Root Cause Industrial Steam Generator Protection: The Importance of On-Line Analytical Instrumentation
Brad Buecker, Senior Technical Consultant, SAMCO Technologies
Posted 7/1/2025
Part 1 of this series examined important issues related to corrosion and scale prevention in steam generators.1 Boiler tube failures and related problems can potentially shut down a unit operation or perhaps even the entire plant. More importantly, some failures can jeopardize employee safety. A critical aspect of a root cause preventive maintenance program is having on-line chemistry instrumentation in place that will alert operators and technical personnel to out-of-spec conditions and allow them to accurately monitor and control chemical feed programs. This article provides an overview of important instruments in that regard, and it includes several case histories from this author’s experience.
Let’s Start at the Beginning: Makeup Water Treatment
In the Wizard of Oz, when Dorothy asked Glenda where to start to reach Oz, Glenda told her, “It’s always best to start at the beginning.” For steam generators, the beginning is the makeup water treatment system. Figure 1 below is a reprise from Part 1. Consider again the low feedwater hardness limits for all cases. The high temperatures in boilers influence mineral solubilities and most notably calcium carbonate (CaCO3), whose solubility decreases and scaling potential grows with increasing temperature. Accordingly, the primary makeup water focus is hardness removal.
For lower pressure steam generators (≤600 psig), a longtime makeup treatment method has been sodium softening.
Grab sample testing for softener effluent hardness has been utilized for decades but grab sampling rarely provides prompt detection of a system upset. Consider the following brief case history of a more advanced monitoring method.
Case History #1
The author once worked at a chemical plant where softened water was required for the primary production process. Even momentary softener upsets would ruin the quality of the finished product. We installed an on-line calcium monitor that instantly alerted the water treatment operators to upset conditions. Modern equipment control programs can be configured to automatically shut down a makeup water unit when analytical instruments detect upsets.
Side Note: Too many cases are known where plant management has instructed operators to continue producing off-spec water or to even bypass malfunctioning softeners and feed raw water to boilers. Such actions can lead to boiler tube failures within days of the event.
Consider another example, which is not boiler related but is extraordinarily energy intensive. It is the requirement for consistent cooling water purity for the copper molds at the inlet of steel mill continuous casters. The casters take molten steel at around 2800oF and produce solid billets and slabs. “Condensate, high-purity boiler feedwater, or low-hardness waters have been used as makeup [to the closed cooling water system]. Hardness levels should never exceed 10 mg/L.”3Any scale formation or fouling in the copper molds and corresponding decrease in heat transfer could lead to molten steel “breakout” from the initial skin that forms on the billet. Breakout can be extremely hazardous and costly. To this author, continuous hardness monitoring appears to be a logical inclusion with other instruments, such as flow, temperature, etc., that keep track of cooling system conditions.
Reverse osmosis (RO) represents a major development for many makeup applications. Unlike sodium softeners, which only take out hardness, modern RO membranes will remove 99+ percent of all dissolved ions. RO systems require conscientious monitoring to maintain system reliability and protect RO membranes. Figure 3 illustrates recommended instrumentation for a system.
Space limitations and a desire to not bore readers to death prevent an in-depth discussion of the instrumentation shown in Figure 3, but listed below are several important details:
- Temperature (T), pressure (P), flow, and specific conductivity (SC) are all critical for RO performance monitoring. These measurements are the primary inputs to a “normalization” program that can track RO performance over time. RO membrane pores shrink and expand with changing water temperatures, which can mask performance degradation due to fouling or scaling. Normalization eliminates that interference. A rule-of-thumb guideline calls for membrane cleaning when normalized performance drops by 10% from baseline.
- Differential pressure across the cartridge filters (CF) is the primary indicator for filter performance and the need for swap-out.
- A sudden increase in permeate specific conductivity suggests a mechanical failure in one of the RO pressure vessels. Some RO units are equipped with a grab sample port on each pressure vessel permeate line. If the permeate SC monitor detects a problem, the operator can sample each pressure vessel and narrow the search to a particular pressure vessel.
- While the RO is in operation, the reject stream valve should never be completely closed, and if that should happen an automatic alarm from the flow meter will alert operators to a no flow condition.
- The schematic includes an online chlorine monitor. Among the oxidizing biocides, chlorine in particular will attack RO membranes. Common is reducing agent feed to remove the oxidizer, with an instantaneous alert if the system malfunctions. An alternative or supplemental measurement is oxidation-reduction potential (ORP).
