OVERHEATING AND FUEL ASH CORROSION FAILURE OF ...

OVERHEATING AND FUEL ASH CORROSION FAILURE OF
BOILER TUBES IN SWCC POWER PLANTS
- Some Case Studies 1
ABSTRACT
Nausha Asrar, Anees U. Malik and Shahreer Ahmed
Research and Development Center
Saline water Conversion Corporation
P.O.Box 8328, Al-Jubail, Kingdom of Saudi Arabia.
Dhib Al-Subaii
Al-Khobar Power and Desalination Plant, Al-Khobar
And
Izdein M. Said
Al-Khafji Power and Desalination Plant, SWCC
Results of investigations of the failure of boiler tubes of SWCC power plants at Al-
Khafji and Al-Khobar are presented. Cause and mechanisms of failure are discussed
and recommendation for prevention of reoccurrence of such failures are provided.
Case - I
Failed boiler tubes of Al-Khobar plant were received. The tubes had circumferential
cracks and blown up portions. All the failures were detected on the fire-side surfaces of
the tubes. Presence of sulfur in the oil ash deposits on the fire-side of the tubes appears
to be the main cause of failure of boiler tubes. The cracking of the tube at the weldment
was due to the combined effect of S-induced corrosion and welding stresses.
Circumferential fissures initiated by the molten ash were enhanced greatly due to
welding stresses and resulted in the cracking of tube at the weldment. It is
recommended to avoid high sulfur in the fuel and to maintain a low metal temperature
(below 480 o C) in the boiler.
Case - II
Superheater tubes of boiler # 100 ad 200 of Al-Khafji plant were found ruptured. The
rupturing and hole formation in the superheater tubes is the result of long term
overheating of the tubes. Thinning of tube walls occurred due to localized deposits and
1
Presented in Second Acquired Experience Symposium on Desalination Plants O&M, SWCC, Al-Jubail,
Sept.29-Oct.3, 1997.
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overheating problems. For avoiding reoccurrence of such failures it is recommended to
carry out regular inspection of scale deposition on the steam/water side surface and
measurement of deterioration in the boiler tube thickness. If the amount of the deposits
has crossed the allowable limit, cleaning of the tubes should be carried out
immediately.
INTRODUCTION
The failure of industrial boilers has been a prominent feature in fossil fuel fired power
plants. The contribution of one or several factors appear to be responsible for failures,
culminating in the partial or complete shutdown of the plant. The use of high sulfur
or/and vanadium-containing fuel, exceeding the design limit of temperature and
pressure during operation, and poor maintenance are some of the factors which have a
detrimental effect on the performance of materials of construction. A survey of the
literature [1-8] pertaining to the performance of steam boilers during the last 30 years
shows that abundant cases have been referred to, concerned with the failure of boilers
due to fuel ash corrosion, overheating, hydrogen attack, carburization and
decarburization, corrosion fatigue cracking, stress corrosion cracking, caustic
embrittlement, erosion, etc. Oil ash corrosion which is quite common in utility boilers is
originated from the vanadium present in the oil. Vanadium reacts with sodium, sulfur,
and chlorine during combustion to produce low melting point ash compositions. These
molten ash deposits on the boiler tube surfaces dissolve protective oxides and scales,
causing accelerated tube wastage [3]. Corrosion problems in boiler tubes arisen due to
overheating are quite common. This mode of failure is predominantly found in
superheaters, reheaters, and water wall tubes, and in the result of operating conditions in
which tube metal temperature exceeds the design limits for periods ranging from days to
years. The phenomenon of overheating is manifested by the presence of significant
deposits, which impart a reduction in water flow and excessive fire-side heat input. Due
to this rise in temperature, steel loses its strength, causing rupture or bulging of the tube
due to internal pressure. In a recent investigation [9], three case studies in two 1800 psig
boilers are described. The failures have been attributed to accelerated corrosion,
hydrogen attack and overheating. In another study, corrosion of stainless superheater
tubes occurred due to carburization resulting in intergranular wastage of steel near the
exposed surface [10]. Use of fuel oil high in S, V, and asphalt content in a plant, after
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about 12 years service, resulted in deposition of carbon coke and soot particles on the
tube surface and introduced a carburization process in the steel matrix [11].
