Introduction

In previous Power Engineering articles, we examined the importance of trace iron monitoring to determine the extent of carbon steel corrosion in heat recovery steam generator (HRSG) condensate and feedwater circuits. ^{(1, 2)} HRSG feedwater systems typically contain no copper alloys, except perhaps rarely a condenser with copper alloy tubes. However, cogeneration and large industrial steam systems may have numerous heat exchangers containing copper alloy tubes.

Accordingly, both iron and copper monitoring of condensate are important for evaluating the efficacy of chemical treatment programs in minimizing corrosion and the secondary effect of corrosion product transport to steam generators. In this article, we will briefly revisit several important aspects of steam generator condensate/feedwater iron analyses. We will also examine why copper monitoring is needed at cogeneration facilities, along with modern analytical methods for trace metal analysis.

Some background history

During the age of large fossil plant construction in the middle of the previous century, the condensate/feedwater network typically contained several closed feedwater heaters plus an open heater, the deaerator.

Copper alloys were a common materials choice for closed feedwater heater tubes because of copper’s excellent heat transfer properties. However, copper is susceptible to corrosion from the combined effects of dissolved oxygen and ammonia, the latter being the common chemical for feedwater pH control (although at some plants alkalizing, aka neutralizing, amines remain the choice). ^{(3, 4)}

Oxygen converts the protective Cu₂O layer on the copper surface (where copper is in the +1 oxidation state) to CuO, with copper transforming to a +2 oxidation state. Cu²⁺ reacts with ammonia to form a soluble compound. So, for virtually any system containing copper alloys, a combination of mechanical deaeration and chemical oxygen scavenging was, and still is, necessary to protect the alloys. The oxygen scavenger also serves as a passivating agent to convert CuO back to Cu₂O.

The combination of ammonia or an ammonia/amine blend for pH control and oxygen scavenger feed is known as all-volatile treatment reducing (AVT(R)). It produces the familiar dark magnetite layer (Fe₃O₄) on carbon steel but is no longer recommended for utility units and HRSGs with no copper alloys.

Rather, all-volatile treatment oxidizing (AVT(O)) as outlined in Reference 1 (with no oxygen scavenger feed but still ammonia or an ammonia/amine blend for pH control) is the proper choice. AVT(O) produces a red oxide layer, α-hematite (alternatively known as ferric oxide hydrate (FeOOH)) on carbon steel. AVT(O) requires high-purity feedwater with a cation conductivity of <0.2 mS/cm to be successful. For cogeneration and industrial steam generation systems, the (usually) lower-purity feedwater and/or presence of copper alloy-tubed heat exchangers prohibits AVT(O), with AVT(R) being the required option.

Careful chemistry control is necessary to find the balance between minimal iron and copper corrosion. A key ingredient in the treatment program is corrosion product monitoring to ensure that the chemistry is optimized.

Corrosion product monitoring

Regarding iron monitoring, several discussion points from Reference 2 bear brief repetition. 

Typically, 90% or greater of steel corrosion products exist as iron oxide particulates. Thus, measurements of just dissolved iron do not come close to the total corrosion product concentration. Hach developed a benchtop procedure that utilizes a 30-minute digestion process to convert all iron to soluble form for subsequent analysis on a standard spectrophotometer.

The lower detection limit is 1 part-per-billion (ppb), which is satisfactory for even high-pressure steam generators where the recommended feedwater iron concentration is <2 ppb. As events have shown over the last nearly four decades, iron monitoring is highly important for tracking flow-accelerated corrosion (FAC) in condensate/feedwater systems and in the low-pressure economizer and evaporator (and often some intermediate pressure circuits) of multi-pressure HRSGs. This benchtop technique provides snapshot readings only, but those are often sufficient with a system protected by proper chemistry. ⁽⁵⁾

Sometimes, however, continuous online measurements are important to quickly detect changing conditions. Hach has developed a laser nephelometry technique for that purpose, with additional details available in Reference 2. This method must be calibrated at each site and is dependent on whether an AVT(O) or AVT(R) program is in place. 

Now we reach a second key point of this article, as summarized in Reference 5.

For a cogeneration plant that sends steam to a steam host for use in a process (either via direct or indirect use) and then receives all or a portion of the condensate back, monitoring corrosion products in the steam condensate indicates whether corrosion and FAC are minimized in the process part of the steam plant. . . .  For mixed-metallurgy plants the copper levels can be extremely variable depending on the plant design and operation, but with chemistry optimized as far as possible, levels of total copper less than 10 [ppb] can be expected.

As with iron, the analytical process must account for dissolved and particulate metal. When this author began his power plant career over four decades ago as a laboratory chemist, the lab was equipped with a flame/graphite furnace atomic absorption spectrophotometer (AAS). Sample acidification with nitric acid solubilized particulate copper, and the total could then be accurately analyzed by the AAS. However, many labs do not have such sophisticated equipment and the trained personnel to operate these instruments. One method for accurate measurements, albeit where samples are collected over time, is corrosion product sampling.

This CPS utilizes a fine-pore mechanical filter paper for particulate collection and cation exchange (and if desired anion exchange) filter papers for dissolved ion collection. Any sampling period may be chosen (one to two weeks is common), after which the filters are sent to a laboratory for accurate analyses. The unit has a precise flow totalizer so that the analytes can be converted to concentration units for the time-period that the sample was collected. 

Consider the extract below from the recently-revised industrial boiler water guidelines produced by the American Society of Mechanical Engineers (ASME).

As the reader will note, recommended feedwater iron and copper limits are stringent, even for low-pressure industrial steam generators, and the values decrease with increasing pressure. For high-pressure utility steam generators, the suggested upper limits are 2 ppb for both iron and copper. A CPS can provide very valuable data on corrosion control in condensate systems with mixed metallurgies. Consider the following example, in which a CPS assisted with corrosion monitoring in a utility steam generator.

CPS case history

The author once consulted for an electric utility whose main unit was and still is a coal-fired boiler at full-load operating conditions of 1, 900psig drum pressure and 1, 005°F main and reheat steam temperatures. The feedwater system had heaters with copper-alloy tubes, requiring an AVT(R) feedwater chemistry regimen. (At the time of this project, plant personnel were developing a plan to replace the copper alloy heater tubes with steel.) Carbohydrazide served as the reducing agent, with a blend of morpholine and cyclohexylamine for pH conditioning.  Chemical injection is at the deaerator storage tank. Even though the chemical feed system could maintain feedwater pH within a range of 9.0–9.3 (the recommended range for balancing steel and copper corrosion control), the condensate pH typically remained in an 8.8–8.9 range.  It became clear that the condensate pH depression resulted from amine decomposition products that carried over with the steam.⁽⁴⁾

Per our recommendation, utility personnel installed a Sentry corrosion product sampler, with the flexibility for monitoring either feedwater or condensate pump discharge (CPD). Sampling indicated that iron concentrations were often five to fifteen times greater than the 2-ppb recommended limit, which suggested serious flow-accelerated corrosion in the condensate/feedwater network. Furthermore, the iron concentrations in the CPD were higher than in the feedwater. These results suggested that the lower pH induced by alkalizing amine decomposition had more of an influence on mild steel corrosion than the higher feedwater temperatures, both of whose influences are well known per the following famous diagram.

Regarding copper analyses, the CPS revealed concentrations very near the 2-ppb limit mentioned above, which should be expected in an oxygen-free environment with a pH close to 9.0. Accordingly, carbon steel corrosion became the primary focus in this unit. Plant personnel have recently incorporated a film-forming amine (FFA) into the chemical treatment program. Film-forming amines and related non-amine products are designed to directly establish a protective layer on metal surfaces. ⁽⁸⁾ Both successful and unsuccessful applications have been reported, but space does not permit a detailed discussion at present. In this application, no CPS data is yet available to confirm the efficacy of the FFA, but Millipore filter tests suggest that carbon steel corrosion has been reduced.   

Film-forming chemistry should be incorporated into and not serve as a full-blown substitute for either AVT(R) or AVT(O) methodologies. An issue that has been problematic regarding FFA applications is direct calculation of reagent concentrations. Significant strides are being made in this respect, which Hach personnel highlighted in a paper at the recent Electric Utility Chemistry Workshop. ⁽⁹⁾

While copper monitoring has proven to be less critical than iron monitoring in the example above, it is often much more important at cogeneration and industrial steam plants. As mentioned, certain conditions such as the combination of dissolved oxygen and ammonia can cause significant copper corrosion and reduce the life expectancy of heat exchanger tubes. 

Another corrodent that can cause severe damage to many metals including copper is sulfide (S^2-). The author once observed a situation where thousands of new 90-10 copper-nickel tubes in a steam surface condenser failed from multiple pitting leaks within 18 months because the machining lubricant contained sulfide that was not removed before the tubes were placed in service. An online measurement often recommended for chemistry control in mixed-metallurgy systems is oxidation-reduction potential (ORP). The data provided by trace metal monitoring methods can be correlated to ORP measurements to then serve for continuous chemical feed control.

Conclusion

Trace metal monitoring continues to become better recognized as a critical tool for optimizing steam generator chemical treatment programs and controlling corrosion. A primary concern with utility units is minimizing carbon steel flow-accelerated corrosion, but for cogen and industrial steam/condensate networks, copper corrosion monitoring is often also very important.

References

1. B. Buecker, “HRSG Steam Generation Issues: Reemphasizing the Importance of FAC Corrosion Control, Parts 1-4” Power Engineering, September-October 2022.
2. Buecker, B., Kuruc, K., and L. Johnson, “The Integral Benefits of Iron Monitoring for Steam Generation Chemistry Control”; Power Engineering, January 2019.
3. B. Buecker, Tech., Ed., Water Essentials.  (The new ChemTreat industrial water handbook, currently being released in digital format at www.chemtreat.com.)
4. Shulder, S. and B. Buecker, “Remember the 3Ds of Alkalizing Amines: Dissociation, Distribution, and Decomposition”; PPCHEM Journal, 2023/01.
5. International Association of the Properties of Water and Steam, Technical Guidance Document: Corrosion Product Sampling and Analysis for Fossil and Combined Cycle Plants.  www.iapws.org.
6. 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.
7. P. Sturla, Proceedings of the Fifth National Feedwater Conference, Prague, Czechoslovakia, 1973.

Even though the large coal plants constructed in the last century continue to be decommissioned, many thousands of other steam-generating units provide the energy for electricity generation and process heating at combined cycle power plants, co-generation and combined heat and power (CHP) facilities, and heavy industrial plants. 

