7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
1/17
One of the primary challenges of reliably burning coal is managing the corrosion experienced by the furnace heat transfer
surfaces. Fireside corrosion remains a leading cause of failure in superheater and reheater tubes. Also, tubes affected by the
fireside corrosion mechanism may lose 15 mils per year (mpy) and more in extreme cases. Five case studies (three
presented here in Part 1) examine the different failure modes experienced by tubes located throughout the furnace.
Fireside corrosion in the superheaters and reheaters of coal-fired units is known as coal ash corrosion, in oil-fired units as oil
ash corrosion, and in refuse-fired boilers as ash corrosion. Sometimes, fireside corrosion is also referred to as hot corrosion.
The mechanism in each case is similar, but the low-melting species in each is different. In coal ash corrosion, the low-melting
species would be sodium or potassium iron trisulphates (Na3Fe(SO4)3 or K3Fe(SO4)3); in oil ash corrosion they would be
V2O5-Na2O or V2O5-Na2SO4; and in refuse-fired boilers they would be chlorides of iron and zinc along with other possibilities
[see references 1 and 2 in the sidebar]. High temperatures (above 1,000F) of the superheater/reheater favor the formation of
these low-melting compounds.
The corrosion rate in coal ash corrosion, between 1,100F and 1,250F, is very high. In this temperature range, Na2SO4/K2SO4
reacts with surface oxides in the presence of SO3 to form complex liquid sulfates (Na3Fe(SO4)3 or K3Fe(SO4)3) that result in
rapid corrosion [3, 4]. Above 1,250F the corrosion rate is decreased significantly due to decomposition of these complex
liquid trisulfates. Once the liquid phase has been removed, the corrosion is due to oxidation in contact with flue gas.
The corrosion constituents in oil ash corrosion are vanadium, sodium, potassium, and sulfur. The combustion of fuel oil may
produce low-melting species V2O5-Na2O, V2O5-K2O, V2O5-Na2SO4, and V2O5-K2SO4. The melting points of these
compounds range between 1,000F and 1,550F, depending on composition [4, 5, 6]. The oil ash corrosion mechanism is
similar to coal ash corrosion: a low-melting-point liquid forms and it dissolves the protective iron oxides.
In refuse-fired boilers, chloride and sulfate species lead to the formation of low-melting- point liquids on the tube surface that
may contain iron, zinc, lead, and sodium. These species dissolve the protective iron oxide and expose the bare steel to the
corrosive environment, resulting in significant wall loss [7]. Reducing conditions inside the furnace may lead to the formation
of iron sulfide instead of iron oxide. The presence of carbon and iron sulfide within the ash deposits indicates the presence of
reducing conditions. Hydrogen chloride can more easily attack iron sulfides, rather than oxides, to form iron chloride as a
corrosion product. This iron chloride has a relatively low boiling point, and therefore iron chloride vapors form in the
superheater/reheater temperature range, and the corrosion mechanism is by loss of iron as a vapor. The porous sulfide
formed in reducing conditions allows easier formation and removal of iron chloride vapor.
Furnace wall tubes are also subject to fireside corrosion, but the low-melting species differ from superheater/reheaters.
Sodium and potassium pyrosulfate (Na2S2O7 or K2S2O7) have been responsible for furnace wall corrosion [1]. Both of these
species melt below 800F, where the furnace wall tubes operate. The melting points of Na2S2O7 and K2S2O7 are 750F and570F, respectively [4, 8, 9]. Mixtures of these two compounds could melt at even lower temperature. Melting points as low as
635F to 770F have been measured.
One finishing superheater tube sample, from a coal-fired unit, was received for metallurgical analysis. The tube was specified
as 1.875-inch outer diameter (OD) x 0.330-inch medium wall tubing (MWT), SA-213 T22 Cr-Mo steel. It had been in service
for 23 years. Figure 1 illustrates the as-received tube sample and the inner diameter (ID) view. Significant wall thinning was
observed on the flanks of the tube, characteristic of coal ash corrosion. Very hard scale was observed on the tube OD. On
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
7 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
2/17
the steam side, there was a thick oxide.
1. As-received tube and view of ID. Courtesy: David N. French Metallurgists
The tube sample was cross-sectioned, mounted, polished, and etched for metallographic examination. A 3% nital etchant
(100 ml ethanol and 3 ml HNO3) was used to reveal the existing microstructure. Metallographic examinations were
conducted via optical microscopy. Figure 2 shows thick scales at the tube OD and ID. A thick ID scale can raise the tube wall
operating temperature significantly. Figure 3 is a view of coal ash corrosion that had occurred on the OD.