Gabrielle [12] overviewed the water related tube failures in industrial boilers. The
causes of the majority of failures are attributed to the upset in water quality and/or steam
purity. The mechanisms of failures due to overheating (short term and long term),
water-side corrosion, general surface attack, stress-assisted corrosion, caustic
embrittlement, hydrogen damage, and chelant corrosion have been discussed in detail.
This paper presents the results of two separate investigations carried out to determine
the causes of failure of boiler tubes of Al-Khobar and Al-Khafji Power and Desalination
Plants. The main aim of this investigation is to acquaint the operation and maintenance
personnel with the different corrosion modes involved in failures, and to suggest some
measures for preventing the recurrence of such failures.
CASE - I : SULFUR INDUCED CORROSION AND STRESS
ENHANCED CORROSION
GENERAL DESCRIPTION
Failed tubes, designated as A and B of Al-Khobar plant were from the tertiary
superheater area. All the tubes were first examined by nacked eyes and then under a
stereo microscope and the failed area were marked by arrow (Fig. 1 a. and b).
Following were the as received conditions of the above tubes.
Tube A. : This tube (OD 45 mm thickness 6 mm) was cracked circumferentially at the
HAZ of the weld and was found in two pieces. The fire-side surface was covered with a
brown color adherent oxide scale while the steam side surface was covered with black
oxide scale (Fig. 1 b).
Tube B : In tube B (OD 45 mm, thickness 6 mm) a ~ 30 mm long ~ 20 mm wide
burst was found. Thickness of the lip of the burst was same as the thickness of the tube
wall. This indicates that this area of the tube had blown up without bulging of the tube.
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In addition to this burst, large number of circumferential cracks, originating at the fire-
side surface of the tube and going deep into metal matrix, were also observed.
Material Analysis
Materials of A and B tubes were analyzed with the help of EDAX and their carbon level
was determined by Carbon-sulfur analyzer. The composition of Tube A was found
similar to 1¼ Cr 0.5 Mo steel (ASTM grade A213 T12) and tube B as 2½ Cr 1.0 Mo
steel (ASTM grade A 213 T22).
Microstructural and Elemental Analyses
A small cross-section of the failed area was taken from the failed zone of the tube and
mounted in conductive resins. Mounted specimens were abraded, polished, etched,
dried and their metallographic studies were carried out under the metallurgical
microscope. Metallographs of the tube A revealed that on fire-side surface of the tube
thickness of oxide scale is not uniform and the corrosion is intergranular in nature (Fig.3
On fireside surface of the tube B, many grooves starting from the surface and going
deep into the matrix were revealed by optical metallography. One of the grooves
showing corrosion product within the canal of the groove is shown in the Figure 4. On the
fireside surface the oxide scale were very fragile in nature and, therefore, were broken
during polishing of the sample.
In order to understand the chemistry of oxide scales, metal matrix and inclusions found
inside the cracks, EDAX and EPMA techniques were used. Figure 5 is the
characteristic EPMA composition profile of the oxide scale formed on the fireside
surface of the boiler tube A. In these images sulfur is recognized in the innermost layer
of the oxide scale. Corrosion product present in the grooves of the fireside surface of
the tube-B was analyzed by EPMA. Figure 6 shows presence of sulfur at the growing
tip of the grooves.
DISCUSSION
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Bunker-C oil is used for fuel in power plants. During the distillation process, virtually
all the metallic compounds and a large part of the sulfur are concentrated in the residual
fuel oil.