Maintaining proper chemistry across a broad spectrum, from cooling water to steam generation to condensate return is extremely critical for plant reliability. Important and cutting-edge developments in this regard were the focus of discussion at the recent 41^st Annual Electric Utility Chemistry Workshop (EUCW), hosted by the University of Illinois Urbana-Champaign. This article highlights some, but certainly not all, of the topics presented at this year’s event. Interested readers need to pencil in June 7-9, 2024 for the next event.

Cooling water

Since 2007, the workshop has offered a four-hour, pre-conference seminar that has rotated between steam generation chemistry, cooling water treatment, makeup water production and wastewater treatment. Your author has been thrilled to be a part of every one of these seminars (usually with support from expert colleagues), and was the presenter of this year’s event, which rotated back to cooling water. Many of the discussion points reflected information offered in a recent Power Engineering series ⁽¹⁾, but several important items are worthy of review here.

• For the many plants that have cooling towers for one or more process applications, conscientious monitoring and control are critical for reliability. Often, towers sit in remote locations and may be somewhat forgotten. Chemistry upsets, and especially microbiological fouling, can occur very rapidly and cause severe problems. Cases are well known of partial cooling tower collapse due to excessive fouling and weight gain in cooling tower fill. Of course, prior to such a catastrophe, tower heat transfer would have been greatly impacted, which most likely would have already caused a significant loss in process efficiency. Numerous oxidizing and non-oxidizing biocides are available for microbiological control, and programs can often be tailored for specific plant needs.
• Corrosion and scale control programs continue to improve with chemistry that directly protects metal surfaces. These programs have also allowed many plants to reduce or eliminate phosphorus (as inorganic and organic phosphates) in cooling tower discharge, which has important environmental benefits. 
• Sophisticated computer software programs are available to calculate chemical feed dosages, chemical inventories, alarm conditions, and other parameters. The systems can be configured to provide data to any location within the plant and also to outside experts for evaluation and prompt response.

Steam generation chemistry

Apart from renewables, many of the retired coal-fired power plants in the country have been replaced with combined cycle units. In general, these plants produce about 2/3 of their power from the combustion turbines and 1/3 from steam turbines supplied by heat recovery steam generators (HRSGs). 

Because virtually no HRSG has copper alloys in the feedwater system, the recommended feedwater chemistry program is all-volatile treatment oxidizing (AVT(O)), with no oxygen scavenger feed. ⁽²⁾ This is a concept that too many combined cycle plant personnel still do not understand. 

At the EUCW, a colleague from one of the most well-known utilities in the country outlined how the chemistry staff is installing supplemental feedwater and economizer oxygen injection systems to reduce flow-accelerated corrosion (FAC) in existing HRSGs. FAC is an extremely serious phenomenon that since 1986 has been responsible for a number of accidents, several with fatalities, at power plants around the country. The many tight-radius elbows in the low-pressure sections of HRSGs can be particularly susceptible to this attack.

Another excellent paper highlighted the fundamental metallurgical aspects of important HRSG corrosion mechanisms, including FAC, thermal fatigue, and water-side deposit-related failures. Most power units now cycle up and down in load regularly because they follow renewable energy load swings. Load fluctuations and on/off operation induce thermal and mechanical cycling stresses in steam generator components. Also, cycling can generate iron oxide corrosion products that transport to and from deposits in the HRSG evaporators, i.e., boilers. These build-ups then serve as potential sites for under-deposit corrosion (UDC). 

A well-known mechanism that afflicts many HRSGs is hydrogen damage. Operation outside of recommended chemistry limits allows impurities to enter the HRSG and concentrate under deposits, causing the corrosion. Hydrogen damage is very insidious and difficult to detect.  Tubes may continue to fail causing frequent outages.

A topic of several papers at this year’s workshop is the continued growth of film-forming products (FFP) for protection of steam generator internals. These products, both film-forming amines (FFA) and non-amines, have been promoted for well over a decade, with stories circulating of both successful and unsuccessful applications.

Successful applications were the theme of these papers, with data showing reduction of carbon steel corrosion during both normal operation and unit outages. A key issue is that even if a FFP trial indicates a product is effective, that is no excuse to abandon other recommended treatment methods such as maintaining an alkaline pH in feedwater and boiler water, and so forth.  A previous difficulty with FFP use has been direct measurement of product residuals, but the workshop included a paper that described a new procedure for analyzing FFA concentrations.    

High-purity makeup water production

In the last two to three decades of the 20th century and continuing onwards, the core technology of ion exchange (IX) for high-purity water production was mostly replaced with reverse osmosis (RO) for bulk demineralization with mixed-bed IX or continuous electrodeionization (CEDI) for RO permeate polishing. Furthermore, the membrane technologies of micro- and ultrafiltration have become common as RO pretreatment methods to remove suspended solids.

While membrane technologies are mature, lessons are still being learned to enhance performance and reliability. A technical specialist from a co-generation facility outlined steps that he and colleagues had taken to optimize performance of a RO-CEDI treatment system installed at their facility five years ago. 

These steps included specifying the correct analytical instrumentation to monitor system performance, conducting tests to optimize performance of upstream media filters, ensuring that chemical feed systems operated properly from day one and establishing steady state conditions as much as possible to cushion the system from mechanical stresses. Water hammer can be very damaging to high-purity makeup equipment.

Additional notes

As the discussion above suggests, the EUCW offers valuable information (and networking) for not only power plant personnel but also co-gen and industrial steam generation plant employees. In that regard, the author had the good fortune of preparing a paper with co-authors from the refinery and co-generation industries that discussed dealing with condensate return and the many potential impurities that may be in those streams. 

A more detailed discussion of these issues will soon appear in Power Engineering. Beyond the pre-workshop seminar on cooling water, a paper in the main session examined raw makeup water manganese removal, as this element can cause serious corrosion in steam condensers.

For the first time in several years, a paper was offered that addressed the nuclear power industry, in this case a new makeup water ion exchange resin that will also de-oxygenate water. The appearance of this paper undoubtedly was spurred by increasing interest in small modular reactors (SMRs) as a technology to reduce the carbon imprint from power production.

The next EUCW will be held June 7-9, 2024 in Champaign. Later this year, interested readers will be able to find more information at https://conferences.illinois.edu/eucw. Or, please feel free to contact me for additional details.

References

1. B. Buecker, “Advanced cooling water treatment concepts, Parts 1-6”; Power Engineering, November 2022-February 2023.
2. B. Buecker, “HRSG Steam Generation Issues: Reemphasizing the Importance of FAC Corrosion Control, Parts 1-4”; Power Engineering, September-October 2022.  The series includes references for more detailed information on the subject.

Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing.  Most recently he served as Senior Technical Publicist with ChemTreat, Inc.  He has over four decades of experience in or supporting the power and industrial water treatment industries, 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 (now Evergy) La Cygne, Kansas station.  His work also included 11 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 on the Electric Utility Chemistry Workshop planning committee.  He may be reached at beakertoo@aol.com.

By Katie Perryman, ChemTreat, Inc.

It has been over a century since steam was first utilized to drive turbines/generators for electrical production. As boiler technology advanced from early designs, power plant owners, operators, and technical personnel began to realize that the increasing pressures and temperatures of steam generators required high-purity makeup water to minimize corrosion and scale formation. This led to the advancement of ion exchange (IX) technology to produce boiler makeup with low part-per-billion (ppb) concentrations of impurities.

In the last several decades, membrane methods, notably reverse osmosis (RO), have become popular for primary demineralization, with ion exchange now serving to “polish” the RO product for steam generator makeup. In this series, we will examine various aspects of current technologies and the capabilities of modern systems. Part 1 offers a discussion of pretreatment methods, which are very important for reducing fouling, scaling, and other chemistry upsets within RO membranes and IX resins.

“Fresh” water still has many impurities

Although freshwater supplies are in decline (subject to regional fluctuations), many industrial facilities still use makeup from lakes, reservoirs, or rivers. Water moves around the globe in a process known as the hydrologic cycle.

Water vapor may be transported many miles before atmospheric conditions cause condensation and precipitation. Along the way, water vapor can absorb gases from the atmosphere, including pollutants, which alter its chemistry. Water chemistry is also influenced by the soil, mineral deposits, and vegetation over which water flows (or filters through to become groundwater).

Table 1 provides a snapshot analysis from several years ago of the major constituents in a Midwestern lake.

For utility heat recovery steam generators (HRSGs) and conventional fossil-fired boilers, common makeup water treatment effluent guidelines are:

• Sodium:  ≤2 ppb
• Silica:  ≤10 ppb
• Specific conductivity:  ≤0.1 μS/cm

When comparing Table 1 to these guidelines, it becomes apparent that even systems with freshwater as the raw makeup source may need to reduce impurity concentrations dramatically before sending the water to high-pressure boilers. Most modern power systems, such as combined cycle units with HRSGs, rely primarily on RO and IX polishing to produce high-purity water.

It is common for contractors to change out exhausted IX “bottles” with vessels containing freshly regenerated resin, eliminating the need for on-site regeneration with acid and caustic.  

Exploring pretreatment options

For the configuration shown in Figure 2, pretreatment largely focuses on reducing fouling and organic growth on RO membranes.

In this article, we spotlight pretreatment options for surface water issues, including:

• The spiral-wound configuration of RO membranes, which makes them susceptible to particulate fouling. 
• The importance of raw water biocide treatment for reducing microbiological growth (keeping in mind that oxidizing biocides, particularly chlorine, can severely damage RO membranes)
• The accumulation of large organic molecules from decaying vegetation found in many freshwater supplies, which can coat RO membranes, inhibiting flow, reducing capacity, and raising the transmembrane pressure

In the 20th century, clarification with multi-media filtration was the common method for removing particulates from clarifier effluent. A well-designed and operated clarifier/filter can produce water with less than 1 NTU turbidity. However, micro- and ultrafiltration membrane technologies have become a popular replacement for clarification, unless lime softening is necessary to lower hardness and alkalinity concentrations, which may be elevated in some groundwater supplies. Figure 3 below shows a 300 gallon-per-minute (gpm) microfiltration (MF) unit chosen as a replacement for an aging power plant clarifier.

Figure 3.  Microfilter skid including the 24 modules required to produce 300 gpm of filtered RO feedwater.  The inlet raw water holding tank, with forwarding and backwash pumps, is on the left. Photo by Brad Buecker.

The unit reduced RO makeup turbidity from a typical range of 0.5–1.0 NTU to less than 0.05 NTU. (2) This led to a dramatic reduction in RO cartridge filter and membrane cleaning frequency. Regularly adjusting clarifier coagulant and flocculant dosages to match changing flow rates was no longer required. This particular MF unit proved to be extremely reliable, provided it was given a thorough off-line cleaning every two to three months. For this application (and also for auxiliary heat exchanger cleanings throughout the facility), plant mechanics fabricated a portable vessel with mixer, heater, hoses, and a circulating pump to warm cleaning solutions to near 100^oF.

