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Root Cause Prevention Principles for Boiler Protection from Water-Side Corrosion and Scale Formation

Brad Buecker, Buecker & Associates, LLC

Posted 1/23/2025

Many, many industrial plants and power-generating stations rely on steam as the heat source to drive various processes.  It has been this author’s observations, along with those of numerous colleagues, that managers, operators, and technical personnel at some facilities focus on process engineering and chemistry issues to the neglect of boiler protection; that is until a boiler tube failure or related incident causes shutdown of a unit operation or perhaps even the entire plant.  More importantly, some failures can jeopardize employee safety.  This article provides an overview of several of the most important root cause prevention techniques to minimize corrosion, scaling, and fouling in steam generating systems.  A follow-up piece will outline instrumentation that is vital for these efforts.

Fundamental Principles

Steam generators come in many designs, sizes, and pressures, from small units that only produce low-pressure process steam; to multi-pressure heat recovery steam generators (HRSGs) at combined cycle power plants; to a dwindling number of large coal-fired units.  (This article does not address nuclear power.)  Most boilers are directly fired, but some use waste heat from industrial processes as the energy source.  It is impossible to address the nuances of boiler design in a condensed article such as this, but we can examine important fundamental corrosion/scale control principles that apply to nearly all configurations.  As a primary guide, we will use Figure 1 below, which illustrates the recommended control ranges for the very common “water tube with superheater” boiler design.

Minimizing Condensate/Feedwater General Corrosion

The standard material of construction for boiler feedwater piping and main boiler components, i.e., drums, tubes, headers, etc., is mild carbon steel.  Iron is an amphoteric material, meaning that it will corrode at both low and high pH.  Thus, it is important to select steam generator water treatment methods that maintain pH within a “sweet spot” to minimize corrosion.  

Figure 1.  Data extracted from Table 1, Reference 1 – “Suggested Water Chemistry Targets Industrial Water Tube with Superheater” (This resource should be in the library of any industrial plant with steam boilers.)

Initially, let’s consider two items from the “Feedwater” section of the table, the first being the moderately basic pH ranges recommended for feedwater (and by extension boiler water), and second, that these ranges narrow with increasing pressure.  A reliable and redundant chemical feed system is necessary for continuous feedwater pH control.  While a number of chemical compounds can do the job, several volatile chemicals (ammonia or perhaps one of the small-chain “alkalizing amines”) are the common choice.  The volatile aspect of these compounds is very important because in many steam generators, and especially larger units including utility boilers, a small portion of the feedwater is extracted for steam temperature attemperation.  Non-volatile alkalis such as sodium hydroxide are a no-no for feedwater pH conditioning in these units, as the caustic can cause prompt and severe damage in steam systems.

Equation 1 illustrates the influence of ammonia on pH.

NH3 + H2O ⇌ NH4+ + OH     Eq. 1

Modern control technology allows automatic feed to maintain pH within recommended ranges.  Data output from accompanying on-line analytical instruments can be configured to alert plant personnel or outside consultants to feed system upsets.

Feedwater pH control guidelines for high-pressure power units can be more complex than those shown in Figure 1.  Consider, for example, the triple-pressure HRSG design that is common for many combined cycle power plants.  The pH control guideline for each individual feedwater circuit, and evaporator, i.e., boiler, circuit for that matter, may be slightly different than the others to optimize corrosion control.  Reference 2 provides further details.  (This document, along with other guidelines from the International Association for the Properties of Water and Steam, can be freely downloaded from the IAPWS website.)  Reference 2 also addresses the recommended feedwater pH range for units that contain copper alloys in the system.  A narrower range of 9.1-9.3 represents a compromise between the corrosion sweet spots of the steel and copper alloys.  Many of the large coal-fired units constructed in the last century had (some still have) feedwater heaters tubed with copper alloys.  Most combined cycle HRSGs do not have feedwater heaters and no copper alloys, thus copper corrosion concerns become moot for these units. 

Dissolved Oxygen Issues

Closely linked to feedwater pH control is dissolved oxygen (D.O.) corrosion mitigation.  Uncontrolled D.O. can cause severe localized attack.

Figure 2. Oxygen corrosion of a carbon steel feedwater line.  Photo courtesy of ChemTreat.

Accordingly, almost all steam-generating systems are equipped with a mechanical deaerator.  

The two common styles of deaerator are spray type and tray type, with the latter being more popular.


Figure 3.  Schematic of a tray-type deaerator.  Illustration courtesy of ChemTreat.

Under normal operating conditions, a properly operating deaerator should be able to reduce the D.O. concentration to the 0.007 mg/L (7 parts-per-billion (ppb)) guideline shown in Figure 1.  D.O. excursions in the deaerator outlet sample indicate a problem within the deaerator compartment.  Common issues include:

  • Misaligned or missing trays
  • Damaged or malfunctioning spray nozzles
  • Inhibited steam admission
  • Incorrect deaerator vent valve settings

Correct preventive maintenance requires regular inspection, and repair, if necessary, of this equipment.  The storage tank also requires inspection, as issues related to weld cracking are known.  

