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Austenitic Stainless Steel
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Basic Weld Inspection - Part 2
Black Liquor Recovery Boilers - An Introduction
Boiler Efficiency and Steam Quality: The Challenge of Creating Quality Steam Using Existing Boiler Efficiencies
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Boiler/Burner Combustion Air Supply Requirements and Maintenance
Carbon Monoxide Poisoning Preventable With Complete Inspection
Combustion Air Requirements:The Forgotten Element In Boiler Rooms
Creep and Creep Failures
Description of Construction and Inspection Procedure for Steam Locomotive and Fire Tube Boilers
Ensuring Safe Operation Of Vessels With Quick-Opening Closures
Environmental Heat Exchangers
Factors Affecting Inservice Cracking of Weld Zone in Corrosive Service
Failure Avoidance in Welded Fabrication
Finite Element Analysis of Pressure Vessels
Fuel Ash Corrosion
Fuel Firing Apparatus - Natural Gas
Grain Boundaries
Heat Treatment - What Is It?
How to Destroy a Boiler -- Part 1
How to Destroy a Boiler -- Part 2
How to Destroy a Boiler -- Part 3
Identifying Pressure Vessel Nozzle Problems
Inspection, Repair, and Alteration of Yankee Dryers
Inspection, What Better Place to Begin
Laminations Led to Incident
Lay-up of Heating Boilers
Liquid Penetrant Examination
Low Voltage Short Circuiting-GMAW
Low Water Cut-Off Technology
Low-Water Cutoff: A Maintenance Must
Magnetic Particle Examination
Maintaining Proper Boiler Inspections Through Proper Relationships
Microstructural Degradation
Miracle Fluid?
Organizing A Vessel, Tank, and Piping Inspection Program
Paper Machine Failure Investigation: Inspection Requirements Should Be Changed For Dryer Can
Pipe Support Performance as It Applies to Power Plant Safety and Reliability
Polymer Use for Boilers and Pressure Vessels
Pressure Vessel Fatigue
Pressure Vessels: Analyzing Change
Preventing Corrosion Under Insulation
Preventing Steam/Condensate System Accidents
Proper Boiler Care Makes Good Business Sense:Safety Precautions for Drycleaning Businesses
Putting a Stop to Steam Kettle Failure
Quick Actuating Closures
Quick-Actuating Door Failures
Real-Time Radioscopic Examination
Recommendations For A Safe Boiler Room
Recovering Boiler Systems After A Flood
Rendering Plants Require Safety
Repair or Alteration of Pressure Vessels
Residential Water Heater Safety
School Boiler Maintenance Programs: How Safe Are The Children?
Secondary Low-Water Fuel Cutoff Probe: Is It as Safe as You Think?
Short-Term High Temperature Failures
Specification of Rupture Disk Burst Pressure
Steam Traps Affect Boiler Plant Efficiency
Steps to Safety: Guide for Restarting Boilers After Summer Lay-Up
Stress Corrosion Cracking of Steel in Liquefied Ammonia Service - A Recapitulation
Suggested Daily Boiler Log Program
Suggested Maintenance Log Program
System Design, Specifications, Operation, and Inspection of Deaerators
Tack Welding
Temperature And Pressure Relief Valves Often Overlooked
Temperature Considerations for Pressure Relief Valve Application
The Authorized Inspector's Responsibility for Dimensional Inspection
The Effects of Erosion-Corrosion on Power Plant Piping
The Forgotten Boiler That Suddenly Isn't
The Trend of Boiler/Pressure Vessel Incidents: On the Decline?
The Use of Pressure Vessels for Human Occupancy in Clinical Hyberbaric Medicine
Thermally Induced Stress Cycling (Thermal Shock) in Firetube Boilers
Top Ten Boiler and Combustion Safety Issues to Avoid
Typical Improper Repairs of Safety Valves
Wasted Superheat Converted to Hot, Sanitary Water
Water Maintenance Essential to Prevent Boiler Scaling
Water Still Flashes to Steam at 212
Welding Consideration for Pressure Relief Valves
Welding Symbols: A Useful System or Undecipherable Hieroglyphics?
What is the Best Welding Process?
What Should You Do Before Starting Boilers After Summer Lay-Up?
Why? A Question for All Inspectors