Normally, a two-step cleaning starts with circulating a relatively dilute but powerful caustic and bleach solution to remove organics and microbes. Following a rinse, dilute citric acid circulation removes iron oxide particles.

The normal process for MF and UF operation involves producing filtered water for a set period, e.g., 20 minutes, followed by a one- to two-minute backflush/air scour process to remove particulates that have collected on the membranes. The solids exit in a small wastewater stream. Modern units also include a periodic chemically-enhanced backwash (CEB) step, in which caustic or a chelant (often citric acid) is added to the backwash water to help clean the membranes. The chemical choice depends on the typical solids that collect on the membranes.

Membrane design options

Three designs exist for MF/UF membranes:

• Hollow fiber
• Tubular
• Spiral wound

The hollow fiber design is most common, with pressurized and vacuum systems available for different application needs.

Typical membrane materials include polyethersulfone (PES), polyvinylidene fluoride (PVDF), polypropylene (PP), and polysulfone (PS), with PES and PVDF being the most common. Both are hydrophilic, meaning the lumen surface becomes completely wetted to help resist organic fouling. PES has a slightly better permeability than PVDF. These materials easily tolerate a continuous oxidizing feed, a common method to minimize microbiological fouling. 

PES has a higher caustic tolerance for organics removal during off-line cleanings, whereas PVDF has a higher chlorine tolerance and membrane durability. These are important factors when deciding which material is better for particular water sources or operational factors.

Pressurized or submerged membrane designs are also available. Pressurized systems can have either an inside-out or outside-in flow path, whereas submersible designs, with the membranes suspended in a tank containing the feedwater, are outside-in, with mild vacuum pulling the water into the central core of the membranes.

Suspended solids excursions and the importance of historical water quality data

The potential for intense suspended solids excursions is an important consideration when designing membrane systems. Such excursions are most common in river waters following heavy precipitation. Some form of particulate pre-screening or settling may be necessary upstream of MF or UF, although submerged membranes can handle much higher solids concentrations than pressurized systems. 

Historical water quality data can be very valuable for process and equipment selection in these instances. For example, the turbidity in some rivers can increase from single digits to hundreds or even thousands of NTU during heavy rain. Without seasonal analyses to confirm such fluctuations, extreme conditions may cause pretreatment system failure.

The impact of oxidizing compounds on RO membranes

Oxidizing biocide (often bleach) feed is a typical treatment option for inhibiting microbiological fouling in water networks and treatment equipment in most raw water makeup systems. Unfortunately, the primary material of most RO membranes (not the spacer or support material) has a polyamide chemistry that contains nitrogen. Chlorine bonds with the nitrogen molecules and irreversibly damages the membranes. A common rule-of-thumb for membrane longevity is 1,000-ppm-hours, meaning membranes remain functional for approximately 1,000 hours at a 1 ppm chlorine concentration (or one hour at a 1,000-ppm chlorine concentration). However, the presence of heavy metals like iron can decrease this tolerance to as low as 200-ppm hours. Given that a normal membrane life expectancy typically ranges from 3 to 7 years, chlorine removal ahead of the RO membranes is an important step for improving membrane longevity. Of course, so is control of suspended solids fouling and scale formation.

The two primary methods for oxidizing biocide removal from RO/demineralizer feed are activated carbon (AC) filtration and reducing agent injection. However, oxidizing biocides react within the first few inches of an AC bed, leaving the remainder of the bed as a breeding ground for organisms that survive treatment. This is exacerbated by the AC bed’s ability to remove organics, which then become food for the organisms. Accordingly, many modern systems are designed with reducing agent injection to remove residual oxidizers. While a number of reducing agents are available, the two most common are:

• Sodium bisulfite (NaHSO₃): The most popular and inexpensive reducing agent, usually supplied as a 30% liquid solution.
• Sodium metabisulfite (Na₂S₂O₅): The granular form of sodium bisulfite.

The reactions of these two compounds with chlorine are shown below.

            2HOCl + 2NaHSO₃ → 2H₂SO₄ + 2NaCl                   Eq. 1

            2HOCl + Na₂S₂O₅ + H₂O → 2H₂SO₄ + 2NaCl          Eq. 2

Continuous monitoring is very important downstream of the reducing agent injection point. The primary measurement is chlorine residual with oxidation-reduction potential (ORP) as a potential supplement. The priority is to provide an alarm in the event of reducing agent feed malfunction to protect RO membranes. However, modern systems can also be designed to adjust reducing agent feed with analyzer signals to minimize overfeed while reducing the impact of chlorine on membrane life.

If possible, the reducing agent injection point should be placed after the RO cartridge filters. If that is not an option, the injection point should be as close to the cartridge filer housing as possible. Some organisms go into hibernation when contacted by an oxidizing biocide, re-emerging once the biocide residual disappears. The surviving microbes can establish large colonies in RO pre-filters and membranes.

Dealing with organic foulants

Many surface water sources contain significant concentrations of large organic compounds, e.g., tannins, lignin, and humic acids that can foul membrane surfaces. These compounds are normally measured as total organic carbon (TOC). TOC of less than 3 ppm in an RO feed is typically recommended. MF and UF are used primarily for particulate filtration, although some large organic removal may be possible. Supplemental AC filtration may be needed to remove other organics. If so, concerns about downstream microbiological fouling potential should be addressed before AC filtration is implemented.

Conclusion

This first installment of the series explores several important aspects of high-purity makeup system pretreatment. Deficient RO pretreatment is a leading cause for RO membrane failure/premature membrane change-out. 

Please remember that each system is different and has unique treatment needs. As with all other technologies, due diligence is necessary to determine the feasibility for utilizing the methods discussed in this article. Difficulties have arisen at some sites where the inlet water had impurities that reacted with pretreatment or backwash chemicals to produce foulants or scale-forming deposits. Always consult your equipment manuals and guides and contact a water treatment professional before making changes to system operation.

References

1. B. Buecker, Tech. Ed., “Water Essentials”; ChemTreat, Inc., 2023.  (This is the industrial water handbook that is currently being released digitally on a chapter-by-chapter basis.)  Information is available at www.chemtreat.com.
2. B. Buecker, “Microfiltration: An Up and Coming Approach to Pre-Treatment for the Power Industry”; presented at the 26^th Annual Electric Utility Chemistry Workshop, May 9-11, 2006, Champaign, Illinois.

Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing.  Most recently he served as Senior Technical Publicist with ChemTreat, Inc.  He has over four decades of experience in or supporting the power and industrial water treatment industries, 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 (now Evergy) La Cygne, Kansas station.  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 may be reached at beakertoo@aol.com.

Katie Perryman is Manager of the Pretreatment Technical Team at ChemTreat. She has nine years in the water treatment industry with a focus on pretreatment applications that include filtration, membrane separation and ion exchange systems. She has spent her time at ChemTreat supporting a wide variety of customers in the power, chemical, food & beverage, and transportation industries, among others. Perryman has acted as a corporate trainer and presenter both internally and externally for several years at conferences such as the Southwest Chemistry Workshop and ChemTreat’s Power conference. Perryman has a B.S. in Chemistry from Virginia Tech.  She may be reached at katieh@chemtreat.com.

Read Part 1 here.

Read Part 2 here.

Read Part 3 here.

Read Part 4 here.

Read Part 5 here.

In previous parts of this series, we examined many issues related to primary cooling water treatment at power and industrial plants. However, most large plants have a number of closed water systems that provide auxiliary cooling to such equipment as pump bearings, lube oil coolers, generator hydrogen coolers and so forth. 

These subsystems are critical to plant operation, and poor performance or failure of a closed system can potentially shut down the plant. In this installment, we will examine several of the most important aspects of closed cooling water treatment.

Closed systems?

The term “closed” cooling water is slightly misleading, as many systems experience leaks or small losses that require makeup. (If serious corrosion has occurred, these losses may be significant.) Also, systems often have a head tank for introduction of makeup and to handle changes in demand, which is another source for oxygen infiltration. Of note is that some closed systems are air cooled, which more completely approach “closed” status. 

While it is possible to utilize water with varying qualities in CCW systems, a frequent choice, and the focus of this article, is condensate or demineralized water that is treated within the system. 

Typical piping material for CCW networks is carbon steel. Copper alloys, stainless steel, or perhaps on occasion titanium are the usual choices for heat exchanger tubes, or plates in a plate-and-frame exchanger.

When planning a treatment program, it is important to know the complete system metallurgy.

Corrosion control, the primary issue

In systems with high-purity water, scale formation is usually not a problem but rather corrosion is the main issue. (Microbiological fouling can also be problematic, which we will explore later in this article.) The most common corrosion mechanisms, many of which were outlined for open recirculating systems in earlier installments of this series include:

• General corrosion
• Localized corrosion; pitting, crevice corrosion, under-deposit corrosion
• Stress corrosion cracking (SCC)
• Galvanic corrosion
• Microbiologically influenced corrosion (MIC)

Similarly to open recirculating systems in the middle of the last century, chromate was very popular for corrosion control in closed systems. After treatment has been initiated, chromate will eventually form what has been termed a “pseudo stainless steel” layer on carbon steel that is quite protective. However, toxicity issues with hexavalent chromium (Cr⁶⁺) led to its elimination from nearly all cooling water applications.

Sodium nitrite (NaNO₂) has been a common replacement for chromate. The compound is inexpensive and safe to handle, and usually includes a pH conditioning agent or buffer such as sodium hydroxide or sodium tetraborate to maintain pH within a 8.5 to 10.5 range. (2)

Nitrite promotes the formation of a passive iron oxide layer on the metal surface.

9Fe(OH)₂  + NO₂ →  3Fe₃O₄ + NH₄ + 2OH + 6H₂O                         Eq. 1

9Fe(OH)₂  + NO₂   →  3(Fe₂O₃) + NH₄ + 2OH + 3H₂O                    Eq. 2

Nitrite first reacts at anodes, and for this reason is commonly known as a “dangerous” inhibitor, because if residuals fall below threshold limits, a small number of anodes can develop in a large cathodic environment. Rapid pitting may then occur. A usually safe nitrite residual range is 500-1,000 ppm to inhibit general corrosion and pitting, but every application should be carefully monitored and controlled. If system leaks prevent the ability to maintain adequate residuals, the treatment should probably be halted until the leaks are repaired.

Per this author’s experience of nitrite treatment for closed systems, fresh chemical introduction was straightforward – a once per week charge of granular sodium nitrite blended with pH buffer into pot feeders.

Batch feed is performed by unlatching the top cover, pouring in the measured amount of solid chemical, re-latching the cover, and then valving in the feeder for several minutes to ensure that the solids dissolve and are transported into the cooling water slipstream. 

