The unavailability of coal fired electrical generating capacity when needed is oftenattributable to corrosion in steam generators. Such problems are becoming more widespreadas electricity demand grows faster than new plants come online, forcing greater use of oldplants. Identifying such corrosion problems before they force boiler shutdowns requires proper inspection tools and techniques. These enable inspectors to take the guesswork out of whether boiler tubes should be repaired or replaced.
The goal of today’s boiler inspection programs is to increase the availability, efficiency,and reliability of the existing power plants and ensure safe and cost effective operation. Power generators are extending the time period between unit shutdowns which makes scheduledoutages even more important to completely examine the boiler in order to operate until thenext scheduled outage. As the United States utility boiler fleet ages, and the time periodsbetween shutdowns increase, the proper inspection tools and techniques needed to find,observe, and document current and possible failures are paramount. Before large andcumbersome inspection rigs are assembled for inspecting large areas in the firebox, it is the job of the inspectors to inspect all surfaces and focus the inspection rigs on the degradedareas. The following paper outlines the tools and techniques needed for properly conducting
and documenting a boiler inspection. The degradation mechanisms will first be introduced, andthen the techniques and tools used to find each mechanism will be discussed.
Degradation Mechanisms Observed Using the Proper Inspection Techniques in Utility Boilers
Long Term Overheating: The steam temperature always varies some from individual tubeto tube, and the boiler design allows for this variability. However, when the range of temperatures is larger than anticipated, the hottest tubes fail sooner than expected. A morelikely cause of premature failure is the slow increase in tube-metal temperatures due to theformation of the steam-side scale. Steam reacts with steel to form iron oxide along the IDsurface of the tube. In any event, the thermal conductivity of the steam side scale is about 5%of the thermal conductivity of the steel tube. Thus, an effective insulating layer forms andprevents proper cooling of the tube metal by the steam. The net effect of the scale is to raisethe tube metal temperature. Depending on the scale thickness, which is dependent on thetime and temperature of operation, tube-metal temperature increases of 25 to 75oF (14 to42oC) are likely. The presence of scale can increase tube metal temperatures beyond the safedesign range. These elevated temperatures result in increased creep deformation rates, morerapid oxidation and corrosion (thinner walls and higher stress) and hasten the onset of creepfailures.
Creep failures are characterized by:
1. Bulging or blisters in the tube.2. Thick-edged fractures often with very little obvious ductility.3. Longitudinal "stress cracks" in either or both ID and OD oxide scales.4. External or internal oxide-scale thicknesses that suggest higher-than expected-
temperatures.5. Microstructure has intergranular voids and cracks.
In steam touched tubes, often the very first sign of creep damage is longitudinal cracks inthe steam-side scale. As creep deformation expands the tube diameter, the brittle ID scalecannot follow the expansion. Cracks develop in the direction, which is perpendicular to theprinciple hoop stress. With time, the tube continues to expand, and these cracks widen. Thiswide crack shortens the path from steam to steel; iron oxide forms preferentially at the tip of the crack, as there is less oxide thickness to protect the steel; and a cusp forms within thesteel tube. The cusp acts as a notch or a stress riser, reducing the local wall thickness. Creepvoids form here, often before any other obvious grain-boundary damage appears elsewherewithin the microstructure. With continued high-temperature operation, creep cracks grow fromthe cusp and ultimately weaken the cross section to the point where failure occurs.
Ash Corrosion (oil, coal, refuse): Carbon and alloy steels develop corrosion resistancefrom the formation of protective oxide scales. The denser and more tightly bound the oxidesare, the more corrosion resistant the material will be. Any process that removes protectiveoxides will promote more rapid corrosion wastage. Any process that prevents the formation of these oxides will also promote more rapid corrosion.
Whether the fuel burned is oil or coal, and whether the corrosion location is in the furnaceat temperatures of 500 to 700oF (260 to 371oC) or the high-temperature components at a metaltemperature above 1,000oF (538oC), the corrosion mechanisms are similar. Constituents withinthe ash form a low-melting-point species or a mixture of several compounds that has therequired low melting point. These low-melting-point species dissolve the protective iron oxideon the surface of the boiler tube and bring the bare metal in contact with oxygen. Twoobservations: a) the melting point discussed here is not the ash fusion temperature, and b) theaction of these liquids is like a brazing flux; it dissolves and prevents the formation of aprotective oxide film.