Even though a deaerator can reduce D.O. concentrations to 7 ppb, this level is still often considered to be excessive.  Chemical treatment with an oxygen scavenger/reducing agent is a supplement to mechanical deaeration.  For simple industrial boilers, a common oxygen scavenger is sodium sulfite (Na2SO3), which is suitable in many units up to 600 psi or so in pressure.  The fundamental chemistry is:

Sulfite should not be utilized in steam generators that provide attemperating water to steam, as this will lead to direct introduction of non-volatile solids to the steam system.  Another issue is sulfite decomposition. Some literature suggests that sulfite may be employed at boiler pressures up to 900 psi, but at the higher temperatures in such units, sulfite may break down to produce hydrogen sulfide (H2S) and acid. These products can cause significant damage to boiler metal. 

For high-pressure boilers, and most notably power units, hydrazine (N2H4) was once the primary feedwater reducing/metal passivating agent. The breakdown products of residual hydrazine are ammonia and water, so neither the hydrazine nor its decomposition products introduce non-volatile solids to the feedwater or steam.  However, hydrazine is now rarely used as it is considered a carcinogen.  A very common replacement is carbohydrazide (CH6N4O), which is safe to handle but then breaks down to hydrazine as temperatures increase in the feedwater system.  Other alternative scavengers are also available.

An important point that I can only touch upon briefly here is that for high-pressure utility steam generators with high-purity makeup water and no copper alloys in the feedwater system, feedwater treatment programs have emerged where a small concentration of D.O. is necessary for carbon steel corrosion protection.  (These programs may necessitate closing of deaerator vents. 3)  The chemistry mitigates the phenomenon of flow-accelerated corrosion (FAC).  Since 1986, FAC-induced failures have killed and injured a number of power plant personnel at facilities around the country.  Detailed information about FAC and oxygenated feedwater chemistry is available in References 2 and 4, and this author summarized many important points in Reference 5.

A critical issue to remember regarding feedwater treatment system selection and operation is that programs must minimize direct attack of the metal and the attendant carryover of corrosion products to the boiler.  Iron oxide particulates will form porous deposits on boiler tubes that serve as sites for localized corrosion.  Some localized mechanisms can cause boiler tube failures within weeks or even days in combination with chemistry upsets, an example of which is outlined in the next section.  

Protecting the Boilers

The boiler, in whatever configuration, is obviously the location of the primary energy input.  Corrosion and scaling reactions are accentuated in the high-temperature environment.  Let’s look at some fundamental preventive water treatment methods to minimize problems.

Referring again to Figure 1, note the low feedwater hardness (calcium and magnesium) guidelines for all situations, and especially for high-pressure units.  The influence for such low hardness limits is scale control, where the chief, but by no means exclusive, culprit is calcium carbonate (CaCO3). 

CaCO3 has a low solubility to begin with, which is exacerbated by increasing temperature, as Equation 3 and the following photo illustrate. Chronic minor upsets can be enormously damaging as well.

Figure 4.  Layered CaCO3 deposits in a boiler tube from chronic softener upsets.  Photo courtesy of ChemTreat.

Boiler tubes often cannot survive scale formation such as that shown in Figure 4, as the insulating effect of deposits will cause overheating failures.  At the least, deposition requires harder boiler firing, which, of course, raises fuel consumption and cost.

Figure 5.  General influence of deposits on boiler tube wall temperatures.  Illustration courtesy of ChemTreat.

This discussion leads to a key takeaway from this article.  This author has directly seen (and has had numerous confirmations of other incidents from colleagues) situations in which a plant’s makeup water treatment system is performing poorly, but where management directs operators to continue sending makeup to the boilers.  This “water is water, just keep the boiler on” philosophy has led to steam generator failures that have incurred six, seven, and even eight figure costs when repairs and lost production are considered.  So, the importance of a properly designed and conscientiously operated/maintained makeup water treatment system is a root cause preventive priority.  For low-pressure boilers, ion exchange sodium softening is common, per operation within the alkalinity and specific conductance (a surrogate for total dissolved solids) limits shown in Figure 1.  Softening systems are often equipped with a downstream forced draft decarbonator or dealkalizer to remove most of the bicarbonate alkalinity (HCO3) from the makeup.  At boiler water temperatures much of this alkalinity can decompose, releasing CO2.  The carbon dioxide exits with steam but then redissolves in condensate to produce carbonic acid (H2CO3).  While this acid is relatively weak, it can still cause significant carbon steel damage.

Figure 6. Carbonic acid grooving of a condensate return line.  Photo courtesy of ChemTreat.

For high-pressure power boilers, more stringent makeup water treatment is necessary.  A common core configuration nowadays is reverse osmosis (RO) followed by ion exchange (IX) polishing to reduce impurity concentrations to low ppb levels.  