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
7 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
3/17
2. Cross-section of the tube wall facing the gas flow at 4.5x magnification. (Note that numbers on the images do not
necessarily correspond to the numbering in this article.) Courtesy: David N. French Metallurgists
3. View of coal ash corrosion at 100x magnification. Courtesy: David N. French Metallurgists
As shown in Figure 4, the microstructure of the T22 tube had transformed to ferrite with spheroidized carbides.
Metallographic examination was also performed at the 8:00 orientation of the tube to look for creep damage, if any. The
microstructure was the same, irrespective of the specimen location, and there was no evidence of creep.
4. Ferrite with spheroidized carbides, mid-wall at 400x magnification. Courtesy: David N. French Metallurgists
Tube wastage will often be evident and manifested as flat spots on either sides of the upstream of flue gas flow, as can be
seen in Figure 5a. A ring sample, Figure 5b, was sectioned from the tube for dimensional and hardness measurements
(Table 1). The tube had thinned significantly at the 4:00 and 8:00 positions due to coal ash corrosion. The thinnest section of
the ring (0.291 inch at the 8:00 position) was at 88% of MWT. The hardness, averaging 73 Rockwell B (RB), showed that the
tube had softened after 23 years of service.
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
7 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
4/17
5a.
5b.
5. (a) Schematic representation of fireside corrosion. (b) Sectioned ring from the tube with corroded areas noted. The dark
spots are the locations of hardness measurements. Courtesy: David N. French Metallurgists
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
7 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
5/17
Table 1. Case 1 dimensional and hardness measurements. Source: David N. French Metallurgists
Alkali oxides react with SO3 in the furnace atmosphere to form alkali sulfates (K2SO4 or Na2SO4) on the oxide scale. Some of
the SO3 diffuses through the alkali sulfates, and reaction occurs at the oxide-sulfate interface to form alkali-iron-trisulfates
(K3Fe(SO4)3 or Na3Fe(SO4)3) according to the following two chemical reactions:
In this process, the thickness of the oxide scale decreases and the metal oxidizes further to renew the oxide layer. The tube
metal temperature decreases as slag thickens. At room temperature, low-melting compounds sinter the ash particles to form
a tightly bound inner layer. After the slag thickness reaches equilibrium, deslagging increases because the liquid layer on the
tube cannot support a thick layer of ash. This deslagging increases the tube-metal temperature. This process (slagging and
deslagging) repeats in a cycle that leads to create the corrosion pattern known as "elephant hiding" or "alligator hiding."
Coal ash corrosion of the tube analyzed in Case 1 resulted in significant wall loss. The temperature range for formation of
trisulfates is between 1,000F and 1,250F. The decomposition of trisulfates occurs when the temperature exceeds 1,250F.
Above this temperature, coal ash corrosion reduces significantly. Numerous empirical equations have been proposed for
estimating the tube operating temperature based on the oxide scale thickness in superheaters and reheaters. Using one of
these equation with the measured ID scale thickness (25 mils) and hours of operation (171,300 hours) results in an
estimated tube temperature of 1,100F [11]. This estimated tube temperature was within the susceptible temperature range fo
trisulfate formation and coal ash corrosion. The metallography confirmed that the tube had operated in this temperature
range. The tube microstructure had transformed to ferrite with completely dispersed carbides, and the hardness had
decreased.
Log X = 0.00022 (T+460) (20+Log(t)) -7.25
Where:
X = steam-side scale thickness in mils
T = absolute temperature (F+460), and
t = time in hours
A high-temperature vertical reheater tube was received for failure analysis. The tube was specified as 2.25-inch OD x
0.180-inch MWT, SA-213 TP-304H stainless steel. It had been in service for 15 years. The fuel type was No. 6 Bunker C oil.
Figure 6 is the as-received tube with specimen locations illustrated, including a close-up view at the failure site and the ID
view. Significant wall thinning was observed at the failure.
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
7 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
6/17
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
7 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
7/17
6. As-received tube with specimen locations illustrated, close-up of failure, and the ID view. Courtesy: David N. French
Metallurgists
Figure 7 is a specimen at Location F1 with fracture face on the left. The tube is darker in the outer one-third of its cross-
section due to carburization. Intergranular corrosion (Figure 8) occurred along the grain boundaries due to chromium
depletion. The depletion of chromium content due to carbide formation along the austenite grain boundaries and within the
surface grains reduces the corrosion resistance of stainless steel. Within and below the carburized layer, the intergranular
cracking is typical of creep. Higher stresses due to significant wall loss at the failure contributed to intergranular creep cracks
The tube wall was thinned down to approximately 0.075 inch at the edge of the failure. There was no evidence of plastic
deformation at the fracture face, which is typical for creep failure.