In the case of furnace-wall corrosion, mixtures of sodium and potassium pyrosulfates arethe suspected liquid species. Melting points between 635oF (336oC) and 770oF (410oC) havebeen reported for ash constituents on furnace walls under severe coal-ash corrosion. For corrosion of steam cooled tubes at temperatures above 1000oF (538 oC) in coal-fired boilers,sodium and potassium-iron trisulfates are the culprits. The exact melting point depends on therelative amounts of sodium and potassium, but the minimum melting point can be as low as1030oF (554oC)1. In oil-fired boilers, mixtures of vanadium pentoxide and sodium oxide or vanadium pentoxide and sodium sulfate are the problem. Again, the precise composition willdictate the particular melting point, but these compounds can melt at temperatures as low as950oF (510 oC). In municipal-refuse burners where appreciable chlorine, from polyvinylchloride, is part of the fuel, various chlorides or mixtures of chlorides will serve the samepurpose. Mixtures of iron, sodium, zinc, lead, and perhaps calcium chlorides will form low-melting-point species2. There are many combinations of chlorides that have melting pointsbelow 600oF (315 oC) and some less than 350oF (177 oC).
The morphology or appearance of fuel-ash corrosion is variable. For steam cooled tubesin an oil-fired boiler, the corrosion pattern depends on the volume of liquid and theaerodynamics of the flue-gas flow over the tube. In coal-fired boilers, the appearance takes theform of a series of grooves and is sometimes referred to as "alligator hide"3. For water walltubes, especially in super-critical units burning coal, the appearance is a series of circumferential grooves or cracks. In cross section, again, the appearance is a series of shallow grooves. A micrometer measurement would show that the gross fire-side wallthickness is not substantially different from the cold or casing side. The wall thickness at the tipof the crack can, of course, be thin enough to form a steam leak. In the case of a refuseburner, the appearance is one of a smooth and uniform wastage that reduces the wallthickness. Corrosion rates can be exceedingly high. Carbon-steel wastage rates of about 1/2inch per year (1.27 cm per year) (failure in less than 2,000 hours of operation) are known.
Thermal Fatigue: Fatigue results from reversed plastic strain in metallic crystals. If plasticstraining is confined to microscopic or submicroscopic regions in an otherwise elasticallystressed component, it is likely that a single crack will occur, originating at the point of maximum local stress and minimum local strength in the entire structure. Thermal fatigue may
result in either low-cycle or high-cycle failure. Cracking that occurs after many cycles of loadingis high-cycle fatigue and has no macroscopic evidence of plastic flow. On the other hand,when plastic straining is more extensive, there is a greater likelihood that cracks will initiate atmany discontinuities after fewer cycles of loading (low-cycle fatigue) and that there will bemacroscopic evidence of plastic flow. The fracture surfaces exhibit some plastic flow which isindicative of low-cycle fatigue. Low-cycle thermal fatigue is usually associated with large
plastic strains and is most often caused by large changes in temperature or large differences inthermal expansion between two structural members.
Pressure and thermal cycling during start-up and shutdown are the most common causesof low-cycle fatigue failures. Design factors that concentrate strain influence low-cycle fatigueas well as high-cycle fatigue; however, the effect is not quite the same. When service stressesare high enough to be conducive to low-cycle fatigue, the presence of a severe stress riser willoften cause complete fracture to occur on the first load cycle. Mild stress risers usually do notlead to fracture on the first cycle, but only induce localized yielding, and multiple crackinitiation. Water in soot blowers, water lances, and water cannons may lead to a crazingpattern. The predominant cracks will be circumferential and the minor cracks will be axial 4.
Dissimilar Metal Weld Failures: Dissimilar metal weld (DMW) cracking is caused by theapplication of temperatures and stresses that increase oxide wedge formation and acceleratethe creep process. The total stress applied to the joint includes stresses that arise fromdifferences in the coefficient of thermal expansion; from internal steam pressure, tube deadweight, and through wall thermal gradients; and from constraints to thermal expansion due totube support malfunction. Dissimilar metal weld cracking produces a circumferential fracture inthe joint. Cracks typically form at the toe of the weld in the heat-affected zone of the ferriticalloy. Poor geometry of the weld, excessive undercut, and other stress factors will aggravatethe crack formation. A brittle, thick edged fracture results from the linking up of creep voidsadjacent to carbide precipitates along the grain boundaries.