An auxiliary device that may be included in the slipstream is a particulate filter. Even with proper chemical treatment some metal corrosion is still probable, particularly from the usually large carbon steel piping network. In general, 90% or greater of steel corrosion products exist as particulates, not dissolved iron. These particulates can settle in low flow areas and locations of high heat transfer, i.e., heat exchangers. Sidestream filtration will remove many particulates and reduce deposition within the cooling system. 

A concern with nitrite is that it is an excellent nutrient for some bacteria such as Nitrobactera agilis, which can grow rapidly by converting nitrite to nitrate, and then foul cooling systems. For example, the author was once part of an inspection team that visited an automobile assembly plant, where nitrifying bacteria had partially plugged the small, serpentine cooling water tubes in automatic welders. Possible remedies include a change to a different corrosion inhibitor or supplemental feed of a non-oxidizing biocide.

Sodium molybdate (Na₂MoO₄) is an alternative to nitrite. Evidence suggests that molybdate acts similarly to chromate and adsorbs onto the carbon steel surface at anodes and then continues to form a protective layer.

Fe²⁺ + MoO₄^2- →  FeMoO₄↓                                                              Eq. 3

Research also indicates that molybdate also acts as a pitting inhibitor per its ability to accumulate within the acidic zone of a pit and block the corrosion process. A common control range for molybdate is roughly 1/3 that of nitrite. Although molybdate is an oxyanion, some research, which has been debated, suggests that the compound requires residual dissolved oxygen to be fully effective. Enough oxygen may enter through the cooling water makeup to provide the needed amount. As with nitrite, molybdate formulations typically include a pH buffer to establish moderately alkaline conditions in the cooling water.

Molybdate is an expensive chemical, and costs may be prohibitive in some applications. Programs have been developed that employ both nitrite and molybdate, which act synergistically and lower the concentration of either chemical when utilized alone.

Copper Alloy Corrosion Control

Copper alloys have been a prime choice for heat exchanger tubes for many years, as copper has superb heat transfer properties. While copper is a more noble metal than iron, significant corrosion is possible in certain environments. The combination of dissolved oxygen and ammonia can be particularly corrosive. Azoles are commonly employed to protect copper alloys, via film-forming chemistry. Figure 4 illustrates the general effect.

The nitrogen atoms in azole molecules bond with copper atoms at the metal surface. The plate-like organic rings then form a barrier to protect the metal from the bulk fluid. Some common azoles are listed below.

Benzotriazole

1,2,3-benzotriazole (BZT – C₆H₅N₃) is the compound shown in Figure 4. It is the most fundamental azole.

Tolyltriazole

Tolyltriazole (TTA –  C₇H₇N₃) is similar to BZT but with a methyl group added to the organic ring.

The methyl group helps orient the molecule to establish a more uniform barrier film. Other azole variations are available, including halogen-resistant compounds designed for use in open-recirculating systems where oxidizing biocides are employed for microbiological control.

Another of the early azoles is 2-mercaptobenzothiazole (MBT), which has two sulfur groups in the nitrogen ring. One of the sulfur atoms also bonds with copper to form a thick passive film.

An azole concentration as low as 1-2 ppm may be sufficient for corrosion control, but higher levels may be needed depending on system layout and conditions.

Glycol containing networks

Cooling systems subject to low-temperature conditions often include ethylene or propylene glycol to prevent freezing. “Both phosphates and nitrites are [acceptable] as ferrous alloy corrosion inhibitors, [and] azoles are [effective] for copper alloy corrosion inhibition.” (2) An issue with glycol, as it is in other equipment including automobiles, is that over time the chemical will break down to organic acids that lower pH and increase corrosion potential. Accordingly, regular pH measurement is important for glycol-treated cooling systems (and glycol-free systems for that matter).

Microbiological control

As previously noted, some corrosion control chemicals, and most notably nitrite, can serve as nutrients for microorganisms. A potential solution, where possible, is a switch from nitrite to molybdate, as the latter is not a microbiological nutrient. However, molybdate has no biocidal properties. Expense and other factors may not allow such a change. Oxidizing biocides are not normally utilized to control microbes in closed systems, as they can cause corrosion and also deactivate treatment chemicals, especially nitrite. Many of the non-oxidizers that we examined in Part 5 of this series may be effective for attacking microorganisms. A potential drawback is that most are deactivated by alkaline pH, but some may attack organisms quickly before significant decomposition. Consultation with a reliable chemical supplier is important for selecting the choice of chemical and dosage. Analyses to determine the organisms present within the system are important for any effort of this type.       

Chemistry monitoring

Field kits are available for monitoring the residual concentrations of the standard corrosion inhibitors. Bench top instrumentation such as UV-VIS spectrophotometry offers accurate readings.

Because microbial growth occurs frequently in closed systems, regular monitoring can detect the onset of fouling.  Dip slide testing is straightforward and does not require exotic laboratory equipment.  Specialized tests can provide valuable information on numerous microorganisms, including sulfate reducing bacteria (SRB), nitrifying bacteria and denitrifying bacteria. (2)

Common for corrosion monitoring is installation of a corrosion coupon by-pass rack, with coupons having the same metallurgy as in the cooling network.

A prime feature of correct design is coupon orientation. As is evident in Figure 7, the orientation is with the water flow along and not against the coupon. This configuration helps to minimize eddy currents. The piping can be configured to hold multiple coupons that can be extracted over different intervals to more accurately evaluate the effect of time on corrosion rates.

An indirect but effective corrosion monitoring technique is iron monitoring, which can also be performed by UV-VIS spectrophotometry. However, because 90% or greater of steel corrosion products usually exist as iron oxide particulates, the test procedure requires a 30-minute digestion process to convert particulate iron to dissolved form. The total iron concentration provides valuable data on the efficacy of corrosion treatment. (3).

Conclusion

Closed cooling water systems are an integral part of many industrial plants. Neglect of system chemistry can lead to severe problems that may cause partial or full plant shutdown. Conversely, on occasion system materials may be over-specified. The author once assisted with a troubleshooting project where the main trunk line of an air-cooled system was ductile iron pipe with an internal cement coating covered over with a bitumen lining. During system startup when conditions reached full heat load, the bitumen broke loose and plugged the heat exchanger and inlet filters to the circulating pumps. Better would have been plain ductile iron piping with treatment by one of the corrosion inhibitors mentioned above. 

This discussion represents good engineering practice developed over time. However, it is the responsibility of plant owners, operators, and the technical staff to implement reliable programs based on consultation with industry experts. Many additional details go into the design and subsequent use of these technologies than can be outlined in a single article.

References

1. Post, R., Buecker, B., and S. Shulder, “Power Plant Cooling Water Fundamentals”; pre-workshop seminar to the 37^th Annual Electric Utility Chemistry Workshop, June 6-8, 2017, Champaign, Illinois.
2. K.A. Selby, “Closed Cooling and Heating Systems in Power Plants”; presented to the ASME Research Committee on Power Plant & Environmental Chemistry, Charleston, South Carolina, March 11-13, 2002.
3. Buecker, B., Murphy, F., and K. Kuruc, “Iron Monitoring in Industrial Steam Generating Systems”; Water Technology, Jan/Feb 2021. 

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as Senior Technical Publicist with ChemTreat, Inc. He has over four decades of experience in or supporting the power and industrial water treatment industries, 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 (now Evergy) La Cygne, Kansas station. 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 may be reached at beakertoo@aol.com.

Read Part 1 here.

Read Part 2 here.

Read Part 3 here.

Read Part 4 here.

The previous part to this series provided an overview of oxidizing biocides, which have for many years been utilized for cooling water microbiological control. However, conditions may exist in which supplemental chemical treatment is needed to control microbial growth or to attack sessile colonies that resist the oxidizers. In these situations, non-oxidizing biocides may be quite valuable. Non-oxidizers may also be needed to attack macro-fouling organisms such as zebra mussels. This installment provides fundamental details of this chemistry.

Non-Oxidizing biocides – A different method of attack

As was noted in Part 3, if bacteria form sessile colonies, the microorganisms may develop substantial immunity to oxidizers by producing protective biofilms that consume the chemical(s). The use of a non-oxidizing biocide on a periodic basis, for example once or twice per week for a relatively short duration, can help to control microbial growth. Whereas oxidizing biocides typically damage cell walls and cause death by leakage of organism internals (lysis), many of the non-oxidizers penetrate slime and then cell walls to react with cell compounds that are necessary for life. (1)

The compounds have varying degrees of efficacy and may target some organisms over others. Both efficacy and residual chemical decomposition are typically influenced by water conditions including pH and temperature. Let’s examine several of the most common non-oxidizers.

2,2-dibromo-3-nitrilopropionamide (DBNPA)

DBNPA is a halogenated amide that is widely used in water treatment and pulp and paper applications, and in the oil-field serves to treat makeup water for fracturing fluids. The compound irreversibly reacts with sulfur-containing amino acids in cell internals and causes death. 

DBNPA acts very quickly. Also, residual concentrations rapidly hydrolyze to less toxic by-products. The rapid decomposition is environmentally advantageous, for if the discharge passes through a retention pond, deactivation chemistry may not be needed. The optimum pH range for maximum DBNPA efficacy is 4-8. The hydrolysis rate increases with increasing pH and the compound rapidly loses potency above pH of 8. Hydrolysis also increases with increasing temperature. DBNPA is deactivated by sulfides and bisulfite or sulfite reducing agents. DBNPA also reacts with ammonia and is not stable to UV light.

DBNPA is effective for other applications. For example, a number of years ago the author, in consultation with an experienced chemical supplier, selected DBNPA to relieve microbiological fouling in reverse osmosis (RO) units for high-purity makeup water treatment at a power plant. Most RO membranes have a polyamide base material that contains nitrogen, which reacts irreversibly with chlorine. This makeup system had activated carbon filters to remove chlorine ahead of the RO unit. 

Typically, however, some organisms survive chlorination and then blossom once the chemical is removed. (Also, an activated carbon bed removes oxidizers in the top few inches, leaving the remainder of the bed as a great spot for incubation of surviving microbes.) Serious membrane fouling may result, which occurred in this system. Feed of DBNPA for one hour twice per week solved the problem.

2-Bromo-2-Nitropropane-1,3-diol (Bronopol)

Bronopol is used extensively in water treatment applications and, like DBNPA, has seen some applications in the oilfield. Bronopol is particularly effective against Pseudomonas bacteria. The compound appears to function by differing mechanisms depending on whether conditions are aerobic or anaerobic. Bronopol is not a fast acting biocide. The compound may release formaldehyde upon decomposition, but the formaldehyde is not responsible for the biocidal properties.

