar conditions. The corrosion scale was constructed by an upper layer rich in Ni, Fe oxide or sulfate mixed with Zn, Pb elements and an inner layer rich in Cr and Si in contact with Ca, K chlorides. Cross-sectional observations reveal that surface is covered with small pits, and supposed that corrosion damage proceed by pits growth and connection. Corrosion scales in the pit area suggest that pitting is limited in the presence of dense silica-rich layer below the chromium-rich oxide scale, while pitting depths increase in damaged Si-rich oxide scale. Silicon has a beneficial effect on fireside corrosion and formation of dense coating structure that limits progression of corrosion. Nevertheless, radial cracks appear in service in the coating.
Acknowledgments The authors would like to thank Michel VILASI and Lionel ARANDA (Institut Jean Lamour, Nancy) for support on SEM analysis and fruitful discussions.
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