The key factors affecting DMW cracking are the magnitude of the temperature swing andthe frequency (number of cycles). The likelihood of initiating damage and the extent of damage increase with wider temperature swings and an increasing number of cycles. Startupand shutdown of equipment can cause thermal fatigue. There is no set limit on temperatureswings; however, as a practical rule, cracking may be suspected if the temperature swingexceeds about 200°F (111oC) 5. Damage is also promoted by rapid changes in surfacetemperature that result in a varied temperature through the thickness or along the length of acomponent. Time to failure is a function of stress and the number of cycles.
Erosion (fly ash, corrosion, soot blower): Erosion involves impact of large numbers of small solid particles against a surface. Erosion by solid particles is a form of abrasive wear.Erosion-corrosion is a description for the damage that occurs when corrosion contributes toerosion by removing protective films or scales, or by exposing the metal surface to further corrosion under the combined action of erosion and corrosion6. Abrasive erosion of superheater tubes results from impact by particles of fly ash entrained in the flue gases.Erosion is enhanced by high flow velocities; thus, partial fouling of gas passages in tube bandsby deposition of fly ash can lead to erosion by forcing the flue gases to flow through smaller passages at higher velocity. This effect, sometimes called laning, exposes tube surfaces to agreater probability of impact by particles having higher kinetic energy, thus increasing the rateof damage. Erosion by fly ash causes polishing, flat spots, wall thinning, and eventual tuberupture.
1. Have gaps between the tube bank and the duct walls.2. Have gas bypass channels where the velocity of the flue gas can be much higher than
that of the main flow.3. Have protrusions or misalignment of tubing rows.4. Are adjacent to areas with large accumulations of ash.
Reducing Conditions: Reducing conditions will increase corrosion rates. The presence of carbon monoxide and/or unburned carbon and hydrogen sulfide promote the formation of metallic sulfides. Iron sulfide, for example, is inherently less protective than iron oxide. Sulfidestend to be less protective because they are porous and less firmly attached to the steel. Alternate oxidizing and reducing conditions are no help either. The oxide that forms duringoxygen-rich cycles is reduced or made less sound during the reducing part of the cycle. In fact,it is not unusual in municipal-refuse burners to find a strong smell of hydrogen sulfide (a rotten-egg aroma) on a freshly broken ash sample. The presence of hydrogen sulfide is positive proof of a reducing furnace atmosphere.
Tube Misalignment: Tube misalignment is common in boilers. Alignment spacers, buckstays or attachment welds break, and due to the thermodynamics of the water-cooled or steamcooled tube, the tube bends in the path of least resistance which can misalign the tube. Thismisalignment can increase erosion due to impingement into the fly ash path, or soot blower, or water lance path. Corrosion can also be exacerbated by tube misalignment due toencroachment into the burner path or fly ash path.
Slag Crushes: Falling slag damage results from impacts by fused coal ash deposits or re-solidified molten material that detach from furnace walls and superheater pendants. The slag isdirected towards the ash hopper by the furnace lower sloping wall. Damage can occur fromeither erosion or mechanical impact results to water tubing in either sloping wall tubes and/or the ash hopper. Slag crushes are due to mechanical impact.