Damaging impurities can also enter boilers apart from makeup system upsets.  At power plants, the most frequent source is the steam surface condenser (unless the unit has an air-cooled condenser).  A tube leak(s) allows direct infiltration of cooling water into the condensate, which of course directly travels to the boiler.  Impurities such as chloride and sulfate can concentrate under boiler tube deposits and induce localized corrosion.  Severe upsets have been known to cause tube failures within weeks and even days.  The primary preventive and important measure for corrosion mitigation is to equip the condensate/feedwater system with on-line analytical instrumentation that can immediately detect upsets and alert the plant staff.  Some personnel should be given the needed training and authority to shut the unit down as soon as possible for repairs.  From my own experience, it was often possible to shut down the unit just for the time to identify the leaking tube and plug the inlet and outlet ends.  A long-term outage was not necessary.

Industrial plants may have multiple condensate-return streams that can introduce a variety of impurities to the boilers.  Depending on the contaminants in the return condensate, preventive measures may include installation of particulate filters, activated carbon units, or ion exchange systems.  Careful evaluation is important to determine the best arrangement.  It may be that no method is effective and that condensate dumping to the plant’s wastewater treatment facility is necessary during upset conditions.

Direct Boiler Water Treatment

As with feedwater systems, boiler water pH control is quite important.  The optimal control ranges are similar to feedwater, but can be a bit more variable depending on boiler type and configuration.  

As drum boiler technology evolved in the early 20th century for power production and other industrial applications, plant operators and technical personnel were confronted not only with pH control issues but with difficulties related to hardness ingress from what were rudimentary makeup treatment techniques.  In the 1930s, tri-sodium phosphate (Na3PO4) boiler water treatment evolved to provide the needed boiler water alkalinity. 

Tri-sodium phosphate (TSP) and related species would also react with hardness ions to form soft sludges that could be removed via the boiler blowdown.  An additional benefit of phosphate chemistry is that it can mitigate, at least temporarily, the acidic conditions that ions such as chloride and sulfate can generate underneath boiler tube deposits.  Such localized corrosion has been known to cause rapid boiler tube failures.  This author, along with colleagues, once directly with an incident where a condenser leak on a relatively low pressure (1,250 psi) utility boiler caused severe hydrogen damage that required an entire boiler retubing.  Needless to say, costs for materials, labor, and replacement power were exorbitant.  The silver lining was that it opened the eyes of managers who had the “water is water” mindset.  

Phosphate programs have undergone numerous twists and turns over the last century, whose details are beyond the scope of this article.  However, phosphate treatment is still common, and I would be pleased to discuss the chemistry in greater depth with interested readers.

A Brief Note About a (Relatively) Modern Development

A treatment method that has received new life in the last two decades or so, and which has a definite preventive flavor, is based on film-forming chemistry.  Several compounds exist, whose fundamental molecular structure is a long-chain organic string (perhaps 18 carbon atoms or thereabouts) with one or two active groups placed on one end of the chain.  The active groups attach to the metal surface, and the tail of the molecules forms a protective barrier.  These treatments are becoming more popular in power and industrial applications, but success stories are not universal, particularly for those who think the chemistry is a panacea for all issues and that they can ignore the treatment methods outlined above.  An additional benefit touted by product developers is that the film stays intact during unit shutdown, which offers protection during off-line periods.  Offline corrosion protection is very important, which I hope to address in a later article.  A drawback of these organic molecules is that they can potentially decompose in high-temperature steam circuits to form organic acids and carbon dioxide.  These compounds can influence condensate chemistry and induce corrosion in downstream equipment such as turbines and condensate return systems.

Conclusion

This article touched upon several very important root cause preventive techniques, based on fundamental principles, for protecting industrial and power steam generating systems.  Steam generation is the heart of many processes, but often plant personnel neglect boiler care until an outage disrupts plant operations.  Repair and lost production costs are usually much greater than preventive costs.


 References

B. Buecker, “HRSG issues: Reemphasizing the importance of FAC corrosion control – Parts 1-4”, 2023, accessible on the Power Engineering website in the O&M/Water Treatment section.

Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers, The American Society of Mechanical Engineers, New York, NY, 2021.

International Association for the Properties of Water and Steam, Technical Guidance Document: Volatile treatments for the steam-water circuits of fossil and combined cycle/HRSG power plants (2015).

J.B. Smith and D.M. Craven, “Supplemental Oxygen for All-Volatile Treatment under Oxidizing Conditions”; PPCHEM Journal, 2024, Vol. 6.

Guidelines for Control of Flow-Accelerated Corrosion in Fossil and Combined Cycle Power Plants, EPRI Technical Report 3002011569, the Electric Power Research Institute, Palo Alto, California, 2017.


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Brad Buecker

Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as a senior technical publicist with ChemTreat, Inc. He has many years of experience in or supporting the power industry, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, IL, USA) and Kansas City Power & Light Company's (now Evergy) La Cygne, KS, USA, station. His work has also included eleven years with two engineering firms, Burns & McDonnell and Kiewit, and he spent two years as acting water/wastewater supervisor at a chemical plant.

Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. He has authored or co-authored over 250 articles for various technical trade magazines, and has written three books on power plant chemistry and air pollution control. He is a member of the ACS, AIChE, AIST, ASME, AWT, the Electric Utility Chemistry Workshop planning committee, and he is active with the International Water Conference and Power-Gen International.

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