The fuel oil constituents that are reported to have the maximum effect on oil ash
corrosion are vanadium, sodium, sulfur and chlorine. According to chemical analysis of
deposits, formed on superheater tubes (Table - 1), sulfur content increases when
vanadium content is reduced in the deposits [13]. Our EDX analysis and EPMA results
showing no vanadium and considerable amount of sulfur in the corrosion product is
in consistent with the findings of Tomozuchi et. al., [13].
Microscopic studies of the corroded areas of the boiler tubes have revealed selective
corrosion of the grain boundaries of the tubes (Fig. 3). Chemical analysis of the
corrosion products indicates that sulfur is one of the major causes of the failure of the
fire-side surfaces of the boiler tubes.
Sulfur-Induced Corrosion
Sulfur typically is found as sodium sulfate in fuel ash. At high temperature it
dissociates according to the following reaction [14].
Na2SO4 → Na2O + SO3
The reaction products will alter the basicity of the molten ash deposits. Sulfur reacts
with sodium in the melt altering the concentration of Na2O, and thereby changing the
corrosion rates. The melting of deposits depends on the Na + S/V ratio and it ranges
from 480-900 o C.
Observation of the corroded parts through optical microscope has revealed grooving and
selective corrosion of the grain-boundaries. EPMA results show presence of only sulfur
beneath the oxide scales. These results indicate that the failure of the boiler tubes is due
to sulfur induced corrosion and, therefore, the tube metal temperature must have raised
above 480 o C. As the intergranular corrosion of the fireside surface of the tubes
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increases the mechanical properties of the tube metal deteriorates. Under these
circumstances if the temperature and pressure of the tube elevate abnormally due to
some reason, the tube will burst.
Figure 6 is the EPMA sulfur print of the grooving. Existence of abundant sulfur at the
tip of the groove proves that the reaction by alkali sulfate compounds play an important
role in the grooving corrosion. During this corrosion the end of the corroded part grows
deep into the metal matrix.
Stress Enhanced Corrosion
In the case of tube A it appears that the weldment was not stress relieved. When
corrosive conditions are prevalent, the current flow between the anodic and cathodic
half cells (stressed and unstressed regions respectively) is greatly enhanced. The
welding stresses of tube A, therefore, might have enhanced the growth of the fissures
caused by sulfur induced corrosion and this resulted into the cracking of the tube at the
weldment.
CASE - II : LONG TERM OVERHEATING
GENERAL DESCRIPTION
The strength of carbon steel remain nearly constant up to about 454 o C. Above this
temperature, steel begins to loose its strength rapidly. If the tube metal temperate is
gradually increased beyond this temperature, it will plastically deform and then rupture.
The approximate time to rupture is a function of the hoop stress (related to internal
pressure and tube dimension) and the temperature. The localized nature of the
overheating is a consequence of the fact that deposits do not form uniformly along the
time. The deposits, occur in locations of high heat flux. Deposits may also favor areas
where physical “drop out” of suspended solids is more likely, such as weld backing
rings or sloped tubes. These deposits insulate the metal from the cooling effects of the
water, resulting in reduced heat transfer into the water and increased metal temperatures.
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As the local regions develop hot spots, bulging of the tube occurs which results into the
rupturing of the tube (Fig. 7).
IDENTIFICATION
Overheating failures caused by the insulating effect of deposits can invariably be
recognized by the formation of blisters in the tube. These blisters represent a localized
area of the tube that underwent creep deformation. Presence of thick, brittle, dark oxide
layers on both internal and external surfaces indicate the occurrence of long-term
overheating. Reduction in wall thickness and increase in OD of the tube (Fig 8) show
the extent of oxide scale formation and bulging of the tube. Bulging usually causes
spalling of deposits at the bulged site, which reduces the thickness of the wall tube. Due
to prolonged thermal oxidation and thinning of the tube wall a hole appeared on the
fireside (Fig. 7a). Superheater tubes shown in Figure 7b, were ruptured longitudinally
due to high pressure and thinning of the tube wall. Here the broad mouth of the rupture
indicates that the ruptured tubes remained in the furnace for long period during which its
lip were heavily oxidized at high temperature and corrosion products were eroded due to
flow of steam. Presence of S and V has been identified by EDAX in the oxide scales on
the fireside surface of these tubes (Fig. 9 and 10).