Acid dew-point corrosion: In boiler terminology, "acid dew-point" refers to the sulfuric-aciddew-point, as this is the highest dew-point temperature. Both sulfurous acid and hydrochloricacid condense at lower temperatures. For hydrochloric acid, the dew-point may be as low as130oF (54oC). While the precise dew-point for sulfuric acid depends on the sulfur-trioxideconcentration, at 10 parts per million (ppm), or 0.001 wt%, of sulfur trioxide in the flue gas thedew-point is 280oF (138oC). The exact dew-point depends on the concentration of thesegaseous species, but it is around 300oF (149 oC). Surfaces that are cooler than 300oF (149 oC)are likely locations for dew-point corrosion. Any point along the flue-gas path, from combustionin the furnace to the top of the chimney, is a possible site. Any flue-gas leak can also causethis type of corrosion. The obvious locations are openings to the furnace, support penetrationsthrough the roof, leaks around superheater, reheater and economizer penetrations, and the air
pre-heater. Load, oxygen levels, sulfur in fuel, moisture content of the fuel and boiler cleanliness are also parameters that will affect the acid dew-point temperature. Since theseare difficult to measure, and correlate, on a continuous basis, it can be difficult to understandthe effects of each parameter on the dew-point temperature. This dew-point temperaturevariation, when uncontrolled, could result in the condensation of the sulfuric acid on the metalwalls, economizer sections, and stack linings resulting acid dew-point corrosion.
Fretting: Fretting corrosion occurs when there is slight relative motion, as caused byvibration, of two metals in contact with each other. The relative motion destroys the protectiveoxide film so that clean metal is in contact with the corroding media. An example of this may bethe more rapid attack of superheater or reheater tube ties or supports as they rub 7.
Common Utility Boiler Inspection Techniques for Degradation Mechanisms
Proper inspection techniques will help minimize downtime by identifying degradationbefore failures occur to power generation utility boilers. Most of these inspections are visual,however, inspectors are always recommended to have electronic verification if applicable tothe degradation mechanism. The scope of this paper is to document generalized inspectiontechniques and may not fully address the particular corrosion/degradation mechanism in allparts of the boiler system. The typical water wall tube numbering system in a boiler consists of the front and rear wall tubes numbered from left to right while the sidewall tubes are labeledfront to rear.
Figures 1 and 2 document long term overheat failures as observed in a utility boiler.Three indicators used for inspection of overheating in the firebox of a boiler. These are:darkening or discoloring of the tube, an elephant hide appearance, and if bulging or warpingare observed8. If overheating is evident using the above visual criteria, inspectors shouldrecord the wall and tube number on the suspect wall, the length of indication on the tube, andelevation of the suspect tube. This will allow the boiler inspectors to accurately explain thelocation and size of the failure for the boiler repairmen, or boilermakers to remove the tube for replacement.
Tubing may overheat if:1. Tube is the wrong material for the location in the boiler.2. Over-firing or uneven-firing of the burners cause a higher surface heat flux than the
tube was designed for.3. Fouling or deposits are observed on the inside of the tube.4. Loss of boiler coolant or low water level occurs.
Determine if the factors above play a role in the overheating of the damage tube andrectify the issue. Figure 3 presents microstructure of a typical creep failure. Numerous creepvoids are observed in the overheated tube metal. Microstructures consisting of spheroidizedcarbides in a ferrite matrix confirm elevated temperatures were experienced by the overheatedtube.
Figures 4 and 5 depict coal ash corrosion inside the boiler on superheater pendants. Coalash corrosion is easier to visually observe than oil or refuse ash corrosion due to the typicalbuildup of coal ash deposits. Sandblasting of the chosen inspection surfaces is recommendedto observe the tube metal surface for the “alligator hide” corrosion indications and for smoothenough surfaces for ultrasonic wall thickness testing (UT) to be performed across the crown of the tube. Figure 6 exhibits the OD surface of a superheater tube suffering from coal ashcorrosion.
For oil and refuse ash corrosion, UT testing is recommended. The smooth uniformwastage produced by both types of fuel can mislead an inspector into a false sense that thetube meets minimum tube wall thickness criteria.
Thermal fatigue is observed in Figures 7 and 8. Typically, circumferential crackingindicates thermal fatigue, however, if a unit is known to use water cannons or water lances,thermal fatigue, sometimes called “craze cracking” is observed. In visual field observations,inspectors use judgment calls to base the severity of the cracking observed. Thermal fatiguecracking correlates to the corrosion potential of the material experiencing thermal fatigue. For example, thermal fatigue cracks on carbon steel water wall tubes will tend to be wider than thesame crack observed on a stainless steel superheater tube. Corrosion of the material plays apart in the width of the crack, while the thermal shock determines the depth of the crack.Location of these cracks should be noted in reference to soot blowers, water cannons, etc. for future monitoring for leaks. Primary sources for the craze cracking in a boiler are water splashing from the bottom ash hopper, and condensate from the soot blower systems9.Historical information plays a large role in determining the probability of failure for fatiguecracks. Sand blast the tube metal surfaces to create grid locations in the suspected areas for UT and dye penetrant (DT) testing. Welds should be removed from locations where crazecracking is observed to minimize failures due to stress risers caused by welding. Figure 9documents typical thermal fatigue cracking on the crown of the tube.