Bronopol will hydrolyze in aqueous solutions, with the rate being much faster at alkaline pH. Increasing temperature also increases the hydrolysis rate. The optimum pH range forbronopol efficacy is 5–9. Bronopol will react with and become deactivated by sulfides and sulfite-based reducing agents.

Isothiazolones

The most common formulation for cooling water treatment has a 3:1 mixture of CMIT and MIT. The CMIT and MIT concentrations in registered products usually have either 1.5 percent or 4 percent active ingredient. Industrial formulations may contain a stabilizer(s), including cupric nitrate, magnesium nitrate, or potassium iodate. Also available is a 1.5 percent active product stabilized with bronopol. The compounds are broad spectrum but slow-acting bactericides that also show good reactivity towards fungi. Apart from cooling water applications, MIT, in very slight concentrations, serves as a common anti-microbial agent in some detergents. 

Both CMIT and MIT are incompatible with hydrogen sulfide and other sulfide-containing compounds. Therefore, if sulfur reducing bacteria (SRB) are present, isothiazolones may not be very effective. Elevated pH (> 9.5) will shorten the half-life of CMIT, but MIT is stable even at a pH above 10. Isothiazolones are deactivated by sodium bisulfite.

Glutaraldehyde

Glutaraldehyde is often used in industrial water treatment applications, including oil and gas operations, the paper industry and for medical instrument sterilization. Within cells, the compound deactivates two essential amino acids, lysine and arginine, which are essential for cell metabolism. Efficacy is greatest within an alkaline pH range of 7-10, but the compound is more stable at an acidic pH. Glutaraldehyde will react irreversibly with amines or ammonium ions to reduce biocidal efficacy.

Quaternary Amines

Quaternary amines, or “quats” as they are commonly termed, have been utilized extensively in a wide variety of cooling and process water applications. The molecules are positively-charged, with four alkyl groups attached to a central nitrogen atom. One or more of the alkyl groups consists of a methyl, benzyl, decyl (C₁₀), coco (C₁₄), or soya (C₁₈) group. Quats are commonly fed in combination with other biocides. Quats are also used as filming-amine corrosion inhibitors.

Quats have surfactant properties and therefore solubilize cell membranes, leading to cell damage and death. (2) The compounds are especially effective when used in combination with other biocides that also attack cell walls.

Foaming is a concern with quaternary amines, but low-foaming compounds are now available. The surfactant properties of quats can inhibit the separation of oil/water emulsions in oilfield production systems, and hard water may decrease the biocidal activity of the compounds. (3) Quats can react with negatively-charged scale and corrosion inhibitors, which reduces efficacy.

Non-oxidizers for macrofouling control

Oxidizing biocides are lethal to clams, mussels, and so forth when these creatures are in the larval stage, but if organisms become established or adult organisms have a pathway into cooling systems, the situation can be entirely different. A classic case is zebra mussels, where, as was noted in Part 3 of this series, the mussels will attach to surfaces, including each other, with thin filaments known as byssal threads. They then reside comfortably by filtering the flowing cooling water. The mussels can sense oxidizing biocides, and when feed is initiated for the two hours per day (or whatever time period is allowed by the plant’s NPDES permit), they will “clam up” (pardon the pun) until the toxic conditions disappear, upon which they will merrily resume filtering the cooling water for food. 

Oxidizers are lethal to adult organisms if plant personnel can obtain a variance for continuous chemical feed for perhaps two or three weeks. The long feed duration eventually forces the organisms to re-open or re-activate, upon which the oxidizer causes damage. However, regulatory agencies are often reluctant to grant such variances.

Non-oxidizers can be of benefit in these cases, as many macro-organisms do not detect the chemical presence and continue to filter water. The most effective include the quaternary amines mentioned above. 

Non-oxidizing compounds pose environmental risks and potential toxicity to other aquatic organisms. Accordingly, they cannot be utilized without permission from the plant’s environmental regulators, with the application specifics incorporated into the facility’s NPDES discharge permit. The permit may require feed of a material such as clay or bentonite to the discharge stream to adsorb and deactivate residual concentrations, although as was noted above, some compounds, if given sufficient retention time in a holding pond, will decompose naturally.

As with any chemical, following proper safety procedures when handling non-oxidizers is very important. Plant personnel must be wearing all protective personnel equipment required for any particular chemical, and should follow all handling procedures to the letter. Safety data sheets (SDS) must be available at the feed site, with a second copy located in a central location such as the plant control room.

Conclusion

Of the various mechanisms that can cause difficulties in cooling systems, micro- and sometimes macro-fouling can be by far the most serious. If organisms become established, growth can be very rapid and damaging. The first line of defense is a well-designed, maintained, and operated oxidizing biocide feed system, but this may not be sufficient for challenging conditions. Non-oxidizing biocide feed effectively supplements oxidizers, but storage, handling, and feed of these chemicals must be based on a firm foundation of safety and adherence to regulatory guidelines.

This discussion represents good engineering practice developed over time. However, it is the responsibility of plant owners, operators, and the technical staff to implement reliable programs based on consultation with industry experts. Many additional details go into the design and subsequent use of these technologies than can be outlined in a single article.

References

1. Post, R., Buecker, B., and S. Shulder, “Power Plant Cooling Water Fundamentals”; pre-workshop seminar to the 37^th Annual Electric Utility Chemistry Workshop, June 6-8, 2017, Champaign, Illinois.
2. Merianos, J. J. 1991. “Quaternary Ammonium Antimicrobial Compounds” in Block, S. S., Disinfection, Sterilization, and Preservation, 4^th ed., Lea & Febiger, Philadelphia, pp. 225-255, and references cited therein.
3. Petrocci, A. N., Green, H. A., Merianos, J. J., and Like, B., 1974. “The Properties of Dialkyl Dimethyl Quaternary Ammonium Compounds,” C. S. M. A. Proceedings of the 60^th Mid Year Meeting, May 1974, pp 87-89.

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as Senior Technical Publicist with ChemTreat, Inc. He has over four decades of experience in or supporting the power and industrial water treatment industries, 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 (now Evergy) La Cygne, Kansas station. 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 may be reached at beakertoo@aol.com.

Read Part 1 here.

Read Part 2 here.

Parts 1 and 2 of this series examined issues related to scaling and corrosion in open recirculating cooling systems, i.e., those systems with cooling towers, and it also provided an overview of modern chemistry methods for scale/corrosion control. An issue that frequently dwarfs these concerns is microbiological fouling. Without proper control, microbes can rapidly establish colonies at many locations within cooling systems. These colonies can degrade heat transfer, restrict fluid flow and induce under-deposit corrosion. Cases are known where heavy microbiological fouling and accumulation of silt and other debris caused partial collapse of cooling towers. This installment provides an overview of common microbiological fouling issues, with discussion also about macro-biological fouling. Parts 4 and 5 will examine current and evolving microbial control methods.

Microorganism types

An enormous number of microbes exist in our environment, and space limitations prevent extensive discussion of the varieties here. For cooling water systems, the three general types of microorganisms that can be problematic are bacteria, algae, and fungi. Bacteria can form colonies in many locations, fungi will attack cooling tower wood, and algae can grow prolifically in sunlit areas such as cooling tower decks. Advanced microorganisms including amoeba and protozoa may appear in established bacterial colonies. These more complex organisms may in turn harbor Legionella bacteria.

Bacteria

Bacteria are generally classified into three types: aerobic, anaerobic and facultative. Aerobic bacteria require oxygen for metabolism, whereas anaerobic bacteria extract oxygen from oxygen-containing molecules such as sulfate and nitrate. Facultative bacteria utilize oxygen if it is present, but can extract oxygen from other sources when oxygen is absent. 

Common organisms include:

• Sulfate-reducing bacteria (SRB)
• Iron-related bacteria (IRB)
• Slime forming bacteria
• Nitrifying bacteria
• Denitrifying bacteria

Bacteria that are free floating in water are known as planktonic organisms, whose concentration can be readily measured. However, if the organisms settle on surfaces to form sessile colonies, problems may arise very rapidly. Some bacteria exude a polysaccharide film (slime) that protects the organisms and allows development of complex colonies that may include many of the organisms listed above. The slime in turn will capture silt to form heavy deposits that often resemble mud.

As is clearly obvious, the slime in this exchanger must have greatly restricted flow and energy transfer.

Microbial deposits can also induce serious corrosion. For starters, the deposits allow differential oxygen cells to form, where the metal underneath the deposit becomes anodic to clean surfaces. Localized corrosion and pitting may result. Beyond that difficulty, some organisms produce harmful compounds as part of their metabolic processes. Sulfate-reducing bacteria are a prime example, whose metabolic byproduct is sulfide. Sulfides will attack many metals including iron and copper. 

This attack is commonly referred to as microbiologically-induced corrosion (MIC). The author observed a situation once where a 15,000-tube (316L stainless steel) steam surface condenser developed thousands of pinhole leaks during a month-long maintenance outage. Water was left standing in the tubes, which allowed microbes to settle and produce harmful byproducts that damaged most of the tubes. The subsequent condenser re-tubing was quite expensive.

Another location that can suffer heavy deposition and fouling is cooling tower fill.

Again, the deposits restrict fluid flow and inhibit heat transfer. Deposition can also add enormous weight to the fill, as is illustrated.

Fungi

With the development of plastic and metal cooling tower structural components and less reliance on wood, fungi attack is perhaps not as broadly serious as in the past. However, wood has not disappeared as a cooling tower material, and fungi control remains important in many applications. Some fungi utilize wood as a nutrient, and the organisms can degrade wooden components. Some species attack the cellulosic wood fibers, while others attack the lignin binder. Names for the various types of attack include surface rot, white rot, and brown rot. Fungi thrive in acidic environments and are less active in modern cooling water systems per typical operation within a mildly basic pH range.

Algae

Algae are photosynthetic organisms that can grow as large masses in areas exposed to sunlight.

A common location for algae growth is on the decks of crossflow cooling towers. The organisms can plug the perforations to the fill below and reduce cooling capacity and tower efficiency.

As was noted in Parts 1 and 2 of this series, phosphorus is a limiting nutrient for algae, so in those systems that have been converted from phosphate-phosphonate scale/corrosion control chemistry to non-P programs, algae growth may be somewhat limited.

Legionella

If sessile colonies become well established, higher life forms including amoeba and protozoa may emerge. While some amoeba species directly cause human health problems, well known is an established relationship between amoeba, protozoa and Legionella bacteria. Legionella is the bacteria first discovered in 1976 when it infected people attending an American Legion convention (and other guests including the author’s parents) at a Philadelphia hotel. (4) Nearly three dozen people died, and many more became ill. The outbreak was traced to water vapor containing the bacteria in the exhaust plume of a cooling tower on the roof of the convention hotel. The hotel’s air handling system circulated some of the vapor through the building. 