DISCUSSION
Long-term overheating is a chronic problem. It is the result of long-term deposition
and/or long-term system operating problem. Heavy deposition on steam and fireside
surfaces of water wall or superheater tubes insulates the tube wall from the cooling
effect of water or steam. Deposits on superheater tubes caused by carryover and/or
contaminated water can produce overheating. Heavy deposition on the steam-side
surfaces of the failed tubes is expected also due to its slant orientation. Other probable
sources of overheating could be overfiring, incorrect flame pattern, restricted coolant
flow.
In order to avoid this problem, headers, U-bends, long horizontal runs and the hottest
areas should be inspected for evidence of obstruction, scales, deposits and other foreign
materials. Sometimes, excess deposits are removed by chemical or mechanical
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cleaning. Also firing procedures, and furnace temperature near the overheated areas
should be checked.
CONCLUSIONS
1. Presence of sulfur in the oil ash deposited on the fireside surfaces of the tube
appears to be the main cause of the failure of the boiler tubes at Al-Khobar Power
Plant.
2. The mode of failure is intergranular corrosion attack induced by molten ash
deposits when the tube metal temperature was raised above normal working
temperature, i.e., 480 o C.
3. Cracking of the tube A of Al-Khobar plant at the weldment is due to the combined
effect of sulfur-induced corrosion and welding stresses. Circumferential fissures
initiated by the molten ash were enhanced greatly due to the welding stresses and
resulting into the cracking of the tube at the weldment.
4. Rupturing of superheater tubes of boiler # 100 and 200 at Al-Khafji plant and hole
formation in the superheater tube of boiler # 200 are the results of long-term
overheating of the tubes.
5. Thinning of the tube walls is due to localized deposits and overheating problem.
6. Ruptured tubes of boiler # 100 and # 200 remained unattended in failed condition
for a long period due to which most of its lip portion were burned.
RECOMMENDATIONS
1. Periodic analysis of the fuel ash deposits on boiler tubes is recommended for
determining the amount of sodium, sulfur and vanadium which are responsible for
corrosion.
2. The use of high sulfur in the fuel and increase in the tube metal temperature
should be avoided.
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3. SWCC should establish its specification for the maximum amount of the sulfur
and vanadium in the fuel oil and stable zone of gas and metal temperature.
4. All the operation parameters of the boiler should be strictly maintained and
monitored properly.
5. Scale deposition on the steam/water side surface and thickness of the boiler tubes
should be inspected as soon as possible. If the amount of the deposits has crossed
the allowable limit, cleaning of the tubes should be carried out at the earliest.
REFERENCES
1. Reid, W. T. External Corrosion and Deposits - Boilers and Gas Turbines. New
York :Elsvier, 1971.
2. Stringer, J. “High Temperature Problems in the Electric Power Industry and their
Solutions”, in High Temperature Corrosion. Ed., R. A. Rapp. Houston : National
Association of Corrosion Engineers, 1983, p. 389.
3. French, D. N. “Liquid Ash Corrosion Problems in Fossil Fuel Boilers”, Porc,
Electrochem Soc., (1983), 83-85, p. 68.
4. “Corrosion in Fossil Fuel Power Plants”, in Metal Handbook, Vol. 13 ed. B. C.
Syratt, Metals, Park, Ohio : American Society for Metals, 1987, p. 985.
5. Porta R. D. and H. M. Herro, “The Nalco Guide to Boiler Failure Analysis. New
York : McGrawll Hill, 1991.