Figures 10 and 11 exhibit dissimilar metal weld (DMW) failures. DMW failures occur dueto different thermal expansion coefficients of the joined materials. In the high temperaturesuperheater and reheater sections of a boiler, inspect for DMW’s using a magnet10. Focus thearea of inspection on the magnetic or ferritic steel side of the weld, which tends to be theweaker material. Figure 12 illustrates a typical DMW failure. This particular failure shows astainless steel weld overlay which has exacerbated the failure.
Figure 13 depicts multiple tubes that have experienced erosion. Some of the tubes showshields on the tube surfaces which help protect against solid particle erosion. Figure 14presents clogged gas lanes observed during a dirty inspection. The clogging will increase flyash velocity, increasing the fly ash erosion potential. Figure 15 documents typical fly asherosion across the crown of the ring sample. UT testing is the recommended inspection tool for erosion. Ideal areas to inspect for erosion is in the back pass region of the boiler in theeconomizer section. Shields and baffles are a couple of ways to combat erosion. Furthermore,areas of refractory should be inspected for soundness. Refractory is another tool used to slowerosion.
Figures 16 and 17 document wall wastage due to reducing conditions in the boiler firebox.Reducing conditions are usually localized around the burner elevation and should be regularlyinspected. Multiple mils per year of wall wastage can occur in these localized areas of corrosion. UT testing is the recommended inspection tool for wall wastage due to reducingconditions. Inspection should be across the crown of the tube.
Tube misalignment is observed in Figures 18 and 19. When tube misalignment isobserved, inspect for previous repairs that may have been made, materials with differentthermal expansion coefficients, and broken hardware11. These areas should be repaired or replaced, otherwise future issues could arise due to current missed steps.
Figures 20 and 21 shows slag fall damage to ash slope boiler tubes. As ash/slag buildsup on the pendant components of the boiler, these masses exfoliate and fall to the ash hopper for removal. Some of these masses are as large as small cars. Inspection of the lower slopeportion of the boilers may reveal slag fall damage that may need replaced. Rule of thumb is if 15% reduction in the ID cross section of the tube is observed, replacement is recommended.Further inspection is recommended up the slag fall damaged circuit(s) in order to identify futurepossible failures caused by the restricted coolant flow.
An economizer tube experiencing acid dew-point corrosion is observed in Figures 22 and23. Inspectors should observe the surface of the suspected acid dew-point corrosion. White or yellowish deposits will be observed on the surface of the tube. Furthermore, iron oxides (rust)may be observed in piles underneath the tubing experiencing acid dew-point corrosion.Inspector s may smell “rotten eggs”, which is also a clear indicator that acid dew-point corrosionis active in a region of the boiler. Final verification of the particular species of active acidshould be sent to a laboratory for analysis. If possible, stack temperatures should be increasedto prevent this type of corrosion.
Figure 24 clearly exhibits signs of fretting corrosion. Inspect areas where contact mayhappen particularly when the boiler is operating at normal operating temperatures. Thematerials will expand, thus increasing the opportunity for fretting to take place. The use of anextendable mirror to observe behind areas normal vision is unable to see is very useful inidentifying fretting corrosion12.
Recommended Inspection Tools/Accessories to be used for Utility Boiler Inspection
This section will identify the recommended inspection tools used by inspectors tothoroughly inspect utility boilers. Table 1 identifies the inspection tools coupled with the abovetechniques that will detect the particular degradation mechanism that could cause a failure anddowntime of a utility boiler to occur.