The key takeaway is that on-line process and chemistry instrumentation is necessary to keep RO systems in good working order.
Another key issue, and this falls into the category of root cause preventive engineering, is that regular raw water sampling and analyses should be initiated at project inception to accurately evaluate raw water chemistry and how it may change during short-term events, e.g., heavy rainfall, or from seasonal influences. Accurate analyses are very important for selecting RO pretreatment equipment and chemical formulations to minimize particulate fouling and scale formation in the membranes. Cases are known where a makeup system had to be replaced shortly after startup because of inaccurate or insufficient raw water analyses that led to incorrect initial design.
The Elephant in the Room, Condensate Return
At many plants, a significant portion of the steam produced for process heating is returned as condensate to the steam generators. Condensate recovery enhances sustainability and reduces the size of the makeup treatment system. Obviously though, the condensate may potentially contain any number of impurities depending on the processes to which the steam provides heating. The following case history is one of many examples of difficulties caused by contaminated condensate.
Case History #2
Years ago, the author and a colleague visited an organic chemicals plant that had four 550-psig package boilers with superheaters. The steam supplied energy to multiple plant heat exchangers, with return of most of the condensate to the boilers. Each of the boiler superheaters was failing every 1.5–2 years from internal deposition and subsequent tube overheating. Inspection of a failed superheater tube bundle revealed deposits of approximately ⅛–¼ inches in depth. Our subsequent walkaround of the boilers revealed foam issuing from the saturated steam sample line of every unit. Past water/steam chemistry analyses performed by an outside vendor included data showing total organic carbon (TOC) concentrations of up to 200 mg/L in the condensate return. Contrast that with the <0.5 mg/L feedwater TOC recommendation from Figure 1. No treatment processes or condensate polishing systems were in place to remove these organic compounds upstream of the boilers. It was not difficult to decipher why steam drum foam formation was probably a constant problem.
Large plants may have many individual condensate return lines, which would prohibit the huge number of online instruments needed to monitor each return stream. Sampling at collection headers or the main feedwater header can provide real-time data for detecting out-of-spec or upset conditions. Grab sampling of individual streams might help pinpoint the contamination source. The following text outlines several measurements, online or grab-sample, that may be valuable, depending on the chemical processes that utilize boiler steam as the energy source.
- pH: Infiltration of acids or bases to condensate influences pH. Furthermore, for makeup systems with only a sodium softener, most of the alkalinity that enters the boiler will be converted by the high temperatures to carbon dioxide. The CO2 leaves the boiler with steam and converts to carbonic acid (H2CO3) in condensate. One technique to minimize corrosion is injection of a neutralizing amine or amine blend (the modern term is “alkalizing amine”) to raise pH. However, a root cause solution is installation of a forced draft decarbonator as shown in Figure 1, or the selection of RO in place of softening.
- S.C.: Specific conductivity provides a surrogate measurement for dissolved solids concentration and often is an indicator of impurity in-leakage. A companion measurement, cation conductivity, provides additional data regarding impurity concentrations and, for high-purity waters where direct pH measurement is difficult, can be combined with specific conductivity into algorithms that provide accurate pH calculations. Additional discussion regarding this pH analytical technique will appear in Part 3 of this series.
- Dissolved oxygen (D.O.) can cause extensive corrosion of both carbon steel and sometimes copper, which we will further examine in the feedwater section below.
- TOC: Organic contamination of condensate is an important issue at refineries, petrochemical plants, and similar facilities. TOC and oil-in-water analyzers are critical items for condensate-return monitoring at these plants. The author once assisted with a troubleshooting project at a plant that was being converted from a liquified natural gas (LNG) import facility to an export facility. Several critical steps are necessary to prepare LNG for liquefaction, all of which require considerable electrical power. The condensate return to the plant’s two combined cycle power units had continuous TOC analyzers to detect leaks from process equipment.
Feedwater
Two critical feedwater monitoring parameters are pH and D.O. Regarding pH, the moderately basic ranges shown in Figure 1 are important for minimizing general corrosion of carbon steel. Alkalizing amines are common for pH control. For feedwater systems containing copper alloys, copper corrosion is minimized towards the lower end of the range, so it may be necessary to adjust chemical treatment as necessary.