Fuel Ash Corrosion

David N. French, Sc.D.
President of David N. French, Inc., Metallurgists, Northborough, MA

Fall 1992  

Category: Operations 


Summary: The following article is a part of National Board Classic Series and it was published in the National Board BULLETIN.  (4 printed pages)



All fossil fuels, with the possible exception of natural gas, contain constituents that will promote corrosion on the fire side of boiler components. The "bad actors" are compounds of sulfur, vanadium and sodium; but in the case of municipal-refuse boilers, chlorine is an increasing concern. There are three temperature regimes where fire-side corrosion occurs:


  1. Less than 300oF. Dew-point corrosion occurs when sulfuric acid condenses.


  2. 500o-750oF. Waterwall-tube corrosion occurs in coal-fired units by the formation of pyrosulfates of sodium and potassium. In refuse-fired boilers, mixtures of chlorides of zinc, lead, iron and sodium are the likely causes of corrosion.


  3. Temperatures greater than 1000oF. The cause of superheater and reheater ash corrosion depends on the fuel. The corrosive species are different for coal and oil-fired boilers. Mixtures of vanadium pentoxide and sodium oxide or vanadium pentoxide and sodium sulfate are the principal offensive compounds in oil ash. For coal-fired boilers, sodium and potassium iron trisulfates are the liquid species blamed for high-temperature corrosion.


The combustion of most fossil fuels, natural gas being one exception, produces flue gases that contain sulfur dioxide, sulfur trioxide and water vapor. At some temperature, these gases condense to form sulfurous and sulfuric acids. The exact dew-point depends on the concentration of these gaseous species, but it is around 300o F. Thus surfaces cooler than this temperature are likely locations for dew-point corrosion. Any point along the flue-gas path, from combustion in the furnace to the top of the chimney, is a possible site. Any flue-gas leak can also cause this type of corrosion. The obvious locations are openings to the furnace, support penetrations through the roof, leaks around superheater, reheater and economizer penetrations, and, of course, the air preheater.

In boiler terminology, "acid dew-point" refers to the sulfuric-acid dew-point, as this is the highest dew-point temperature. Both sulfurous acid and hydrochloric acid condense at lower temperatures. For hydrochloric acid, the dew-point may be as low as 130oF. While the precise dew-point for sulfuric acid depends on the sulfur-trioxide concentration, at 10 parts per million sulfur trioxide in the flue gas, the dew-point is 280o F.

Dew-point corrosion is exacerbated in coal-fired boilers by the presence of fly ash. Fly ash accumulates throughout the flue-gas path, and the resultant deposit acts like a sponge to collect both moisture and acid, especially during shutdown cycles.

One other corrosion problem associated with oil ash is the potential for acid corrosion following water washing. While strictly speaking this is not a dew-point corrosion, a solution of oil ash in water does result in an acid p H. Thus, unless these salts are neutralized, a strong acid forms in the wash water just before it evaporates to dryness. To prevent fireside pitting corrosion during water washing, the final rinse should be a basic solution. The most common and least expensive is washing with soda (sodium carbonate) dissolved in water. Such a solution will neutralize the acids in the oil ash and prevent pitting.


Carbon and alloy steels develop corrosion resistance from the formation of protective oxide scales. The more dense and tightly bound the oxides are, the more corrosion resistant the material will be. Any process that removes the oxide will promote more rapid corrosion wastage. Any process that prevents the formation of these oxides will also promote more rapid corrosion. Fly-ash and soot-blower are not by themselves corrosive, but both remove the protective iron-oxide layer. The cleaned steel is then exposed to the high temperature flue-gas environment, and an oxide film reforms. The oxide forms by converting steel to scale, and a little metal is lost. Each cycle of scale formation and removal reduces the wall thickness until the boiler tube is too thin to contain the fluid pressure, and failure occurs. The actual cause of the wastage is the rapid oxidation of clean, unprotected steel.