7. Location F1, oxalic at 4.5x magnification. Courtesy: David N. French Metallurgists
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
7 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
8/17
8. Location F1, fracture face at 42x magnification. Courtesy: David N. French Metallurgists
Location F2 also had intergranular cracks with some of the grains missing at the tube OD due to pull-out during polishing
(Figure 9). In Figure 10, the microstructure shows sensitized austenitic grains with large carbides along the grain boundaries.
Sensitization occurs from 800F to 1,500F, with the most rapid sensitization at 1,200F.
9. Location F2, intergranular cracks along the grain boundaries at the OD at 200x magnification. Courtesy: David N. French
Metallurgists
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
7 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
9/17
10. Location F2, sensitized grains, mid-wall at 400x magnification. Courtesy: David N. French Metallurgists
Similar carbides were observed in the mid-wall away from the failure at Location B (Figure 11). Although sensitization
decreases the corrosion resistance, it does not affect the mechanical properties significantly.
11. Location B, sensitized grains, mid-wall, 12:00 at 400x magnification. Courtesy: David N. French Metallurgists
Ring samples (Figure 12) were sectioned from the tube for dimensional and hardness measurements. The tube had thinned
significantly: Ring A is 72% of MWT at the 2:00 position, and Ring B is 48% of MWT at the 12:00 position. The hardness,
averaging 83 Rockwell B (RB), is slightly above the range for new SA-213 TP304H, 72-81 RB, as expected for material that
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
7 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
10/17
has been carburized.
12. Sectioned rings. Courtesy: David N. French Metallurgists
Elemental analysis was performed on white deposit that was scraped from the OD surface. Analysis was via energy
dispersive spectroscopy in the scanning electron microscope (see ASTM E1508-98) [10]. The carbon and sulfur content was
determined by combustion analysis (ASTM E1019-03) [11]. The results are summarized in Table 2. The deposit was primarily
iron oxide. Chromium, nickel, and manganese were likely from the steel. High amounts of carbon and sulfur indicate the
possibility of reducing conditions. Unburnt carbon due to reducing conditions resulted in carburization of stainless steel tube.
Potassium, sodium, and vanadium in the deposit point to the presence of low-melting species (such as V2O5-Na2O,
V2O5-K2O, V2O5-Na2SO4, and V2O5-K2SO4) which may have contributed for significant wall loss. Calcium and phosphorus,
from water or water treatment chemicals, were formed after the tube failure. Minor amounts of arsenic, magnesium, titanium,
and chlorine were also detected. The white color may be associated with aluminum and silicon in the deposit.
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
17 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
11/17
Table 2. Constituents of the whitish reheater tube OD deposit. Source: David N. French Metallurgists
The reheater tube failed due to oil ash corrosion, resulting in thinning and creep. Reducing conditions caused carburization of
stainless steel. The microstructure had transformed to carbides along the austenitic grains. Carburization and sensitization
contributed to a reduction in corrosion resistance that resulted in significant wall loss. The OD deposits also point to thepresence of low-melting compounds that caused oil ash corrosion.
A secondary superheater tube was received for metallurgical characterization. The tube was specified as 2.125-inch OD x
0.420-inch MWT, SA-213 T22 Cr-Mo steel. It had been in service for 43 years. Figure 13 illustrates the as-received tube with
specimen locations, and the tube ID view. The oxide scale is seen at the ID. Some roughening and pitting corrosion were
observed on the OD.
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
17 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
12/17
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
17 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
13/17
13. As-received tube with specimen locations illustrated and the ID view. Courtesy: David N. French Metallurgists
Figure 14 is the close-up view of pitting corrosion that had occurred on the OD. A specimen was circumferentially cross-
sectioned to determine the depth of pits. Figure 15 is the close-up view of alligator hiding due to oil ash corrosion. Alongitudinally cross-sectioned specimen was examined to determine the significance of oil ash corrosion at Location B.
14. Close-up view of pitting corrosion at Location A at 3:00. Courtesy: David N. French Metallurgists
The pits observed in Figure 14 were shallow, and there was some intergranular attack along the grain boundaries, as shown
in Figure 16. The alligator hiding (circumferential ridges) shown in Figure 15 was measured, and the deepest oil ash
corrosion was 15 mils from the OD (Figure 17). The cycling of metal temperature causes ash layers to form and shed,
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
17 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
14/17
leading to the alligator hiding. These circumferential grooves from the tube OD are typical for fireside corrosion. No creep
damage was seen at the OD or at the tip of the groove. This area of the tube was exposed to the highest temperature,
making it more likely to have oil ash corrosion.
