OVERHEATING AND FUEL ASH CORROSION FAILURE OF BOILER TUBES IN SWCC POWER PLANTS

- Some Case Studies1

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

ABSTRACT

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 oC) 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 1 Cr 0.5 Mo steel (ASTM grade A213 T12) and tube B as 2 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 oC.

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 oC. 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 oC. 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 oC.

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 oC) [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 intergranularcorrosion by molten ash (X800)

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Figure 4. Optical micrograph of cross section ofgrooving of tube-B (X l00)

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Figure 6. EPMA picture and composition profile of cross section of grooving on the tire-side surface of the boiler tube - B

@ Figure 5. EPMA micrograph and compositionprofile of oxide scale formed onfireside surface of the boiler tube-A

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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 long- term overheating. Tubes in (b) remained in the furnace for very long periodafter 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

1427

rdc swcc of

rdc swcc

rdc swcc

rdc swccof

rdc swcc

rdc swccof oxide scale formed on fireside surface of the boiler tube - D.

rdc swcc

rdc swcc

rdc swcc

rdc swcc

rdc swcc

rdc swcc

rdc swcc

rdc swcc

rdc swccof oxide scale formed on fireside surface of the

rdc swcc

rdc swcc

rdc swcc

rdc swcc

rdc swcc

rdc swcc

f \

Figure 10. EDAX result of the oxide scale formed on the fireside surface of the rapturedsuperheater tube of unit # 100.

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