As previously noted in Part 1 of this series, feedwater dissolved oxygen removal by mechanical deaeration and chemical oxygen scavenging is critical to protect against the localized corrosion that oxygen can induce. (This narrative has changed dramatically for utility steam generators, which we will review in Part 3.) Accordingly, D.O. measurement at the deaerator outlet (and perhaps other locations in some boilers) is a core parameter to ensure that the deaerator and reducing agent feed system are performing properly.
A major improvement to D.O. monitoring is the development of optical sensor technology.
While older methods such as those based on polarography provide accurate data, maintenance is often time-consuming and tedious. Optical sensors eliminate most maintenance issues.5
Returning to the iron and copper discussion, notice the guidelines in Figure 1. Monitoring is important for two primary reasons. First is to evaluate if treatment programs are doing the job. Second is that steel and copper corrosion products exist mostly as particulates. When the particles reach the boiler, they will precipitate on waterwall tubes as porous deposits. The buildups can then serve as sites for under-deposit corrosion (UDC). The effect becomes magnified at higher temperatures. Copper deposits may also initiate galvanic corrosion.An accurate, albeit not instantaneous, analytical technique is corrosion product sampling (CPS). A CPS unit incorporates both filtration and ion exchange to capture particulate and dissolved metals, which are then analyzed to determine the metal concentrations. Common is to collect a sample for a week or two and then have the filters and ion exchange resin analyzed for results.
These units are equipped with flow totalizers that allow for quick calculation of iron and copper concentrations once the sample weights have been measured.
Boiler Water and Steam
While boiler water guidelines and analytical measurements serve several purposes, the two most important are for pH control and to protect the steam system from excessive impurity ingress. Accordingly, recommended boiler water online analyses include pH and specific conductivity. A common pH range for lower-pressure units is roughly 9-11, but tightens to around 9-10 for high-pressure utility boilers, which we will explore in Part 3. Still common for many drum units is phosphate feed (principally tri-sodium phosphate) for pH control. Online phosphate analysis is a straightforward technology.
The second critical item is minimizing impurity carryover to steam. Even with well-designed and maintained steam separators in the drum, some moisture escapes into the steam. This is known as mechanical carryover, whose percentage increases with increasing pressure. Boiler water specific conductivity offers a reliable measurement to control impurity concentrations with the aid of boiler blowdown. Notice the decreasing specific conductivity with increasing pressure, whose principal goal is to limit impurity carryover such that steam sodium concentrations do not exceed 20 µg/L. (A µg/L is basically equivalent to a part-per-billion.) Sodium compounds, and particularly hydroxide, chloride, and sulfate, are corrosive to turbine blades and rotors. Every steam generator is different, so the general guidelines shown should be refined for every unit, per operating data once the unit is started. Online sodium instrumentation is a mature technology. So is silica monitoring. Silica carries over vaporously with steam and will deposit on steam turbine blades. Although silica is not corrosive, deposition will influence turbine aerodynamics and efficiency. Silica is a common online measurement for high-pressure steam monitoring.
Conclusion
This article touched upon a number of online monitoring techniques that are valuable for steam generator root cause corrosion and scale control. In Part 3 of this series, we will more closely examine online monitoring for utility steam generators, as even seemingly minor impurity ingress may cause major problems in high-temperature, high-pressure boilers and steam systems.
Disclaimer
This article offers general information and should not serve as a design specification. Every project has unique aspects that must be individually evaluated during project design. From those evaluations, comprehensive specifications can be developed. For years, the author reviewed the water treatment and sampling specifications submitted by outside engineering firms for combined cycle power plants. Quite regularly, some instruments would be over-specified, quantity-wise, while others would be under-specified.
References
- Buecker, B., “Boiler Protection – From Corrosion and Scale”; Maintenance World, January 2025.
- 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.
- Flynn, D.J., Ed., The Nalco Water Handbook, Third Edition; 2009, McGraw-Hill.
- Shulder, S., and Buecker, B., “Combined Cycle and Cogeneration Water/Steam Chemistry Control”; pre-workshop seminar for the 40th Annual Electric Utility Chemistry Workshop, June 7, 2022, Champaign, Illinois.
- Mettler Toledo Case Study, “From 400 hours per Year to Zero: Massive Drop in DO Sensor Maintenance, February 2020.
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