The link between Legionella and amoeba was first reported by Rowbotham (5) who showed that amoeba could serve as hosts for the Legionella.

Of critical importance for Legionella control is proper design and operation of a biocide feed system that minimizes all forms of microbiological fouling. Another important measure is finding and eliminating, if possible, all dead leg piping. Stagnant water can allow organisms to proliferate. When workers enter cooling systems for regular maintenance work, such as cleaning condenser waterboxes, masks should be a part of their personal protective equipment (PPE).

Macrofouling

Much larger organisms including mussels, clams, and barnacles can cause severe cooling system fouling. Fresh water clams first became a problem in the United States in the late 1970s when the Asiatic clam, Corbicula flominea, entered the country. A problem with these creatures is that they are often the perfect size to fit into steam condenser and heat exchanger tube inlets.

Then in 1986 Dreissena polymorpha, the zebra mussel, and its close relative the quagga mussel were introduced to the Great Lakes in the ballast water discharge of a foreign ship. These mussels are native to the Black and Caspian Sea areas. The mussels attach to surfaces, including each other, with string-like filaments known as byssal threads. Colonies can become massive, with thousands of mussels per square foot.  

Zebra mussels have been a primary focus in recent years following their spread from the Great Lakes through various waterways in the eastern and midwestern United States. Besides spreading naturally through waterways, the organisms can also survive for two to three weeks out of water. Thus, if they attach to a recreational boat in one water body and the boat is transferred to another water body within a relatively short time, the mussels can infiltrate the next source.

Conclusion

As this installment suggests, micro- and macro-biological fouling can occur rapidly in cooling systems, and it can cause severe problems to the point of perhaps partial or total plant shutdown. Critical to prevent such fouling are well-designed, operated, and maintained treatment systems in which the selected chemistry maximizes biocide efficacy. We will explore these topics in Parts 4 and 5 of this series. And, as we shall see, some of the treatment methods are also appropriate for once-through cooling systems.

This discussion represents good engineering practice developed over time. However, it is the responsibility of plant owners, operators and the technical staff to implement reliable programs based on consultation with industry experts. Many additional details go into the design and subsequent use of these technologies than can be outlined in a single article.

References

1. Post, R., Emery, K., Dombroski, G., and M. Fagan, “Effectively Cleaning Cellular Plastic Cooling Tower Fill”; from the conference proceedings of the 33rd Annual Electric Utility Chemistry Workshop, June 11-13, 2013, Champaign, Illinois.
2. Monjoie, M., Russell, N., and G. Mirsky, “Research of Fouling Film Fill”; Cooling Technology Institute, TP93-06, New Orleans, Louisiana, 1993.
3. Post, R., Buecker, B., and S. Shulder, “Power Plant Cooling Water Fundamentals”; pre-workshop seminar to the 37^th Annual Electric Utility Chemistry Workshop, June 6-8, 2017, Champaign, Illinois.
4. Legionnaires’ disease – About the Disease – Genetic and Rare Diseases Information Center (www.nih.gov)
5. T. Rowbotham “Preliminary Report on the Pathogenicity of Legionella pneumophila for Freshwater and Soil Amoebae” J. Clin. Pathol. 1980, 33, 1179-1183.
6. https://www.pall.com/en/medical/water-filtration/legionella-filtration.html

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as Senior Technical Publicist with ChemTreat, Inc. He has over four decades of experience in or supporting the power and industrial water treatment industries, 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 (now Evergy) La Cygne, Kansas station. 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 may be reached at beakertoo@aol.com.

Read Part 1 here.

Part 1 of this series offered an overview of the most prominent cooling water scale/corrosion inhibitor treatment programs since the middle of the last century. Treatment evolved from the very effective but ultimately hazardous acid/chromate chemistry to phosphate/phosphonate/zinc treatment that utilized “controlled” precipitation reactions and mildly basic pH to reduce the corrosion and scaling potential of cooling water. The latter programs can be complicated to control, with sometimes a fine line between corrosion and scaling conditions. The photo below of a two-pass heat exchanger offers a dramatic example.

At the inlet end (the lower tubes of this exchanger), corrosion was evident. At the warmer outlet side (the top half), deposition was troublesome, as is clearly visible. The phosphate/phosphonate program was not particularly effective at mitigating corrosion or scaling depending on location and temperature within the heat exchanger. 

In this installment, we will examine the general chemistry of phosphate replacement technologies that have proven effective in many applications; with less uncertainty than phosphate/phosphonate treatments, and with reduced environmental impact from discharge chemistry.

Corrosion control: Remember the key principle, protect the metal surface

As the reader will recall from Part 1, from a corrosion-control standpoint, phosphate/phosphonate programs largely rely on deposition of reaction products to inhibit anodic and cathodic reactions. A common corrosion cell in aerated water is shown below.

While carbon steel oxygen corrosion is probably the most common mechanism, many other corrosion mechanisms are possible. Space limitations prevent a detailed discussion of most of these mechanisms in this article, but I hope to outline some of the most important in a future Power Engineering article. Continuing with the main topic; reliance on precipitating chemistry to depolarize anodic and cathodic reactions can often be very challenging, where variable conditions can lead to other problems such as the scale formation shown in Figure 1. Accordingly, modern programs have emerged to establish a direct protective film on metal surfaces. The important features of the organic molecule(s) in many formulations are active sites that directly attach to metal surfaces with the hydrophobic organic chain extending outwards.

One compound with which this author is familiar goes by the general chemical name of reactive polyhydroxy starch inhibitor (RPSI), (1) where active oxygen-containing groups on the molecules attach to the metal surface with the organic portion shielding the metal. This chemistry and similar technologies have significantly grown in popularity and use over the last decade or so, with now several thousand applications or more. Results indicate that proper application of the chemistry, which does not require high concentrations, can often lower carbon steel corrosion rates to less than 1 mil per year (mpy, where a mil is 0.001 inches). This is well within the projected lifetime of typical carbon steel components.

Data from Reference 1 also indicates good corrosion protection of 300-series stainless steel metals from chloride pitting and cracking, which brings up a subject that this author has been planning to address. For several years, I was heavily involved in reviewing water treatment design specifications for new combined cycle power plants. In numerous instances, the design engineering firm would specify either 304 or 316 stainless steel for steam surface condenser tubes, apparently without giving any thought to cooling water chemistry and potential problems from impurities. 

A primary case in point is that stainless steels form an oxide layer which protects the base metal, but where chloride in sufficient concentrations will penetrate the oxide layer and initiate pitting. For years, the recommended maximum chloride limits for these steels ranged from 500 ppm for 304 SS to 3,000 ppm for 316L (L stands for low-carbon content) SS at ambient temperature. Research has subsequently shown that these limits were too high, and one noted materials expert suggests 100 and 400 ppm, respectively, for clean tubes. (2) Deposits increase the corrosion potential. Some makeup waters have chloride levels that exceed these guidelines before even being cycled up in a cooling tower. (3) Pitting is an insidious corrosion mechanism, and has been known to cause failure within months and sometimes even weeks of materials that should last for decades. Another element that can cause severe stainless steel corrosion is manganese. We will examine that issue in a future article. 

Two primary takeaways come from this example. First, design engineers for major projects that have water and process fluid systems need to consult with or have on staff chemistry and corrosion experts who can select the correct materials. It is typically much easier to select proper materials in the design phase than to deal with operational issues after installation. Second, and of direct importance to this discussion, is that the film-forming chemistry highlighted above may offer a solution at existing facilities in which material replacement would be cost prohibitive.  

Another benefit of this modern cooling water treatment alternative is environmentally related. Phosphorus is a primary, and often limiting, nutrient for microbiological growth in cooling systems and in receiving bodies of water, including retention ponds for cooling tower blowdown. The following two figures from Reference 1 show a before and after photo of the retention pond at an industrial facility, in which treatment was changed from a polyphosphate/zinc program to a non-phosphorus (non-P) film-forming program.

Results such as these are often an additional driving factor for program change, particularly in locations where environmental regulations limit or perhaps even prohibit phosphorus discharge from point sources. (Agricultural runoff is a different issue that cannot be addressed here.) Furthermore, regulations continue to tighten on discharge of other elements and compounds, which in this case often includes zinc; a common corrosion inhibitor in phosphate/phosphonate programs. 

What about scale control with Non-P Chemistry?

As Part 1 outlined, phosphate/phosphonate programs provide double duty as both corrosion and scale control methods. For the advanced non-P programs now, polymers with active groups serve for scale control. Figure 6 outlines the general structure of and common active groups on the polymers.

These compounds function via a variety of mechanisms to control scale formation, including:

• Sequestration: The polymers bind with scale-forming ions. Those polymers with carboxylate groups (COO^–) work well in sequestering calcium and magnesium.
• Crystal Modification: The polymers alter the crystalline structure of deposits to reduce the adherent tendencies of the crystals, which allows them to be washed away. The acrylate and maleate functional groups are effective on calcium carbonate, but co- or ter-polymers with sulfonate or additional active groups may be needed for other deposits such as calcium phosphate.
• Crystal Dispersion: Suspended particles in water usually have an overall negative charge. Dispersants enhance the negative charge to keep particles, e.g., silt, clay, corrosion products, in suspension.

An often-important factor for deposit control is to enhance the ability of the polymers to penetrate deposits. This is especially true for organics, including oils and greases, as these compounds bind deposits together. Surfactants can assist in breaking down these materials. Nonionic surfactants are similar to detergents by having a hydrophilic (water loving) functional group and a lipophilic (oil loving) chain. As the lipophilic end binds with oils, the hydrophilic end attaches to water molecules to remove the oil. Structural modifications to the lipophilic and hydrophobic active sites allow for specialized properties.

Polymers of variable chain lengths are available, where a thorough analysis of the water constituents is necessary to select chain size and the most efficient active groups. Also, some compounds may cause foaming, and these issues need to be considered during product selection. And, of course, sometimes field adjustments are necessary, as laboratory testing may differ from the actual full-scale application.

Conclusion

Modern methods are available to move recirculating water chemistry control beyond the complicated phosphate/phosphonate programs that held sway for four decades. However, the chemistry cannot be applied blindly or without monitoring, with the expectation that all problems will instantaneously be solved. Cases are well known where corrosion coupons indicate good performance, but locations within the system become heavily fouled or corroded. Temperature effects and other factors may be at work in these locations. Even more importantly, microbiological fouling can completely offset any effects of the scale/corrosion inhibitors. Micro-fouling is often the proverbial “800-pound gorilla in the room” when it comes to cooling water difficulties. In the next several parts of the series, we will review these issues.