6. Dooley, R B. “Boiler Tube Failures - A Perspective and Vision”, Proceedings
International Conference on Boiler Tube Failures in Fossil Plants, Palo Alto,
California : EPRI, 1992.
7. Calannino J., “Prevent Boiler Tube Failure Part I : Fire-side Mechanisms”,
Chemical Engg. Progress, October, 1993, p. 33.
8. Calannino, J. “Prevent Boiler Tube Failures Part II : Waterside Mechanisms”,
Chemical Engg. Progress, November 1993, p. 73.
9. Hendrix, D. E., “Hydrogen Attack on waterwall Tubes in High Pressure Boilers”,
Materials performance, (1995), 32(8), p. 46.
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10. Lopez-Lopz, D., Wong-Noreno, and L. Martinez, “Usual Superheater Tube
Wastage Associated with Carburization”, Materials Performance, (1994), 33(12),
p. 45.
11. Paul, L. D. and R. R. Seeley, “Oil Ash Corrosion - a Review of Utility Boiler”,
Corrosion, (1991), 47, p. 152.
12. Gabrielli, F. “An Overview of Water-Related Tube Failure in Industrial Boilers”,
Materials Performance, (1988), 27(6), p. 51.
13. T. Kawamura and Yoshio Harada, “Control of Gasside Corrosion in Oil Fired
Boilers”, Mitsubishi Tech. Bulletin, No. 139, May, 1980.
14. L. D. Paul and R. R. Seelay, “Oil Ash Corrosion - A Review of Utility Boiler
Experience, “Corrosion, Feb. 1991, p. 152.
Table 1. Chemical Analysis of Deposits Formed on Superheater
Tubes (At steam temperature 571 o C) [Ref. 13]
Fuel/Sulfur (%)
V2O5 (ppm)
0.2 - 0.3
1-3
2.7 - 2.8
45-65
1.6 - 1.8
130-150
2.4-2.5
200-250
pH 1g/ 100 ml H2O 6.5 3.5 3.8 4.1
Acid Insol. Matt (%) 0.86 3.90 2.54 0.88
Total C as C (%) 0.50 0.66 0.44 0.05
Total S as SO3 (%) 51.8 24.4 21.6 0.89
Total Fe as Fe2O3 (%) 4.70 13.0 11.2 6.48
Total V as V2O5 (%) 0.85 30.0 49.7 83.0
Total Ni as NiO (%) 3.38 6.42 2.24 7.45
Total Na as Na2O (%) 34.4 17.6 17.8 2.69
Total Ca as CaO (%) 2.06 2.25 1.17 0.22
Total Mg as MgO (%) 1.92 1.41 0.88 0.20
SO3 + V2O5 + Na2O (%) 87.1 72.0 72.0 86.6
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Figure 1. Boiler tube - A of Al-Khobar plant showing crack at the weldment
Figure 2. As received boiler tube-B with circumferential cracks and failure opening
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-.
Figure 3. Magnified view of Fig.6 showing intergranular
corrosion by molten ash (X800)
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Figure 4. Optical micrograph of cross section of
grooving of tube-B (X l00)
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@ Figure 5. EPMA micrograph and composition
profile of oxide scale formed on
fireside surface of the boiler tube-A
Figure 6. EPMA picture and composition profile of cross section of
grooving on the tire-side surface of the boiler tube - B
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*
\
Figure 7(a). Superheater tube of boiler #200 showing hole and portion of ruptured (b)
superheater tubes of boiler # 100 and # 200. The tubes have experienced longterm
overheating. Tubes in (b) remained in the furnace for very long period
after rupturing and burned its lips considerably.
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Figure 8. As received condition of the boiler tube-C
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Figure 9 EPMA micrograhp and composition profile of oxide scale formed on fireside surface of the boiler tube-D
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Figure 10. EDAX result of the oxide scale formed on the fireside surface of the raptured
superheater tube of unit # 100.
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f\