15. Close-up view of alligator hiding at Location B at 1:00. Courtesy: David N. French Metallurgists
16. Location A, 3:00, superficial pit, OD at 100x magnification. Courtesy: David N. French Metallurgists
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
17 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
15/17
17. Location B, 1:00, 15 mils depth of ash corrosion, OD at 100x magnification. Courtesy: David N. French Metallurgists
The microstructure had transformed to ferrite with spheroidized carbides due to years of service (Figure 18). Similar
microstructure was observed irrespective of the specimen location.
18. Ferrite with spheroidized carbides, Location B, 12:00, mid-wall at 400x magnification. Courtesy: David N. French
Metallurgists
The thickest scale was measured as 20 mils (Figure 19). Based on the oxide thickness and years of service, the tube
temperature was estimated as 1,064F. This temperature is below the recommended maximum for T22 material, 1,075F, but
43 years ago the maximum temperature may have been 1,125F. The operating temperature was within the susceptible
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
17 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
16/17
temperature range for formation of low-melting-point constituents in oil ash corrosion, 1,000F to 1,500F. The low-melting
compounds in oil ash corrosion are V2O5-Na2O, V2O5-K2O, V2O5-Na2SO4, and V2O5-K2SO4. Unlike coal ash corrosion, these
compounds do not thermally decompose at higher temperature.
19. Location B, 6:00, ID with 20 mils of scale at 100x magnification. Courtesy: David N. French Metallurgists
Superficial pitting and some alligator hiding were observed on the OD of the superheater tube due to oil ash corrosion.
V2O5-Na2O, V2O5-K2O, V2O5-Na2SO4, V2O5-K2SO4, or reducing conditions inside the furnace may have contributed to
alligator hiding in this superheater tube. The tube microstructure had transformed to ferrite with spheroidized carbides after
43 years of service.
In Part II we'll explore several more case studies, including ash corrosion of a superheater and fireside corrosion of a water
wall tube.
1. David N. French, Metallurgical Failures in Fossil Fired Boilers, 2nd ed., John Wiley & Sons Inc.
2. R.C. Corey, H.A. Grabowski, and B.J. Gross, "External Corrosion of Furnace-Wall Tubes III," Transactions of the
ASME, vol. 71 (November 1949), pp. 951-963.
3. R.B. Dooley and W.P. McNaughton, Boiler Tube Failures: Theory and Practice, EPRI, vol. 3, ch. 33, "Steam
Touched Tubes" (1996).
4. W.T. Reid, External Corrosion and Deposits: Boilers and Gas Turbines(New York: American Elsevier Publishing
Co., 1971).
5. J.O. Collins and W.A. Herbst, "How Ash of Residual Fuel Oil Affects High Temperature Boiler Operation," POWER,
vol. 98 (November 1954), pp. 100-101.
6. H.W. Nilson, A Review of Available Information on Corrosion and Deposits in Coal and Oil-Fired Boilers and Gas
Turbines, Battelle Memorial Institute, 1958.
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
17 1/6/2012
7/31/2019 The Role of Fireside Corrosion on Boiler Tube Failures, Part I
17/17
7. A.J.B. Cutler, W.D. Halstead, J.W. Laxton, and C.G. Stevens, "The Role of Chloride in the Corrosion Caused by
Flue Gases and their Deposits," Transactions of the ASME(July 1971), pp. 307-312.
8. R.W. Bryers, "Prospects of Fireside Ash Deposition While Firing Coal/Oil Mixture," Joint Power Generation
Conference, St. Louis, Missouri (October 1981).
9. P.D. Miller, C.J. Slunder, H.H. Krause, and F.W. Fink, State-of-the-Art Report on Control of Corrosion and Deposits
in Stationary Boilers Burning Residual Fuel Oil, Battelle Memorial Institute for Bureau of Yards and Docks, Navy
Department (May 1963), Accession Number: AD0422073.
10. ASTM Standard E1508 - 98, "Standard Guide for Quantitative Analysis by Energy-Dispersive Spectroscopy,"ASTM.
11. ASTM Standard E1019 - 03, "Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen
in Steel and in Iron, Nickel, and Cobalt Alloys," ASTM.
-Dr. Rama S. Koripelli ([email protected]) is metallurgical engineer, Dr. David C. Crowe
([email protected]) is technical director, Dr. David N. French is founder, and Jonathan Brand
([email protected]) is a senior metallurgical technician for David N. French Metallurgists.
Close Window
Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-
Top Related