Figure 25 documents the hard cased box suggested for transporting boiler inspectiontools to the worksite. Plant sites can be harsh environments and a solid-cased inspection boxwill protect the equipment, especially electronic equipment, from being damaged. Figure 26documents the satchel pack carried by boiler inspectors to easily tote the needed tools into theboiler. Important digital documentation devices such as a digital voice recorder and a digitalcamera help inspectors when communicating a possible safety or loss of life issue or asituation that will cause a forced outage before the next planned outage. Figure 27 exhibits anextremely important tool in an inspectors satchel; the ultrasonic thickness test gauge. This toolallows the inspector to give accurate and precise wall thickness readings in areas of interestand removes all guesswork from the inspection process. This tool works best on a smoothsand-blasted OD surfaces, so proper preparation of the boiler tube surface is essential for accurate readings. Figure 28 presents vernier calipers useful for determining the outer diameter of a tube surface. Figure 29 documents a fillet weld gauge. This tool is excellent for measuring the depth of crushes and nicks found on the fireside surfaces of tubes. Figure 30exhibits a tube wall thickness conversion calculator. The reference page allows the inspector to quickly determine what course of action is needed for a wall thickness below specifiedminimum wall thickness. Figure 31 presents an angle locator. The angle locator is used to
verify header location and on some vintages of boilers, the tilt of the burners. Figure 32presents a flexible Pi tape. Pi tapes are used to measure the diameters of headers todetermine if they have swelled, for example, due to creep. Figure 33 exhibits one portion of replication kit used to non-destructively analyze microstructure on high energy piping, typicallyheaders. Replication tools typically consist of a polishing tools kit and a chemical etchant kitthat are transported separately. Another tool that should not be discounted is boiler inspectionsoftware. Figure 34 exhibits an example of a boiler software package system used for maintenance tracking and asset management for both fossil fueled and alternative fueledboilers. These systems enable the user to identify potential tube failures before occurrenceand aid in the development of maintenance strategies for through life management. Improvingavailability, extending unit life, and optimizing capital expenditures are the three coreobjectives of these types of systems. Furthermore, this software also aids management with afoundation for easier and more accurate budgeting and maintenance repair planning.
Proper inspection tools and techniques can help minimize downtime by identifyingdegradation before tube failures occur within power generation utility boilers. Furthermore,these tools can help identify problem areas of the boiler to observe during subsequentoutages. Corrosion and erosion mechanisms active in certain locations of power utility boilerscan be easily and routinely detected by a boiler inspector using the general tools andtechniques outlined in this paper.
ACKNOWLEDGEMENTS
The author would like to express specific appreciation to Dr. David N. French who shareshis knowledge and insight regarding metallurgical failures in fossil fired boilers with us eachday. In addition, the authors express gratitude to the owners and management of David N.French Metallurgists, in supporting the contribution of this paper to NACE and the utility power industry.
FIGURE 7. Circumferential thermal fatigue cracks are observed on the fireside crown of thetube.
FIGURE 8. Thermal fatigue “craze cracking” is observed on the OD surface of a tube due toover-use of a water cannon used to clean slag off tube surfaces.
FIGURE 11. Macroscopic view of photomicrograph samples indicate transgranular cracking inthe heat affected zone (HAZ) of the SA-213-T22 material. This is a typical failure of DMW.
Material is SA-213-T22 to SA-213-304H DMW, 10x, nital etchant.
FIGURE 12. Oxide filled transgranular crack is observed in HAZ of weld. Creep is alsoobserved parallel to weld repair. Material is SA-213-T22 to SA-213-304H DMW, 100x, nital
FIGURE 13. Polished surfaces due to fly ash erosion are observed deep into the superheater bundle.
FIGURE 14. Ash deposits, which clog the gas lanes, are observed during a dirty inspection.This in turn increases the fly ash velocity through the boiler increasing the fly ash erosion
FIGURE 15. Fly ash erosion is observed from the 11:00 o’clock to the 3:00 o’clock position.
FIGURE 16. Wall wastage due to reducing conditions at the burner elevation is observed.
FIGURE 17. Uniform OD surface wastage is observed due to reducing conditions at burner elevation in the water wall tubes. Material is SA-210-A1, 200x. nital etchant.
FIGURE 27 - Ultrasonic thickness tester with ultrasonic coupling medium. Thickness tester documents hard data using ultrasonic technology to determine actual wall thickness of
