Time and again, the authors have reviewed new power project specifications in which the plant designers routinely select 304 or 316 stainless steel as the tube material for condensers and auxiliary heat exchangers. To many, the term stainless steel conjures up an aura of invincibility to corrosion, when in fact stainless steels can sometimes be the worst choice because of their susceptibility to localized attack. And, in this era of diminishing fresh water availability for cooling water makeup, combined with cooling towers that operate at high cycles of concentration, potential stainless-steel failure mechanisms are magnified. In some applications, the 300-series stainless steels have survived for just months, and at times only weeks, before failing. This article highlights issues, primarily from a water treatment perspective, that should at least be considered when selecting condenser tube materials. Other factors not discussed in this article but that play a part in materials selection include material strength, heat transfer properties, and resistance to mechanical forces including fatigue and erosion-corrosion.
The addition of 12 percent or greater chromium to steel induces the alloy to form a continuous oxide layer that protects the underlying base metal. Thus, the term stainless. In the absence of other alloy materials, most notably nickel, the carbon steels are part of the ferrite group, whose unit cells have a body-centered cubic (BCC) structure.
When nickel at 8 percent concentration or greater is added to the alloy mix, the unit cells, even at ambient temperature, exist in a face-centered cubic (FCC) structure known as austenite.
As Table 1 illustrates, the 300-series stainless steels and others have the nickel content to produce the austenitic structure.
Austenitic steels have proven to be very valuable in many applications, including as materials for high-temperature superheater and reheater tubes in power boilers. The 300-series in particular has commonly served as the materials for lower-temperature heat exchanger tubes, including for steam surface condensers. But, it is in these applications that many people lose sight of potential failure mechanisms.
The primary difficulty with stainless steels, and particularly the popular 304 and 316 materials, is that frequently the protective oxide layer can be disrupted by impurities in the cooling water and by the presence of crevices and deposits that help to concentrate impurities. Furthermore, during shutdown conditions, standing water allows for microbiological growth, whose metabolic byproducts can be highly damaging to metals.
Chloride – The 800 Pound Gorilla in the Room
A common cooling water impurity, which is among the most difficult to economically remove, is chloride. This ion can cause many problems in a steam generator, but in condensers and auxiliary heat exchangers the chief difficulty is that in sufficient concentration chloride will penetrate and disrupt the protective oxide layer on stainless steel to induce localized corrosion, i.e., pitting.
Pitting is one of the most insidious forms of corrosion, as it can cause through-wall penetration and equipment failure with very little metal loss.
The concentration of chloride does not have to be great to induce pitting of 304 and 316 stainless steels, and the recommended maximum chloride concentration for clean surfaces without any deposits or crevices is now considered to be:
- 304 SS – 150 mg/l
- 316 SS – 400 mg/l
There are several factors that can easily generate chloride concentrations in excess of these guidelines, either in general or at localized spots. First consider that once-through cooling for new power plants has become very rare. Most are being built with cooling towers, or in some cases, air-cooled condensers (ACC). For those with cooling towers, the impurities in the makeup are “cycled up” in concentration. For example, a tower with a makeup water chloride concentration of 50 mg/l that operates at five cycles of concentration would have 250 mg/l of chloride in the circulating water. That alone should usually eliminate 304 SS from consideration. Furthermore, at both new and existing plants alternatives to fresh water for plant makeup are increasingly being required. One common alternative is municipal wastewater effluent. Table 2 offers a comparison of analyses from four fresh water supplies vs four wastewater supplies.
Notice the increased levels of chloride (and other impurities such as nitrogen species and phosphorus, which can greatly enhance microbiological fouling in cooling systems). For essentially all of the grey waters, any cycling up in a cooling tower would exceed the recommended chloride limit for 316 SS.
The preceding discussion was based on corrosion potential of plain metal surfaces. Crevices and deposits alter the story dramatically, as both offer locations where impurities can concentrate. Typical locations for mechanical crevices in condensers and similar heat exchangers are at tube to tube-sheet joints. Deposition within tubes will generate crevices at the deposit boundaries, plus the deposits themselves can serve as sites for impurity concentration. In addition, because stainless steels depend upon a continuous oxide layer for protection, deposits can establish oxygen-depleted locations that become anodic to the remaining steel surface.
The above-mentioned discussion outlines issues that plant designers often do not consider when specifying condenser and auxiliary heat exchanger tube materials for new projects. The mindset regarding 304 and 316 SS sometimes still seems to be “That’s the way we’ve always done it” without regard to the consequences of such actions. Alternative materials are available to handle the tougher cooling water conditions that many plants now face.
One other point must be briefly addressed before discussing alternative metals. There have been many instances where 316 SS and even 304 SS have performed well during normal operation, but then have failed during outages. In most cases, failures are due to poor draining of the condenser or heat exchanger that allows standing water to stagnate in the tubes. This environment provides ideal conditions for microbiological growth. The microbial colonies in turn produce corrosive compounds that will directly attack the tube metal.