This discussion represents good engineering practice developed over time. However, it is the responsibility of plant owners, operators, and the technical staff to implement reliable programs based on consultation with industry experts. Many additional details go into the design and subsequent use of these technologies than can be outlined in a single article.

References

1. Post, R., and Kalakodimi, P., “The Development and Application of Non-Phosphorus Corrosion Inhibitors for Cooling Water Systems”; presented at the World Energy Congress, Atlanta, Georgia, October 2017.
2. E-mail correspondence with Dan Janikowski of Plymouth Tube Company, January 2022.
3. Post, R., and Buecker, B., “Grey Water – A Sustainable Alternative for Cooling Water Makeup”; Proceedings of the 2018 International Water Conference, 79^th Annual Meeting, November 4-8, 2018, Scottsdale, Arizona.

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as Senior Technical Publicist with ChemTreat, Inc. He has over four decades of experience in or supporting the power and industrial water treatment industries, 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 (now Evergy) La Cygne, Kansas station. 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 may be reached at beakertoo@aol.com.

Over the last three decades, combined cycle power plants have replaced many coal units as our country moves to reduce carbon dioxide emissions.

A feature of every combined cycle unit is the heat recovery steam generator, which converts combustion turbine exhaust heat into steam for additional electrical production that adds approximately 20% net efficiency. Load cycling is basically the norm for combined cycle units, which places much thermal, mechanical and water/steam chemistry stress on HRSGs.

This article provides an overview of many important HRSG inspection items during scheduled (and sometimes forced) outages.

HRSG components

While HRSGs come in a number of configurations, the most common design is the triple-pressure drum style, as shown in Figure 1 below.

As is evident from even this basic figure, HRSG water/steam and gas paths can be complex, where regular and thorough inspections of many components are necessary to ensure reliable and safe operation. The following discussion highlights many, but certainly not all, important inspections and inspection techniques. Given the tight spacing of the evaporator tube bundles, aka harps, and other equipment within an HRSG, methods beyond simple visual observation, including non-destructive techniques, are necessary for a thorough evaluation of equipment conditions.

Water/Steam-side

Visual drum inspections should be standard, and can reveal much about the effectiveness of boiler water treatment programs. Large deposits of loose material on the drum floor(s) suggest corrosion in other parts of the system or perhaps contaminant in-leakage from a steam-surface condenser, where the impurities have reacted with boiler water treatment chemicals. Borescope examination of drum riser tubes is also important.

The recommended feedwater treatment program for most HRSGs is all-volatile treatment oxidizing (AVT(O)), which has no oxygen scavengers to help minimize single-phase flow-accelerated corrosion (FAC). If AVT(O) is applied properly, the drums and evaporator tubes should have a solid red color. If black magnetite is visible, the program is not functioning correctly. Additionally, borescope inspection of LP and IP evaporator and all economizer tube elbows can reveal single-phase FAC.

Also important during drum inspections is examination of the steam separators. Broken or missing components can allow moisture transport, with accompanying impurities, to the steam and ultimately the turbine. Even minor contaminant concentrations can cause multiple steam system problems, including corrosion of the blades and rotor in the last stages of the LP turbine. Inspection of the LP upper drum will reveal the presence or absence of two-phase FAC, which, if present, suggests that modifications to the chemical treatment program are needed.

Visual inspection of the water/steam side of other equipment such as superheaters/reheaters, economizers, lower headers, and so forth may be difficult, as these constitute pressure piping and usually do not have readily-removable inspection ports. Borescope inspections from accessible spots can provide valuable data.

Apart from visual inspections, several valuable non-destructive methods are available for additional evaluations. These include ultrasound thickness (UT), liquid penetrant, and wet fluorescent magnetic particle (WFMP) testing. UT testing is a well-recognized method to locate wall thinning from FAC. Liquid penetrant and WFMP are common techniques to check weld integrity. Weld inspections are a critical process, as stress and corrosion can weaken welds to the point of failure.

Gas-side inspections

HRSG components are also, of course, exposed to high-temperatures and stressful conditions on the gas side. Thorough inspections are necessary to identify equipment condition and those areas that may need repair. The following list outlines a number of the most important gas-side inspection items.

• Inlet duct liners: The liners are exposed to turbulent flow that may cause failure. Original equipment is often under-designed, which exacerbates the issue. Liner degradation and failures may also occur from high temperature impingement induced by duct burners.
• Duct burners: During normal operation, the sole heat source for the HRSG is combustion turbine exhaust. However, many HRSGs are equipped with inlet or interstage duct burners to increase steam generation during times of high load. Burner inspection is important to ensure that all are in proper working order. The inability to produce even a few megawatts below maximum load during emergency peak conditions can be quite costly to the plant owner.
• Lead superheater and evaporator tubes: Natural gas is the typical fuel for combustion turbines, and it burns cleanly. However, even the small amount of particulates that enter with combustion air can collect on evaporator tubes, particularly if the tubes have fins to enhance heat transfer. Cleaning all but the outside tubes may be difficult because of the close spacing within and between the harps.
• Expansion joints: Similar to expansion joints in other applications, HRSG expansion joints can degrade over time leading to cracks and spots for flue gas to escape.
• Exhaust duct floor: The flue gas is obviously much cooler at the HRSG outlet. Condensation within the outlet duct can lead to corrosion, particularly of the duct floor. Among other things, this can be a critical safety item.
• Stack dampers: Dampers allow the HRSG to be mostly sealed off from the ambient environment during unit shutdown, as humid and/or cold ambient air ingress can induce corrosion within the HRSG. The dampers also are utilized to reduce heat loss, which allows for faster startups and reduces thermal fatigue in the HRSG. Inspections confirm damper integrity.
• Stack silencers: Many combined cycle units are located in or near residential areas. Accordingly, stack silencers are often required to reduce the noise level to the surrounding neighborhoods. 
• SCR catalyst beds, SCR ammonia grid injection system, and CO catalyst beds: Regular testing and monitoring of NO_x, CO, and ammonia-slip emissions are regulatory requirements. An increase in concentration of any indicates some problem, whether it be aging catalyst, or, in the case of the SCR, a problem with the ammonia injection system. Inspections can be valuable for identifying mechanical issues.

The discussion above outlined many, but certainly not all, recommended inspection points and techniques for HRSGs. Neglected or haphazard unit inspections can lead to equipment failures, and even more importantly, potentially jeopardize employee safety. The tight spacing of HRSG internals makes some inspections very difficult, where special methods may be required to ascertain equipment condition.

Reference

Buecker, B., Shulder, S., and Sieben, A., “Fossil Power Plant Cycle Chemistry”; pre-conference seminar for the 39^th Annual Electric Utility Chemistry Workshop, June 4-6, 2019, Champaign, Illinois. 

About the Author: Alejandro Rodas is a Louisville, Ky-based proposal engineer with Bremco (a member of the SVI Industrial family) with over 12 years’ experience working with HRSGs.

An issue that became readily apparent when researchers began investigating flow-accelerated corrosion (FAC) is that a small amount of chromium in carbon steel will greatly inhibit the corrosion mechanism. The common 1¼ (percent) and 2¼ chrome-alloy carbon steels are highly resistant to FAC. Fabrication of economizer and HRSG evaporator elbows and other FAC-susceptible components with these alloys is a straightforward solution. 

However, the chrome-steel alloys are more expensive than plain carbon steel, and thus this option is often not considered during project design. Also, the frequent load swings that most power units now experience expose more locations to FAC than exist in base-loaded units. Materials cost would be greater if this factor was included in equipment design.

The last 15 years or so have seen a gradual re-emergence of film-forming chemistry to protect steam generator metal surfaces from corrosion, including FAC. The concept goes back decades, but results then and even now have been mixed. 

This section briefly highlights some of the most important pros and cons for adopting film-forming chemistry in steam generators, with the understanding that many details are omitted due to space constraints. Readers are encouraged to download the Reference 1 document for additional information on film-forming amines.

Film-forming chemistry basics

As the name implies, the key function of film-forming products (FFP) is to protect metal surfaces. The general chemical structure of these products is a rather long organic chain with a hydrophilic and hydrophobic end. Most common are amine-based compounds, which we will refer to as AFPs. But also available are non-amine compounds, or NFPs. 

To obtain a better understanding of important FFP action mechanisms, consider the common oxide layers that form on steam generator carbon steel.

Topotactic is the tight layer that initially forms from oxygen reaction with the base metal. The epitactic layer consists of loose iron oxides, usually produced elsewhere in the steam generating network, which precipitate on metal surfaces.

Table 1 compares some of the most important properties of AFPs and NFPs.

Figure 2 outlines the general chemical structure of one AFP.

As the figure depicts, the compound bonds with the topotactic layer and the long, hydrophobic molecular chains extend outward from the oxide surface, providing a shield from the fluid.

Figure 3 outlines the general structure of an NFP.

The active groups in this compound are amides, HN-C=O.

An issue that arises with FFP use is the inclusion of other chemical products in a treatment program. The FFP formulation may contain a surfactant to enhance bonding with the metal surface. Beyond that is the inclusion of ammonia or an alkalizing amine to maintain the moderately basic pH that is recommended for the AVT programs outlined in the previous installments to this series. 

In this author’s opinion, such pH control remains important, because if the filming product did not provide a uniform layer throughout the feedwater network, the ammonia alkalinity would help protect exposed metal surfaces. A question that arises is whether the alkalinity booster should be included in the FFP formulation or be fed separately. The latter arrangement allows more chemical feed flexibility.

With respect to boiler water chemistry, many conventional drum units and the intermediate-pressure and high-pressure circuits of many HRSGs still rely on tri-sodium phosphate or perhaps caustic treatment. The literature suggests that these programs can be continued with FFP treatment. From my perspective, and having directly observed serious boiler tube corrosion caused by impurity in-leakage from steam surface condenser tube failures, I would feel more comfortable continuing the phosphate chemistry. Others might have a different opinion.

FFP positives and negatives

For any well-formulated FFP, “ideally, the product establishes a complete hydrophobic barrier on metal surfaces to provide protection during operation and down times.” (2)

However, not all FFP applications have been successful, and there are still a number of “gray areas” with regard to feed control, accurate chemistry monitoring, and side effects on chemistry and equipment. These include:

• Some vendors closely guard the chemical formula(s) of their product, which makes it difficult to determine the precise chemistry mechanisms within the steam generator.
• Direct measurement of FFP concentration is often problematic. This makes feed control and monitoring difficult. Researchers continue to improve monitoring methods.
• Common is to set an initial dosage per manufacturer’s guidelines and then make adjustments as the film becomes established. Overfeed can result in the formation of “gunk balls” that may cause fouling. Also, feed rates may need adjustment per unit load swings, which in turn may require a somewhat sophisticated control system.
• By their very nature, FFPs may also form a layer on other equipment, including instrument probes and condensate polisher resin for units so equipped. 
• FFPs that carry over into superheaters and reheaters, and particularly additions to the formulations such as surfactants and/or alkalizing amines, will break down to small-chain organic acids that lower condensate pH and increase condensate/feedwater cation conductivity.  Chemistry and corrosion control problems may result.