Whether the fuel burned is oil or coal, and whether the corrosion location is in the furnace (at temperatures of 500o-700oF) or the high-temperature components (at a metal temperature above 1,000o F), the corrosion mechanisms are similar. Constituents within the ash form a low-melting-point species or a mixture of several compounds that has the required low melting point. These low-melting-point species dissolve the protective iron oxide on the surface of the boiler tube and bring the bare metal in contact with oxygen. Two observations: a) the melting point discussed here is not the ash fusion temperature, and b) the action of these liquids is like a brazing flux; it dissolves and prevents the formation of a protective oxide film.

In the case of furnace-wall corrosion, mixtures of sodium and potassium pyrosulfates are the suspected liquid species. Melting points between 635o and 770oF have been reported for ash constituents on furnace walls under severe coal-ash corrosion. For corrosion of superheaters and reheaters at temperatures above 1000oF in coal-fired boilers, sodium- and potassium-iron trisulfates are the culprits. The exact melting point depends on the relative amounts of sodium and potassium, but the minimum melting point can be as low as 1030oF. In oil-fired boilers,mixtures of vanadium pentoxide and sodium oxide or vanadium pentoxide and sodium sulfate are the problem. Again, the precise composition will dictate the particular melting point, but these compounds can melt at temperatures as low as 950o F.

In municipal-refuse burners where appreciable chlorine, from polyvinyl chloride, is part of the fuel, various chlorides or mixtures of chlorides will serve the same purpose. Mixtures of iron, sodium, zinc, lead, and perhaps calcium chlorides will form low-melting-point species. There are many combinations of chlorides that have melting points below 600oF and some less than 350o F.

Reducing conditions will exacerbate fuel-ash corrosion. 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. Sulfides tend 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 during oxygen-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.

The morphology or appearance of fuel-ash corrosion is variable. For superheater or reheater tubes in an oil-fired boiler, the corrosion pattern depends on the volume of liquid and the aerodynamics of the flue-gas flow over the tube. In coal-fired boilers, the appearance takes the form of a series of grooves and is sometimes referred to as "alligator hide."

For waterwall tubes, 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 wall thickness is not substantially different from the cold or casing side. The wall thickness at the tip of the crack can, of course, be thin enough to form a steam leak.

In the case of a refuse burner, the appearance is one of a smooth and uniform wastage that reduces the wall thickness. Corrosion rates can be exceedingly high. Carbon-steel wastage rates of about 1/2 inch per year (failure in less than 2,000 hours of operation) are known.

The formation of "alligator-hide" appearance in superheaters and the circumferential grooving in furnace-wall tubes are related and develop by the same kind of mechanism. A liquid phase forms from constituents within the coal ash. The strength of the liquid layer between the ash and the tube is weak. When the ash layer builds to a particular thickness, the film of liquid can no longer support the weight, the ash layer falls off exposing the bare tube to the fire, and the local heat flux jumps. This sudden rise in heat flux means a sudden rise in temperature and creates a locally high stress. As the ash layer reforms, the insulating effect of the ash reduces the metal temperature. Over several (or many) such cycles, corrosion-fatigue cracks form. The difference between the "alligator-hide" appearance on superheater tubes and circumferential grooving on waterwall tubes is the magnitude of the heat flux and temperature spike. For superheaters, the peak heat flux is perhaps 1/4 -1/3 that of a furnace wall in the highest heat-release regions. In the case of a stoker-fired, municipal-refuse boiler, the heat flux is not high enough to lead to a temperature spike, so the corrosion proceeds in a uniform fashion.

In summary, the three temperature regimes of fire-side corrosion are: less than about 300oF, where sulfuric acid dew-point corrosion occurs, 500o - 750oF on furnace walls, and greater than 1000o F on superheater and reheater tubes. Even though the temperature regimes are quite different, the mode of corrosion is similar for furnace walls and superheaters. A liquid phase forms on the surface of the tube from constituents within the fuel, dissolves the protective iron oxide (similar to a brazing flux), and leads to more rapid corrosion. Under reducing conditions, protective iron oxides do not form as readily, and the result is the formation of a porous iron sulfide that is inherently less protective.



Editor's note: Some ASME Boiler and Pressure Vessel Code requirements may have changed because of advances in material technology and/or actual experience. The reader is cautioned to refer to the latest edition of the ASME Boiler and Pressure Vessel Code for current requirements.


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