This mechanism, termed microbiologically-induced corrosion (MIC), has been known to destroy stainless steel tubes, and other metals for that matter, within weeks. If the heat exchanger cannot be drained, then serious thought should be given to circulating water through the exchanger on a regular basis with biocide feed during the process. (More details on proper layup procedures may be found in D. Janikowski, “CONDENSER AND BOP EXCHANGER LAYUP – Do’s and Don’ts”; presented at the 39th Annual Electric Utility Chemistry Workshop, June 4-6, 2019, Champaign, Illinois.)
For the tough environments highlighted above, and for even more aggressive environments such as brackish water or seawater, alternative metals are available to withstand the impurities. Three alloy groups have proven successful, commercially pure titanium, the 6% molybdenum austenitic stainless steels, and the super-ferritic stainless steels. These alloys are also resistant to MIC. Although titanium is considered to be very resistant to corrosion, its hexagonal-close-packed crystal structure and very low modulus of elasticity make it susceptible to mechanical damage. This alloy is best utilized in new units that have a robust tube support structure. An excellent alternative is the super-ferritic stainless steel, Sea-Cure®. The composition of this material is shown below.
The steel has a high chromium content, but low nickel such that it is a ferritic rather than an austenitic stainless steel. With its low nickel content, it can have a significantly lower cost than other alloys. Sea-Cure’s high strength and modulus of elasticity allow for thinner walls than for other materials, resulting in improved heat transfer.
The enhanced performance of these metals is shown in the chart of “Pitting Resistance Equivalent Number”, which was a test procedure developed to determine, as the name implies, the resistance of various metals to pitting.
What are the Maximum Chloride Levels we can use?
One of the most common questions asked is “What is the maximum chloride level that can be tolerated for a particular grade of stainless steel?” The answer varies considerably. Factors include pH, temperature, presence and type of crevices, and potential for active biological species. A tool is added on the right axis of Figure 5 to help in this decision. It is based upon having a neutral pH, 35-degree centigrade flowing water (to prevent deposits from building and forming crevices) common in many BOP and condensing applications. Once an alloy with a particular chemistry is selected, the PREn can be determined and then intersected with the appropriate sloped line. The suggested maximum chloride level can then be determined by drawing a horizontal line to the right axis. In general if an alloy is being considered for brackish or seawater applications, it needs to have a CCT above 25 degrees Centigrade measured by the G 48 test.
When using this guide, additional caveats need to be considered:
- If the temperature is higher than 35 centigrade, the maximum chloride level should be lowered.
- If the pH is lower than 7, the maximum chloride level should be lowered.
- This guide is based upon having a clean surface. If deposits are allowed to form, the pH can be significantly lower under the deposits, and the chloride levels may be much higher than the bulk water.
As is evident, the super-ferritic alloys, exemplified by Sea-Cure®, are usually suitable for even seawater applications. There is also another benefit to these materials that must be highlighted. Issues with manganese corrosion of 304 and 316 SS have been observed for years, including plants along the Ohio River. More recently, heat exchangers at plants along the Mississippi and Missouri rivers have been attacked. Manganese corrosion is also a common problem in systems supplied by well water makeup. The corrosion mechanism has been identified as reaction of manganese dioxide (MnO2) with oxidizing biocides that creates hydrochloric acid under the deposit. HCl is what actually attacks the metal. [W.H. Dickinson and R.W. Pick, “Manganese-Dependent Corrosion in the Electric Utility Industry”; presented at the NACE Annual Corrosion Conference 2002, Denver, Colorado.] The ferritic steels are resistant to this corrosion mechanism.
Even with Materials Upgrades Don’t Neglect Proper Water Treatment Chemistry
Selecting higher grade materials for condenser and heat exchanger tubes is still not a substitute for proper water treatment chemistry control. As author Buecker has outlined in previous Power Engineering articles, correctly designed and operated chemical treatment programs are necessary to minimize the potential for scale, corrosion, and fouling. Polymer chemistry is emerging as a strong replacement for the old phosphate/phosphonate chemistry to control corrosion and scaling in cooling tower systems. Control of microbiological fouling has, and will remain, a critical issue. While oxidizing chemistry with chlorine, bleach, or similar compounds is a cornerstone for microbiological control, supplemental treatments often can improve the efficiency of treatment programs. One such example is stabilizing chemistry that helps to improve the release rate and efficiency of chlorine-based oxidizing biocides, without introducing any hazardous compounds to the water. Also, supplemental feed of a non-oxidizing biocide may be quite beneficial in controlling microbial development. The upshot is that a number of methods are available to improve the sustainability and reliability of power plant heat exchangers, but every system is different and thus careful planning and consultation with industry experts is important for selection of materials and chemistry programs. This article is in large part written from a water treatment perspective, where we are not involved in materials decision making, but are called upon to help manage the impact of those decisions once the unit is up and running. The final decision on materials selection must be made by plant personnel per a number of factors that each application dictates.
About the author: Brad Buecker is senior technical publicist with ChemTreat. He has 36 years of experience in or affiliated with 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, Illinois) and Kansas City Power & Light Company’s La Cygne, Kansas station. He also 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.
Dan Janikowski is technical manager with Plymouth Tube. He has been involved in metals development, and manufacturing and testing of tubular products including copper alloys, stainless steels, nickel alloys, titanium, and carbon steels for over 35 years. Having been with Plymouth Tube since 2005, Janikowski has held various senior-level positions before becoming technical manager in 2010.