Corrosion product monitoring is one method to evaluate the efficacy of a program. After a program has been well established, iron and other metal concentrations in the feedwater and boiler water should be at a low parts-per-billion level. However, during program initiation, AFPs in particular will fracture much of the epitactic iron oxide, which then enters the boiler water. This must be understood at the onset of a program. 

If metals concentrations do not stabilize after a sufficient treatment period, investigation is necessary. Visual inspections of boiler and feedwater systems, when possible, can be valuable. Important questions during these inspections include, “Do internal components exhibit hydrophobicity when water droplets are applied? Is more or less sludge visible in boiler drums and headers than in the past?” (2)

FFPs for air-cooled condensers

Air-cooled condensers (ACCs) are becoming increasingly common for combined cycle power plants. Text from Reference 1 sums up the potential advantages of film-forming amine products (FFAP) to protect these units from corrosion.

Unlike water-cooled condensers made of corrosion-resistant alloys like red or yellow metal, stainless steels, or titanium grades, ACC tubes are normally fabricated in carbon steel. They add a vast steel surface area to a water/steam cycle, typically of the order of thousands of square meters, and hence constitute a major potential source of total iron corrosion products. Conditions both in the [steam] transport lines [to the ACC] and at the tube entries of the ACC make them susceptible to FAC, with the tube entries in the upper ducting operating under the most severe two-phase FAC conditions.     

The text goes on to say, “In this case, the dosage of the FFAP into the steam line from the turbine to the condenser can be considered in order to directly provide the FFA to the huge iron surfaces of the ACC.” (1) Regardless of the possible success of a program, typical guidelines recommend a condensate iron filter to remove the usually large amount of iron oxides that could otherwise precipitate in boiler tubes and cause overheating and under-deposit corrosion difficulties.

This final part to this FAC series outlines additional methods for potentially mitigating FAC (and other corrosion) in steam generators. The text only provides a brief overview of these technologies. 

For anyone considering FFP chemistry, due diligence is of key importance. Any test or full-scale application of any product(s) should be done in full consort with a reputable vendor, and which includes the development and use of detailed test, monitoring, and inspection protocols. Not to be overlooked is regulatory approval of any products that might be discharged from the plant to the environment.

References

1. International Association for the Properties of Water and Steam, IAPWS TGD 8-16, Technical Guidance Document: Application of Film Forming Amines in Fossil and Combined Cycle Plants.
2. Buecker, B., and Shulder, S., “Combined Cycle and Co-Generation Water/Steam Chemistry Control”; pre-workshop seminar for the 40^th Annual Electric Utility Chemistry Workshop, June 6-8, 2022, Champaign, Illinois.

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing.  Most recently he served as Senior Technical Publicist with ChemTreat, Inc.  He has over four decades of experience in or supporting the power and industrial water treatment industries, 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 (now Evergy) La Cygne, Kansas station.  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 may be reached at beakertoo@aol.com.

In the first two parts of this series, we examined the phenomenon of single-phase FAC, which continues to afflict many utility steam generators around the world. A primary culprit in many of these cases is the continued reliance on AVT(R) feedwater chemistry, which, unless copper alloys are present in the feedwater system, is not recommended. 

However, moving away from AVT(R) does not guarantee elimination of FAC, either single-phase or two-phase. Regarding the single-phase FAC, if the dissolved oxygen concentration drops out of the 5-30 ppb range outlined in Part 2, reducing conditions may arise that allow corrosion. Often, this oxygen deficiency appears as patches of gray-black magnetite mixed in with the red color that should otherwise be uniform with proper AVT(O) conditions. As suggested in Part 2, correction may require supplemental oxygen feed to keep the D.O. within the recommended range.

Two-Phase FAC

Besides dissolved oxygen concentration, we have seen that pH has a large impact on FAC potential. Locations exist in both conventional units and HRSGs in which the design and operation will alter either or both of these variables, and initiate two-phase FAC. The most notable spots within conventional units include deaerators and feedwater heater drains. 

Consider a deaerator compartment where the rising injection steam scrubs D.O. from the condensate, producing an agitated vapor with small water droplets in the deaerator vessel. This results in two-phase FAC, where the combination of steam and water exist. 

I have inspected deaerators in which baffle plates exhibited severe wear from flowing, oxygen-deficient water droplets. The figures below illustrate the much different appearance of single-phase and two-phase FAC.

Several noticeable contrasts and comparisons are apparent from these two photos. Single-phase FAC typically exhibits a rougher appearance than the two-phase variety. The metal in two-phase FAC often appears to be “sanded” (a concept that we will return to in Part 4.) 

Notice in Figure 2 the presence of both gray magnetite and red hematite. With complete AVT(O), all surfaces should be red. It is the magnetite that is suffering from two-phase FAC.

At this point, think back to Part 2 of this series that discussed how, in the most common type of HRSG – the feed-forward, low-pressure (FFLP) design – dissolved oxygen escapes with steam in the low-pressure evaporator. Two-phase FAC can therefore become quite pronounced in the upper section of the LP drum of these units. 

So, the question naturally arises: “How can such locations be protected from two-phase FAC?”

Per the Sturla diagram shown in Part 1, a key approach is maintaining an elevated pH of 9.6-10.0 in the feedwater. But this brings up another twist to the puzzle. 

For decades, organizations such as EPRI emphasized that only ammonia should be employed as the feedwater pH-conditioning agent. However, in the low-pressure drum of FFLP units, much of the ammonia will partition with the steam, leaving behind water droplets with a lower pH and no oxygen. An ammonia alternative is an alkalizing amine such as ethanolamine (ETA), cyclohexylamine, or others that are less volatile than ammonia. 

Unfortunately, whatever portion of the amine that carries over with steam will break down in the superheater/reheater to small-chain organic acids and carbon dioxide. These acidic compounds may lower the pH of condensed steam to below 9, and the pH is not re-elevated until the condensate reaches the chemical injection point. 

Furthermore, the organic acids raise the cation conductivity (now commonly known as conductivity after cation exchange (CACE)) of the steam and condensate. This issue has caused problems for the commissioning of new units in which the steam turbine manufacturers insist on CACE values <0.2 µS/cm. 

In this author’s opinion, this surrogate measurement for chloride and sulfate is outdated, as these constituents can be measured directly, now with an on-line instrument that requires limited maintenance. (1)

Apart from the issues above, debate raged for years that the organic acids could potentially cause turbine blade and rotor damage.  I am not sure that this debate has totally disappeared. However, research suggests that an ammonia-alkalizing amine blend (a common recommendation is 90% ammonia – 10% ETA) may be a good compromise. The ETA can help mitigate two-phase FAC in the HRSG LP drum by keeping the pH elevated in the water droplets, while minimizing formation of organic acids in the steam.

The importance of iron monitoring

As reported previously in Power Engineering, iron monitoring should be an integral part of a water/steam sampling program, regardless of feedwater chemistry treatment. (2) 

For decades, EPRI-established guidelines have suggested that with proper chemistry, the total iron concentration in boiler feedwater can be maintained below 2 ppb, even for those units on AVT(R).  But if FAC is underway, the iron concentration is typically well above that value.  Thus, regular iron analyses are critical for establishing and maintaining the correct chemistry to control FAC. 

A complicating factor, however, is that typically 90% or greater of the steel corrosion products exist as particulate iron, with only a small fraction as dissolved iron.  So, any analyses must account for the particulate iron. 

Two common techniques are on-line particle counting, and corrosion product sampling (CPS).  The latter 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 so, and then have the filters and ion exchange resin analyzed for results. For conventional units that still have copper-alloy feedwater heater tubes, CPS is a technique to monitor copper corrosion as well.

While these technologies have been successful, other methods have emerged that offer good results at reasonable cost.  Simple colorimetric lab methods have traditionally been used to monitor dissolved iron contamination, but additional procedures are necessary to measure particulate iron.  A combination digestion-reduction-detection bench-top method is particularly useful for simplifying analysis and minimizing contamination.

Procedures have been developed to provide complete dissolution of particulate magnetite or hematite. The reported detection limit is 1 ppb.

A combination of a simple colorimetric total iron laboratory analysis with a sensitive laser nephelometric analyzer can also provide a method for quantitative, real-time corrosion monitoring. When properly calibrated, the nephelometric readings can be correlated to total iron concentration values. Magnetite and hematite produce a different nephelometric response to visible light. Black magnetite absorbs more and reflects less light than red hematite. Dissolved iron does not produce any nephelometric response. 

Corrosion products range in size from sub-micron to 10 µm in diameter, with an average diameter of 1 µm [3]. This size range poses a challenge for particle monitoring because nephelometers respond differently to different particle sizes. These variables make it impossible to create a universal nephelometric calibration for quantification of corrosion products. A nephelometric calibration which is appropriate for one location will not be accurate for a different location where corrosion characteristics may be different. 

Therefore, quantification of total iron via nephelometry must be accomplished through site-specific calibration. Variability in water chemistry, phase, and local piping configurations contribute to variable corrosion characteristics. Site-specific calibration ensures that nephelometric response is correlated to the specific corrosion characteristics present at each installation.

Conclusion

This installment briefly examined two-phase FAC in HRSGs and techniques for its control. Two-phase FAC may also occur in other locations including steam turbine exhaust and in air-cooled condensers. We will examine some of these issues in Part 4. This installment also emphasized the importance of iron monitoring as a tool to ensure that chemical treatment programs are performing properly to minimize FAC.

References

1. B. Buecker, “Monitoring of Water and Steam Chemistry for Steam Generators”; Chemical Engineering, September 2019.
2. Buecker, B., Kuruc, K., and Johnson, L., “The Integral Benefits of Iron Monitoring for Steam Generation Chemistry Control”; Power Engineering, January 2019.
3. Kuruc, K., Johnson, L.,  Proc., Electric Utility Chemistry Workshop 2015, 2015 (Champaign, IL, USA).  University of Illinois, Urbana-Champaign, IL, USA.

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing.  Most recently he served as Senior Technical Publicist with ChemTreat, Inc.  He has over four decades of experience in or supporting the power and industrial water treatment industries, 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 (now Evergy) La Cygne, Kansas station.  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 may be reached at beakertoo@aol.com.